1APEC E N E RG Y O VE R VI E W 2017

Prepared by
Asia Pacific Energy Research Centre (APERC)
The Institute of Energy Economics, Japan
Inui Bldg.-Kachidoki 11F, 1-13-1 Kachidoki, Chuo-ku, Tokyo 104-0054, JAPAN
Tel: +81 (3) 5144-8551 Fax: +81 (3) 5144-8555
E-mail: apercadmin@aperc.ieej.or.jp
APERC Website: http://www.aperc.ieej.or.jp
For the Asia-Pacific Economic Cooperation (APEC) Secretariat
35 Heng Mui Keng Terrace Singapore 119616
Tel: (65) 6775 6012 Fax: (65) 6775 6013
E-mail: info@mail.apecsec.org.sg
Website: http://www.apecsec.org.sg
 2017 APEC Secretariat
APEC# 217-RE-01.15

APEC E N E RG Y O VE R VI E W 2017

F O RE W O RDFOREWORDThe APEC Energy Overview is an annual publication that seeks to outline the energy
situation in each of the 21 APEC economies.
Based on the latest data compiled by the Expert Group on Energy Data and Analysis(EGEDA), this publication provides updated information on APEC’s energy supply anddemand trends. It also contains information on notable energy developments in the region,
as well as APEC’s progress towards its twin targets of reducing energy intensity by at least
45% by 2035 (from 2005 levels) and doubling the share of renewables in its energy mix
from 2010 to 2030.
It is encouraging to note that various efforts and measures have been put in place by
economies to contribute towards the APEC targets. These include increased investment
in energy efficiency; increased deployment of renewable resources; promotion of goodenergy management practices and the conduct of several energy-efficiency awarenessraising campaigns.
We hope that this report will help to deepen the understanding of energy issues among
APEC economies, promote the use of EGEDA data and provide useful insights to policy
makers in the region.

Takato OJIMI
President
Asia Pacific Energy Research Centre(APERC)James Michael Kendell
Chair
Expert Group on Energy Data
and Analysis (EGEDA)

May 2018

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APEC E N E RG Y O VE R VI E W 2017

E X E C U T I VE S U M MA R Y

EXECUTIVE SUMMARYAPEC population―which had remained constant for the last five years―grew 0.7% in 2015 toreach 2.85 billion. Its GDP, on the other hand, continued to increase significantly, reaching USD
59 014 billion (PPP constant 2011 USD) in 2015, up by 3.7% compared with the 2014 levels (USD
56 908 PPP constant 2011 USD). Total primary energy supply in 2015 posted a negative growth (0.3%) after continuously slowing since 2012 to reach 7 885 million tonnes of oil equivalent (Mtoe)
compared with the 2014 supply level of 7 912 Mtoe. This decline can be attributed to the slide incoal supply posted at -2.5% in 2015. Total final energy consumption in APEC reached 4 728 Mtoe
in 2015, an almost negligible increase from the 2014 levels of 4 728 Mtoe. If consumption for nonenergy use is added, total final consumption was 5 250 Mtoe.
The APEC Overview has become the platform to monitor APEC goals―energy intensity reduction
by 45% by 2035 (against the 2005 level) and doubling renewable energy share by 2030 with 2010as base year. As agreed during the 49th EGEEC (Expert Group on Energy Efficiency andConservation) meeting and subsequently at 53rd EWG (Energy Working Group) Meeting, APERC
is now monitoring energy intensity improvement in final energy consumption excluding nonenergy. Also in coordination with EGEDA, rough estimation of the annual change of the share ofmodern renewables to final energy consumption was presented in this summary.
Energy intensity in the APEC region has been improving continuously. In 2015, the final energy
intensity was reduced 3.5% to 80 tonnes of oil equivalent (toe) per million USD (PPP constant2011 USD) as compared with 2014 final energy intensity level of 83 toe/million USD (PPP
constant 2011 USD). With 2005 as base year, the final energy intensity has improved significantly
by 17.9%. If the current trend continues, final energy consumption intensity (ex. non-energy)
reduction would fall just short of the APEC goal, reaching 44.6% in 2035―the APEC goal would
be reached the following year.
APERC in cooperation with EGEDA, developed the definition of modern biomass to be used inmonitoring the renewable doubling goal. Biomass used in the residential and commercial sectors
is assumed to be traditional biomass because solid biofuels are typically used in these sectors forheating (residential) and cooking (residential and commercial), with inefficient technologies that
often have adverse effects on human health. Traditional biomass will not be part of the renewables
goal. This definition is applied to all APEC member economies, including those that are membersof the Organisation for Economic Cooperation and Development (OECD). All other renewables(hydro, geothermal and so on) including biogas and wood pellets are considered modern
renewables (although data on wood pellets are limited) and their share in total final energy
consumption will be monitored for the renewables doubling goal.
In 2015, consumption of modern renewables in APEC grew 1.8% to reach 327 Mtoe comparedwith 2014 (321 Mtoe). Its share of total final energy consumption in 2015 was 6.9%, which is 1.7%
more than the 2014 levels. In 2010, the share of modern renewables to total final energy
consumption was 5.8% (253 Mtoe). Since then it has surged at a compounded annual growth rateof 3.5% through 2015. Assuming continuation of a straight line trend from 2010 to 2015, it wasestimated that the share of modern renewables to the total final energy consumption will reach
10.2% by 2030. If the current annual growth rate continues, the share of renewables in total final
consumption will likely fall short of APEC’s renewables doubling goal by 2030 compared with
2010.

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APEC E N E RG Y O VE R VI E W 2017

AC K N OW L E D G E M E N T S

ACKNOWLEDGEMENTS

We would like to thank APEC member economies for the timely data information provided toensure the accuracy and timeliness of this report. We would also like to thank members of the
APEC Energy Working Group (EWG), APEC Expert Group on Energy Data and Analysis(EGEDA), and numerous government officials, for their helpful information and comments.
The APEC Energy Overview 2017 could not have been accomplished without the contributions ofmany individuals and organisations. We would like to thank all those whose efforts made thispublication possible, in particular those named below.
PROJECT MANAGER
Elvira Torres Gelindon
PROJECT COORDINATOR
Lay Hui Teo
MAIN CONTRIBUTORS
Data Collection and Compilation: Expert Group on Energy Data Analysis (EGEDA) throughits Coordination Agency, the Energy Statistics & Training Office (ESTO), Asia Pacific Energy
Research Centre, The Institute of Energy Economics, Japan.
Economy Chapters: Thomas Willcock (Australia), Atikah Ismail (Brunei Darussalam), Kirsten
Smith (Canada), Juan Ignacio Alarcon (Chile), Yilin Wang (China), Cho Yee Ip (Hong Kong,
China), Gigih Udi Atmo (Indonesia), Takashi Otsuki (Japan), Choong Jong Oh (Korea),
Muhamad Izham Abd. Shukor (Malaysia), Diego Rivera Rivota (Mexico and Peru), Martin
Brown-Santirso (New Zealand), Elvira Torres Gelindon (Papua New Guinea and thePhilippines), Alexey Kabalinskiy (Russia), Lay Hui Teo (Singapore), Fang Chia Lee (Chinese
Taipei), Ruengsak Thitiratsakul (Thailand), James Michael Kendell (United States), Dan Linh
Nguyen (Viet Nam).
EDITORS
Crimson Interactive Pvt Ltd (ENAGO) and Lay Hui Teo
ADMINISTRATIVE SUPPORT
Hideyuki Maekawa, Yoshihiro Hatano, Tomoyo Kawamura and Hisami Obayashiv

APEC E N E RG Y O VE R VI E W 2017

C ON T E N T S

CONTENTS
Foreword ........................................................................................................................................................................... iii
Executive Summary............................................................................................................................................................ iv
Acknowledgements ............................................................................................................................................................... vContents ............................................................................................................................................................................. vi
Abbreviations and symbols ................................................................................................................................................ vii
Acronyms ......................................................................................................................................................................... viii
Currency Codes ................................................................................................................................................................... xAustralia ............................................................................................................................................................................ 1
Brunei Darussalam ........................................................................................................................................................ 17
Canada............................................................................................................................................................................. 28
Chile................................................................................................................................................................................. 52
China ............................................................................................................................................................................... 71
Hong Kong, China ....................................................................................................................................................... 87
Indonesia ...................................................................................................................................................................... 100
Japan .............................................................................................................................................................................. 124
Republic of Korea ....................................................................................................................................................... 138
Malaysia......................................................................................................................................................................... 148
Mexico........................................................................................................................................................................... 167
New Zealand ................................................................................................................................................................ 181
Papua New Guinea ..................................................................................................................................................... 193
Peru................................................................................................................................................................................ 208
The Philippines ............................................................................................................................................................ 220
Russia ............................................................................................................................................................................ 234
Singapore ...................................................................................................................................................................... 250
Chinese Taipei ............................................................................................................................................................. 270
Thailand ........................................................................................................................................................................ 281
United States ................................................................................................................................................................ 293
Viet Nam ...................................................................................................................................................................... 313

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APEC E N E RG Y O VE R VI E W 2017

AB B RE VI AT I O N S AN D S Y M B O L S

ABBREVIATIONS AND SYMBOLS
Abbreviation

Term

B/D

barrels per day

Bcfbillion cubic feetbcm

billion cubic metres

Btu

British thermal units

GW

gigawatt

GWh

gigawatt-hourkLkilolitrekm

kilometre

km/L

kilometres per litre

ktoekilotonne of oil equivalentkVkilovoltkWkilowattkWhkilowatt-hour

Mbbl/D

thousand barrels per day

MLmillion litres (megalitre)

Mloe

Million litres of oil equivalent

MMbbl

million barrels

MMbbl/D

million barrels per day

MMBFOE

million barrels of fuel oil equivalent

MMBtu

million British thermal units

MMcf/D

million cubic feet per day

MMscf/D

million standard cubic feet per day

mpg

miles per gallon

Mt

million tonnes

Mtce

million tonnes of coal equivalentMtoe

million tonnes of oil equivalentMWmegawatt

PJ

petajoules

Tbbl/D

trillion barrels per dayvii

APEC E N E RG Y O VE R VI E W 2017

AC R ON Y MS

tce

tonnes of coal equivalent

Tcf

trillion cubic feettoetonnes of oil equivalenttUtonnes of uranium metalTWhterawatt-hours

W

watt

ACRONYMS
APEC

Asia–Pacific Economic Cooperation

APERC

Asia Pacific Energy Research Centre

APP

Asia–Pacific Partnership on Clean Development and Climate

ASEAN

Association of Southeast Asian Nations

CBM

coal-bed methane

CCS

carbon capture and storage

CCT

clean coal technology

CDM

clean development mechanism

CFL

compact fluorescent lamp

CMEcoconut methyl ester

COP 1515th Conference of the Parties to the United Nations Framework Convention on Climate
ChangeCSM

coal-seam methane

DUHF

depleted uranium hexafluoride

EAS

East Asia Summit

EGEDA

Expert Group on Energy Data and Analysis

ESTO

Energy Statistics and Training OfficeEEZ

exclusive economic zone

FEC

final energy consumptionGDPgross domestic product

GHG

greenhouse gas

HEU

highly enriched uranium

IAEA

International Atomic Energy Agency

IEA

International Energy Agency

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APEC E N E RG Y O VE R VI E W 2017

AC R ON Y MSIEEJThe Institute of Energy Economics, Japan

IPP

independent power producer

JOA

joint operating agreement

JOB

joint operating body

LCD

liquid crystal displayLEDlight-emitting diodeLEU

low-enriched uranium

LNG

liquefied natural gas

LPG

liquefied petroleum gas

MDKB

measured depth below kelly

MOPS

Mean of Platts Singapore

NGL

natural gas liquidsNGO

non-governmental organisation

OECD

Organisation for Economic Co-operation and Development

OPEC

Organization of the Petroleum Exporting Countries

PES

primary energy supply

PPP

purchasing power parity

PSA

production sharing agreement

PSC

production sharing contract

PVphotovoltaicRE

renewable energy

TFEC

total final energy consumption

TPES

total primary energy supply

UNDP

United Nations Development Programme

UNFCCC

United Nations Framework Convention on Climate Change

US

United States

VAT

value added tax

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APEC E N E RG Y O VE R VI E W 2017

C U RR E N C Y C OD E S

CURRENCY CODES
CodeCurrency

Economy

AUD

Australian dollar

Australia

BND

Brunei dollar

Brunei Darussalam

CAD

Canadian dollar

Canada

CLP

Chilean peso

Chile

CNY

yuan renminbi

China

TWD

New Taiwan dollar

Chinese Taipei

HKD

Hong Kong dollar

Hong Kong, China

IDR

rupiahIndonesia

JPY

yen

Japan

KRW

won

Korea

MYR

Malaysian ringgit

Malaysia

MXN

Mexican peso

MexicoNZDNew Zealand dollar

New Zealand

PGK

kina

Papua New Guinea

PEN

nuevo sol

Peru

PHP

Philippine peso

Philippines

RUB

Russian ruble

Russia

SGD

Singapore dollar

Singapore

THB

baht

ThailandUSD

US dollar

United States

VND

dong

Viet NamxAPEC ENERGY OVERVIEW 2017

AUSTRALIA

AU S T R A L I A
I N T ROD U C T I ON

Australia is the sixth-largest economy in the world in terms of land area, covering approximately 7.7 million square
kilometres (km2). It lies in the Southern Hemisphere between the Indian and Pacific oceans and comprises six states
and two territories. The population of approximately 24 million mostly lives in major cities or regional centres along
the eastern and south-eastern seaboards. The economy has maintained robust economic growth, with an average annual
growth rate (AAGR) of 3.1% from 1990 to 2015 (EGEDA, 2017). In 2015, gross domestic product (GDP reached
USD 987 billion (2010 USD purchasing power parity [PPP]), a 2.4% increase from 2014 (EGEDA, 2017). Australia is
the only developed economy in APEC to have recorded no annual recessions over the last 25 years (Austrade, 2018).
Australia has abundant, high-quality energy resources that are likely to last for many decades at the current rates
of production. Energy production increased at an average annual rate of 3.3% from 2000 to 2015 and 4.3% from 2014
to 2015 (reaching 381 327 kilotonne oil equivalent [ktoe]) supported by growth in coal and gas production (EGEDA,
2017). Australia produces energy for both domestic consumption and export; however, it is becoming increasingly
export-oriented. Net energy exports grew by 6% and constituted 65% of domestic energy production in 2015 (EGEDA,
2017).
In 2015–16, coal constituted 74% of Australia’s primary energy production in energy content terms, followed bygas (20%), oil (4%) and renewables (2%) (Environment, 2017a). Coal was even more dominant in the energy export
mix, constituting 81% of the total, followed by gas (15%) and oil (4%). The Australian energy industry constituted 5%(AUD 87.5 billion) of the economy in 2016–17 (ABS, 2017) and, along with other bulk resource commodities, 55% ofexports (OCE, 2017).
Australia constitutes approximately 9% of the world’s black coal production and is the fourth-largest producer
after China, India and the United States (OCE, 2017). Australian coking and steaming coals are high in energy content
and relatively low in sulphur, ash and other contaminants. Coal is Australia’s second-largest commodity export, earning
AUD 54.3 billion in 2016–17 followed by LNG (AUD 22.3 billion) and crude oil (AUD 5.5 billion) (OCE, 2017).
Australia constitutes approximately 2.4% of the world’s energy production and is the world’s largest exporter ofmetallurgical coal, the second-largest exporter of thermal coal and a major exporter of raw uranium and LNG (OCE,2017). Given Australia’s large energy resources and geographical proximity to burgeoning markets in the Asia-Pacificregion, it is capable of meeting a significant proportion of the world’s growing energy demand as well as its own
domestic needs for years to come.
Table 1: Key data and economic profile, 2015
Key data a

Energy reserves b

Area (million km2)

7.7

Oil (billion barrels)

Population (million)

24

Gas (billion cubic metres)

GDP (2010 USD billion PPP)

987

Coal (million tonnes)

GDP (2010 USD PPP per capita)

41 509Uranium (kilotonnes U308)

5.4
3 228
130 442
1 287

Notes: Oil reserves comprise crude, condensate and LPG. Coal reserves are defined as recoverable economically demonstrated
resources of black and brown coal. Uranium reserves are considered to be reasonably assured resources at USD 130/kg U.
Sources: a EGEDA (2017); b GA (2018).

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APEC ENERGY OVERVIEW 2017

AUSTRALIAE N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

In 2015, Australia’s total energy production was 381 327 ktoe and total primary energy supply (TPES, the energy thatis used in the economy) was 125 307 ktoe (EGEDA, 2017). Coal narrowly remains the primary source of domesticenergy supply in Australia at 34%, followed by oil (33%), gas (26%) and renewables and others (6%).
Coal’s primary role is in the transformation sector, which constitutes 92% of use (Environment, 2017a), almost
entirely at coal-fired power stations and coke ovens. Significant black coal basins in New South Wales and Queensland
and Victoria’s enormous brown coal resources have historically provided stable and affordable energy. However, coal’sshare of TPES has been decreasing over the past decade, from 45% in 2005, due to decreased use in the electricity
generation sector (which has seen flat consumption and an increased share of gas and renewables) and closures at ironand steel works.
Gas has become increasingly important to the Australian economy as a source of export income and as acontributor to domestic energy needs. Almost all of Australia’s conventional gas comes from three basins: the offshore
Carnarvon Basin in Western Australia, the offshore Gippsland Basin in Victoria and the onshore Cooper–Eromanga
Basin, which straddles the South Australian and Queensland borders (GA, 2018). Unconventional production, in theform of coal seam gas (CSG), occurs mainly in Queensland and has grown rapidly in recent years. Gas production in
2015–16 of 88 billion cubic metres was a 28% increase on the previous year as Queensland CSG expanded to support
the start of liquefied natural gas (LNG) exports from three new projects in Gladstone (OCE, 2017). Several other LNG
projects will be completed in coming years as gas production continues to grow strongly until 2020.
Australia is a net importer of oil products but a net exporter of liquefied petroleum gas (LPG) (Environment,2017a). Primary energy supplies of crude and refined products are roughly equal. This is because approximately half ofAustralia’s liquid fuel consumption comes from direct imports (mostly from other APEC economies) and the rest fromdomestic refineries. Supply of crude oil and LPG production declined by 4% in 2015–16 relative to 2014–15, largely
due to maturing oilfields, but will be bolstered in coming years by increasing condensate production associated with
offshore gas fields being developed for LNG (Environment, 2017a).
Renewable energy primary energy supply has grown by 2.4% a year over the past decade (to reach 8 197 ktoe in2015) due to significant investments by the electricity sector in utility-scale wind and solar, residential-scale solar
photovoltaic (PV) and hot water (EGEDA, 2017). This growth has been somewhat offset by the decreasing use of
biomass in the residential sector and lower than average hydro generation in recent years due to drought.
In 2015, 252 360 gigawatt-hours (GWh) of electricity were generated, mostly from coal-powered thermal sources(EGEDA, 2017). Given its abundance, coal is likely to remain the most commonly used fuel for electricity generation.
However, its share has declined over the past decade, a trend that will continue as a large number of committed andexisting wind and solar energy projects will constitute an increasing proportion of total electricity generation. Despite
this, the share of renewable energy in the electricity generation mix dropped to 14% in 2014–15 from 15% in theprevious year, as lower rainfall decreased hydro generation, particularly in Tasmania (EGEDA, 2017).
FINAL ENERGY CONSUMPTION

Australia’s total final consumption rose slightly to 81 292 ktoe in 2015, following two flat years (EGEDA, 2017). The
transport sector is the largest end-use sector, constituting 40% of Australia’s total final consumption, followed byindustry (30%), others (25%), which includes the commercial, residential and agriculture sectors and non-energy (5%)(EGEDA, 2017). By fuel type, oil constituted 51% of final energy consumption in 2015, followed by electricity (24%),gas (16%), renewables (6%) and coal (3%) (EGEDA, 2017). Oil, electricity and gas consumption have all been growing
in recent years, while coal is in structural decline as an end-use fuel type. Direct-use renewable energy consumption has
been relatively stagnant since 2010, as an increasing uptake of solar hot water offsets falling biomass use in the residential
sector. The share of electricity generated by renewables, however, has grown at 10% a year over that period due to large
investments in wind and solar capacity.

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AUSTRALIA

Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

381 327

Industry sector

24 001

Net imports and others–249 562

Transport sector

32 515

Thermal

217 871

Total primary energy supply

125 307

Other sectors

20 707Hydro

13 445

Coal

42 909Non-energy

4 069

Nuclear0

Oil

41 888

Final energy consumption*

77 222Others21 044Gas

32 217

Coal

2 330

Renewables

8 197

Oil

39 30896

Gas

12 705

Renewables

4 611

Electricity and others

18 268OthersPower generation (GWh)
Total power generation

252 360

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel types do not include non-energy uses. This is different fromthe total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in power plants is
assumed to comprise renewables.
ENERGY INTENSITY ANALYSIS

Australia is contributing to APEC’s aspirational goal of a 45% energy intensity reduction by 2035 from the 2005 level.
Australia’s energy intensity has been declining since at least 1990 (EGEDA, 2017). In 2015, primary energy intensity
declined by 2.3% while final energy intensity declined by 1.9% (EGEDA, 2017). Australia’s energy intensity
improvements are mainly due to structural shifts in the economy, away from energy-intensive industries and towards
commercial sectors (such as financial services, education and tourism), and efficiency improvements driven by advancesin technology (particularly in the transport and building sectors) (OCE, 2015).
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

130

127

–2.3

Total final consumption

84

82

–1.9

Final energy consumption excl. non-energy

79

78

–0.7

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

Modern renewable consumption increased by 1.6% from 2014 to 2015. This was mainly due to increased solar hot
water in the residential sector and increased solar PV and wind energy in the electricity generation sector. The share of
final energy consumption was almost unchanged, however, as the consumption of non-renewables grew at 1.8%.
Traditional biomass, which shrunk by 3.7% in 2015, has been in structural decline in Australia for numerous years as
gas and electricity replace wood-fired heating.

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APEC ENERGY OVERVIEW 2017

AUSTRALIA

Table 4: Renewable energy share analysis, 2014 vs 2015
2014
Final energy consumption (ktoe)

Change (%)

20152014 vs 2015

75 90577 222

1.7

Non-renewables (Fossils and others)

68 86470 133

1.8

Traditional biomass*

1 243

1 197

–3.7

Modern renewables*

5 798

5 892

1.6

Share of modern renewables to final energy
consumption (%)

7.6

7.6

–0.11

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are typicallyused in these sectors for heating (residential) and cooking (residential and commercial), with inefficient technologies that often
have adverse effects on human health. This definition is applied to all APEC member economies, including those that are membersof the Organisation for Economic Cooperation and Development (OECD) and those that are not (Non-OECD). All otherrenewables (hydro, geothermal and so on) including biogas and wood pellets are considered modern renewables, although data onwood pellets are limited
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

Australia’s system of government has three tiers: federal, state and territory and local. Federal government andstate/territory governments own Australian energy resources, rather than private individuals. None of the tiers ofgovernment engages in commercial exploration or development. The Australian Federal Government has title andpower over energy resources located outside the first three nautical miles of the territorial sea (‘offshore’). The state
governments and the Northern Territory have jurisdiction over resources on their lands or inside the first three nautical
miles of the territorial sea (‘onshore’).
Each state government oversees the approval process for oil and gas exploration for their jurisdiction. However,the Australian Government, in the form of the Australian Department of the Environment and Energy, considers
aspects of ‘national environmental significance’ in accordance with the Environment Protection and Biodiversity
Conservation Act 1999. In this process, each state/territory assesses applications from organisations to explore in its
area before declining or granting access. Similarly, each state/territory assesses safety requirements and environmental
regulations for the coal industry in its respective jurisdiction.
At the federal level, the Department of the Environment and Energy oversees energy matters. This includes
energy security, international engagement, energy efficiency programmes and energy markets. The Department ofIndustry, Innovation and Science oversees resources issues (including some related to onshore gas). All six states andboth territories have energy- or mining-related departments (or divisions) responsible for similar matters at the state or
territory level.
The COAG (Council of Australian Governments) Energy Council, a ministerial forum comprising theCommonwealth, state, territory and New Zealand governments, handles much of the responsibility for advancing
national energy market reform. Such action includes developing and implementing an integrated and coherent energy
and mineral resources policy. The COAG Energy Council is responsible for the regulations of the former Standing
Council on Energy Reform (SCER), the Ministerial Council on Energy (MCE) and the former Ministerial Council on
Mineral and Petroleum Resources (COAG, 2018a). The Australian Minister for the Environment and Energy chairs theEnergy Council.
The Energy Council’s work covers the following broad themes:

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APEC ENERGY OVERVIEW 2017

AUSTRALIA

Overarching responsibility of and policy leadership for Australian gas and electricity markets;The promotion of energy efficiency and energy productivity in Australia;

Australian electricity, gas and petroleum product energy security;

Cooperation between Commonwealth, state and territory governments; and

Facilitation of the economic and competitive development of Australia’s mineral and energy resources.

ENERGY SECURITY

Australia’s energy security policy does not equate to energy independence or self-sufficiency in a particular energy
source. Instead, energy security is enhanced by diverse commercially driven fuel options and supply and delivery sources,
including the importation of liquid fuels from multiple sources.
The Australian Government assesses Australia’s energy security through National Energy Security Assessments(NESAs) that consider the effectiveness and anticipated resilience of Australia’s electricity, natural gas and liquid fuelmarkets and changes in energy security drivers.
The Australian Government broadly defines energy security as the adequate, reliable and competitive supply of energy
to support the functioning of the economy and social development. Adequate is defined as the provision of sufficientenergy to support economic and social activity; reliable is defined as the provision of energy with minimal disruptions to
supply; and competitive is defined as the provision of energy at an affordable price.
In 2009, the Australian Government released the inaugural NESA, which found that Australia’s energy sector was
adequately meeting the economy’s economic and social needs. The second assessment in 2011 found that Australia’s
energy security situation continued to be robust. Furthermore, Australia’s overall energy security should remainadequate and reliable because of the level of new investment going forward and the price of energy (Environment,
2018a).
Since March 2012, Australia has been non-compliant with the International Energy Agency’s (IEA’s) 90-day oilstockholding obligation, a key requirement of the International Energy Programme Treaty to which Australia is asignatory. The Australian Government presented a plan to return to compliance with the IEA in mid-2016 that
introduces a mandatory reporting of Australian petroleum statistics from January 2018, a return to full compliance with
the IEA stockholding obligation by 2026, the purchase of 400 ktoe of oil tickets and the establishment of an Energy
Security Office (Environment, 2018b).
Australia is an active participant in numerous other international energy security forums, including the APEC
Energy Working Group and Energy Security Initiative fora, and it has bilateral engagement on energy security issues
with numerous other economies, including Japan, China and Korea (Environment, 2018c).
UPSTREAM ENERGY DEVELOPMENT

The following basic principles guide the Australian Government’s approach to developing the economy’s energy
resources:

The efficient commercial development of energy resources should be promoted to provide the highest value
return for the community;Energy resource development should be safe, sustainable and consistent with all relevant environmental andhealth and safety standards and obligations;

The development of Australia’s energy resources should contribute to its ongoing domestic energy security;

The development of Australia’s energy resources should enhance its international competitiveness; andThe energy resource development framework should appropriately and effectively interface with other relevantmarkets or regulatory frameworks to support efficient investment in upstream development and downstream
supply capacity.

The Australian Government does not undertake or finance energy resource exploration or development. In theoffshore petroleum sector, the Australian Government relies on an annual acreage release of vacant offshore areas to5

APEC ENERGY OVERVIEW 2017

AUSTRALIA

create opportunities for investment. The release, distributed worldwide, is a comprehensive package that includes
geological details of the acreage, bidding requirements and investment considerations for each release area on offer.
The onshore petroleum sector is managed by the relevant state/territory jurisdiction.
ENERGY MARKETSMARKET REFORMS

The COAG Energy Council, under the energy market reform program, currently has eight priority areas (COAG,2018b):


Consumer empowerment;Energy market transformation;Australian gas markets;Energy and carbon policy;

Institutional performance improvement;

Security, reliability, affordability and sustainability of the national electricity market;

Energy market governance; andEnergy security board

These priority areas have been guided by the Independent Review into the Future Security of the National Electricity Market,
released in mid-2017. The events that led to the review and its conclusions are discussed in the ‘Notable Energy
Developments’ section.
ELECTRICITY AND GAS MARKETSThe National Electricity Market (NEM) was established in 1998 to enable the inter-jurisdictional flow of electricity
among the Australian Capital Territory, New South Wales, Queensland, South Australia and Victoria (Tasmania joined
the NEM in 2005). Western Australia and the Northern Territory are not connected to the NEM because of theirdistance from the market. The NEM comprises a wholesale sector and a competitive retail sector. All dispatchedelectricity is traded through a central pool, where output from generators is aggregated and scheduled at five-minuteintervals to meet demand.
The Australian gas market comprises three distinct regional markets defined by pipeline transmission
infrastructure—the eastern gas market (including the Australian Capital Territory, New South Wales, Queensland, South
Australia, Tasmania and Victoria), the northern gas market (Northern Territory) and the western gas market (Western
Australia). The Northern Gas Pipeline, currently under construction, is scheduled to link the eastern and northernmarkets via Tennant Creek and Mt Isa in the late 2018.
All three of Australia’s gas markets are, to varying degrees, grappling with structural change associated with thedevelopment of huge amounts of new LNG supply capacity. This is most keenly felt in the eastern gas market where
the growth of unconventional gas production has underpinned new LNG plants that link that market to global gas
markets for the first time (the western and northern markets have been linked for some time). This has prompted
several government reviews, including two by the Australian Competition and Consumer Commission (ACCC, 2016,2018) and the Australian Energy Market Commission (AEMC, 2016) into the supply, demand and competitiveness ofthe east coast gas market.
The impact of these reviews in driving new policy and the adverse effects of gas price and supply issues onelectricity markets are discussed in the ‘Notable Energy Developments’ section.
A key component of ongoing energy market reforms was the establishment of the Australian Energy Market
Operator (AEMO) on 1 July 2009. AEMO represents the amalgamation of six electricity and gas market bodies: the
National Electricity Market Management Company (NEMMCO), Victorian Energy Networks Corporation(VENCorp), Electricity Supply Industry Planning Council, Retail Energy Market Company (REMCO), Gas Market
Company and Gas Retail Market Operator (AEMO, 2018a).

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AEMO’s functions include operating the NEM and the retail and wholesale gas markets in eastern and Southern
Australia; overseeing the system security of the NEM grid and the Victorian gas transmission network; undertaking
economy-wide transmission planning; and establishing a short-term trading market for gas from 2010. In 2015, AEMO
also took responsibility as the wholesale and retail market operator in Western Australia and the gas market bulletinboard. Power system operation functions in Western Australia were handed over to AEMO in 2016.
AEMO is also responsible for improving the operation of Australia’s energy markets. It prepares and publishes a
20-year National Transmission Network Development Plan, which provides information to market participants andpotential investors. In addition, it publishes the Electricity Statement of Opportunities and the Gas Statement ofOpportunities, both of which forecast long-term supply and demand in the eastern market. It also maintains Australia’s
gas market bulletin board; more recently, having taken charge of Western Australia’s gas and electricity markets, itreleases similar publications for that market (AEMO, 2018a).
AEMO oversees Australia’s energy market governance in cooperation with the Australian Energy Market
Commission (AEMC), which is the rule-making body, and the Australian Energy Regulator (AER), which is theregulating body. The COAG Energy Council, discussed previously, is responsible for energy policy and the legislative
frameworks under which AEMO, AEMC and AER operate.
FISCAL REGIME AND INVESTMENTFEDERAL CORPORATE INCOME TAX

The corporate taxation treatment of companies operating in the energy sector is generally the same as that in all otherindustries. Corporations that earn income in Australia are subject to corporate income tax imposed at a rate of 30%.
Project ring fencing does not apply, and the profits and losses of one project can be used to offset those of anotherproject, subject to common ownership criteria.
Certain expenditures incurred by energy companies, such as exploration expenditure and royalty payments, areimmediately deductible for corporate income tax purposes. Other indirect taxes, such as the payroll tax, fringe benefits
tax, fuel excise and land tax may apply.
FEDERAL PETROLEUM RESOURCE RENT TAX

The Petroleum Resource Rent Tax (PRRT) is a federal profits-based tax payable on the upstream profits of a petroleum
project. The PRRT has been in operation in Australia since 1 July 1986. Previously applied solely to operations inoffshore Australia, it was extended to apply to all onshore and offshore projects operating in Australia from 1 July 2012
(ATO, 2018a).
Unlike royalty and excise regimes, the PRRT applies to the profits derived from a petroleum project and not thevolume or value of the petroleum produced. Deductions are provided for all allowable expenditures (together withindexation of carry-forward losses) to ensure that only the economic rent generated from a petroleum project is capturedby the PRRT. Further, when other layers of resource taxes are applicable, such as state and territory royalties and federal
crude oil excise, such expenditures are creditable against the liabilities of PRRT projects. This ensures that petroleum
projects are not subject to double taxation (ATO, 2018a).
The PRRT applies at a rate of 40% to taxable profit derived in a financial year from a petroleum project. Taxable
profit is calculated by deducting eligible project expenses from the assessable revenues derived from the project. Because
the PRRT is a project-based tax, losses are not generally allowed to be offset against other project income. The exception
is exploration expenditure, which is transferable to other petroleum projects subject to conditions. PRRT payments are
deductible for income tax purposes. PRRT liability is calculated as shown in Figure 1 below (ATO, 2018a).

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Figure 1: Calculating the PRRT liability

Source: ATO (2018a).

The government recently completed a review of the design and operation of the PRRT. Released in April 2017,
the review highlighted possible improvements to the PRRT but did not recommend changes to the crude oil excise or
royalty schemes (Treasury, 2017).
ROYALTIESRoyalties are generally levied by the states as an alternative mechanism of charging for resource extraction. Royalty rates
vary across states and commodities. They are either specific, ad valorem, profit-based or a hybrid (flat ad valorem with aprofit component). With regard to petroleum, the state and Northern Territory governments collect royalties foronshore production. The rate is generally from 10% to 12.5% of the net wellhead value of production depending onwhether it is from a primary or secondary production licence or a combination of these (Industry, 2018a).
With regard to offshore production (excluding petroleum), 60% of the royalties are directed to the state or territory
governments and the remaining 40% to the Australian Government.
FEDERAL CRUDE OIL EXCISE

Excise arrangements apply to eligible crude oil and condensate production from the North West Shelf project area andonshore areas (including coastal waters). Excise is levied on the price of all sales made in a producing region at rates
based on the timing of the discovery and/or the date of development. The first 30 000 barrels of cumulative production
from each field are exempt from crude oil excise (ATO, 2018b).
EXPLORATION DEVELOPMENT INCENTIVE

Effective from 1 July 2014, the Australian Government introduced the Exploration Development Incentive (EDI) to
encourage investments in small exploration companies that undertake ‘greenfield’ mineral exploration in Australia. The
scheme is available to junior mineral exploration companies that incur eligible ‘greenfield’ exploration expenditures inAustralia (ATO, 2018c).
When a mining company does not have sufficient income to utilise exploration deductions, the EDI provides amechanism for Australian resident shareholders to deduct the expense of mining exploration against their taxable
income. The EDI does not apply to exploration for quarry materials, petroleum exploration (including exploration for
natural gas from coal seams and shale oil) or geothermal energy resources.
RESEARCH AND DEVELOPMENT TAX INCENTIVE

The research and development tax offset has been in effect since 1 July 2011. The two core components of the package
are as follows (ATO, 2018d):


A 45% refundable tax offset for companies with a turnover of less than AUD 20 million per year; and

A 40% non-refundable tax offset for aggregate turnover equal to or greater than AUD 20 million per year.

MINERALS RESOURCE RENT TAX

The Minerals Resource Rent Tax (MRRT) regime applied to iron ore and coal mining in Australia between 1 July 2012
and 30 September 2014. Following the repeal of the tax, no Australian entities have faced further MRRT-related
liabilities since 1 October 2014 (ATO, 2018e).

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AUSTRALIAJOINT PETROLEUM DEVELOPMENT AREA

Petroleum produced within the Joint Petroleum Development Area (JPDA), located in the Timor Sea between Australia
and Timor-Leste, is subject to fiscal terms outlined in a production-sharing contract (PSC). PSCs are agreements
between the parties to a petroleum extraction facility and the Australian and Timor-Leste governments regarding thepercentage of production each party will receive after the participating parties have recovered a specified amount ofcosts and expenses. Government revenues from petroleum extracted within the JPDA are divided, with 90% going toTimor-Leste and 10% to Australia (Industry, 2018b).
ENERGY EFFICIENCYIn December 2015, the COAG Energy Council released the National Energy Productivity Plan (NEPP). By better
coordinating energy efficiency, energy market reform and climate policy, the NEPP brings together new and existingmeasures from across the COAG Energy Council’s work program, as well as from the Commonwealth and industry.
The NEPP provides a framework and an economy-wide work plan designed to coordinate efforts and accelerate
initiatives to deliver a 40% improvement in Australia’s energy productivity from 2015 to 2030. Current research hassuggested that Australia can meet this target by implementing financially attractive end-use energy efficiency initiatives.
In particular, there are cost-effective opportunities to improve energy productivity in the transport, manufacturing andbuilding sectors (COAG, 2017a).
Energy productivity is a measure of the amount of economic output derived from each unit of energy consumed.
Over the past decade, Australia’s energy productivity has improved; however, it still lags behind many other developed
economies such as Japan, Germany and the United Kingdom. The NEPP takes action to address this gap. In the past,
improving Australia’s energy productivity has been challenging because of separation between supply-side energy
market reform and demand-side energy efficiency actions. The NEPP aims to bring supply-side and demand-side
policies closer to fully realise the benefits to both the customer and the broader energy system. Policies such as thecommercial building disclosure program, the emissions reduction fund, the Victorian residential efficiency scorecard,
Commonwealth Scientific and Industrial Research Organisation’s (CSIRO’s) energy-use modelling and ARENA’s and
CEFC’s (see next section for more detail on these organisations) funding of energy efficiency projects are all assistingin achieving this goal.
RENEWABLE ENERGY

Australia has abundant and diverse clean energy resources with significant potential for future development, as shownin Figure 2. Australia’s best wind and wave resources are mostly located towards the ‘roaring forties’ (the strong westerly
winds found in the Southern Hemisphere between the latitudes of 40 and 50 degrees) along the Southern and Western
coastlines, while outstanding solar resources exist across inland Australia. Large tidal and geothermal resources exist in
Northern and Central Australia, respectively.
From 2014–15 to 2015–16, solar PV, hydro and wind-powered electricity generation increased by 24%, 14% and6%, respectively, due to new capacity (solar and wind) and increased utilisation (hydro, which enjoyed improved water
inflows) (Environment, 2017a). In the case of solar and wind, this actually represents a slowdown of 54% and 22%,
respectively, on their average annual growth over the past decade (Environment, 2017a).

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Figure 2: Map showing the distribution of Australia’s energy resources

Source: GA (2018).

Australia’s Renewable Energy Target (RET) has been in operation since 2001 and aims to increase the share ofelectricity generation from renewable sources to 23.5% by 2020 (Environment, 2018d). Previously known as the
Mandatory Renewable Energy Target (and aiming to source only 2% of electricity generation from renewable resources),the RET has undergone several amendments since 2001, including being split into two parts: the small-scale renewableenergy scheme (SRES) and the large-scale renewable energy target (LRET) in 2011. The LRET mandates 33 000 GWh
of total electricity generation in 2020. The uncapped SRES provides a subsidy to small-scale technologies, such as
residential solar panels and solar hot water systems.
The Australian Renewable Energy Agency (ARENA) is an independent agency established by the AustralianGovernment on 1 July 2012. It has AUD 2 billion to fund renewable energy projects (for example, solar, bioenergy,
marine, geothermal and enabling technologies such as storage) until 2022. It also supports research and development,commercialisation and early deployment activities, energy efficiency and low emission technology and activities that
capture and share knowledge. The two primary objectives of ARENA are to improve the competitiveness of renewableenergy technologies and increase the supply of renewable energy in Australia. The Australian Centre for Renewable
Energy and Australian Solar Institute were incorporated into ARENA.
By June 2017, ARENA had committed AUD 1 billion in support of more than 320 projects, studies, fellowships
and scholarships, which have a total value of AUD 3.5 billion (ARENA, 2017). ARENA’s independent decision-making
board comprises up to seven members appointed by the Minister for the Environment and Energy. The board also has
a CEO appointed by the minister on the recommendation of the board. For more information, see: www.arena.gov.au.
The Clean Energy Finance Corporation (CEFC) is a statutory authority established and financed by the AustralianGovernment in 2012 to help mobilise investment in renewable energy, low-emission and energy efficiency projects andtechnologies in Australia. The CEFC is mandated to act with commercial rigour and seek benchmark rates of return.

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Between its establishment and June 2017, the CEFC has invested AUD 4.3 billion in projects worth AUD 11
billion (CEFC, 2017). Like ARENA, the CEFC is controlled by an independent board that appoints a CEO who is
responsible for day-to-day operations.
There is no Australia-wide feed-in tariff scheme to support small-scale renewable technologies. Most state andterritory governments have previously implemented jurisdictional feed-in tariff arrangements for small-scale renewable
technologies; however, most of these schemes have now been amended or closed.
Growth in renewable energy in Australia over the past decade has been mostly driven by residential solar PV andutility-scale wind farms. This dynamic is changing slightly as utility-scale solar has built momentum in the last few years
with the Nyngan (102 MW), Broken Hill (53 MW) and Royalla Solar PV Farms (20 MW) in New South Wales and the
ACT. Other large solar projects such as Aurora and Bungala in Port Augusta (150 MW and 220 MW, respectively),
Manildra and Parkes in New South Wales (50 MW and 55 MW, respectively), Clare, Darling Downs and Whitsunday
in Queensland (150 MW, 110 MW and 67.5 MW, respectively) and Bannerton and Yatpool in Victoria (88 MW and 81
MW, respectively) are all committed or under construction (AEMO, 2018b).
A significant number of wind generation projects such as Coopers Gap (453 MW), Sapphire (270 MW), Silverton(199 MW), Mt Emerald (181 MW), Mt Gellibrand (132 MW) and Lincoln Gap (126 MW) are also committed or underconstruction (AEMO, 2018b). The government has also undertaken a feasibility study on an expansion of the Snowy
Hydro scheme (dubbed Snowy Hydro 2.0) to expand the project by 2 gigawatt (GW) of capacity as well as provide an
additional 350 000 megawatt-hours (MWh) of storage at a cost of AUD 3.8 to 4.5 billion (Snowy Hydro, 2018). Snowy
Hydro will make a final investment decision in 2018.
ENERGY TECHNOLOGY AND RESEARCH AND DEVELOPMENT

In the Australian science system, the bulk of basic research occurs in the university sector. Funding delivery comes fromorganisations such as the Australian Research Council, which has established a range of competitive grant schemes.
Furthermore, the CSIRO’s Energy Flagship program provides a focus for energy research and development in Australia,
and ARENA supports research and development into renewable energy through funding and knowledge sharing.
NUCLEAR

Australia does not have any commercial nuclear reactors, but research is undertaken by the Australian Nuclear Scienceand Technology Organisation.
CLIMATE CHANGE

The Australian Government has two main commitments to reducing greenhouse gas emissions. The first one is a 5%
reduction of the 2000 levels by 2020. Second, Australia’s Nationally Determined Contribution (NDC), submitted to theUnited Nations Framework Convention on Climate Change (UNFCCC) in 2015, is a 26–28% reduction of the 2005
levels by 2030 (Environment, 2018e). The Emissions Reduction Fund (ERF) is the government’s tent-pole program tomeet this target. Legislation for the ERF was passed by the parliament on 31 October 2014.
The fund has three main components: crediting emission reductions, purchasing emission reductions andsafeguarding emission reductions. The Clean Energy Regulator (CER) administers the fund that operates as a reverse
auction, where the government purchases emission reductions on eligible carbon reduction projects. The total amountof money in the fund is AUD 2.55 billion. The sixth auction concluded in December 2017, where 26 abatement
contracts were awarded to deliver 7.95 million tonnes (Mt) of abatement at an average price per tonne of $13.08 for a
total of AUD 104 million (Environment, 2018f). Six auction rounds have awarded 404 carbon abatement contracts for
191.7 Mt of abatement since the implementation of the fund in 2014. The average price across all six auctions is now
AUD 11.90 per tonne.
Other programmes, policies and tools supporting action on climate change include the 20 million trees and carbon
neutral programmes, taxation measures and energy efficiencies initiatives. Further detail regarding these and otherprogrammes is available at http://environment.gov.au/climate-change/government. The repeal of the carbon tax by
Parliament became effective on 1 July 2014 (Environment, 2018g).

11APEC ENERGY OVERVIEW 2017

AUSTRALIAN OTA B L E E N E RG Y D E V E L O P M E N T S
THE FINKEL REVIEW AND NATIONAL ENERGY GUARANTEE

On 16 September 2016, South Australia experienced a rare ‘system black’ event—the total shutdown of power supply
to the grid. An extreme weather event damaged 23 pylons on electricity transmission towers in the state, which led to acascading series of events—automatic shutdowns at interconnectors and wind farms chief amongst them—that left thegrid without power for several days. The economic and political consequences of these events were widespread andcatalysed debate about the role of renewables in the NEM, prices, system operation and stability and costs andinvestment.
One of the government’s first responses was to establish The Independent Review into the Future Security of theElectricity Market, chaired by Australia’s chief scientist, Dr Alan Finkel (Environment, 2018g). The key issue tackled by
the review surrounds the energy ‘trilemma’: the need to deliver energy securely, affordably and sustainably. Historically,
Australia has satisfied two of these criteria: affordability and security of supply (mainly via cheap baseload coal-fired
generation). Over the past decade, the sustainability of the grid has improved via investment in wind and solar capacity;
however, this has occurred at the same time as dramatically rising prices. South Australia’s system black event showedthat security, the final pillar of the trilemma, was also under pressure.
The review makes numerous recommendations addressing each of these three challenges. Chiefly amongst which
was the need to agree on an emission reduction trajectory and develop a clean energy target to achieve that goal. The
review emphasises the importance of agreement across political lines to create certainty for the market to make theinvestments required to build sufficient new capacity. Other recommendations affect frequency response and inertia(required to maintain system stability); generator closures; improved system planning and integration; and better data,
forecasting and analysis. According to COAG, as of December 2017, most recommendations are currently under review
or on track, with a small number deemed to be complete or not yet started (COAG, 2017b).
One of the first recommendations implemented by government was the establishment of an Energy Security
Board (ESB). The ESB has been instrumental in shaping the government’s response to one of the key recommendationsof the review: a national energy guarantee (NEG). The NEG, rather than the clean energy target proposed in the Finkel
Review, aims to reduce carbon emissions while maintaining system reliability (Environment, 2017b). It will comprise
two parts. The first is a reliability guarantee, which will be set to ensure that retailers and some large users deliver a
sufficient amount of dispatchable generation. The second is an emission guarantee that will be set to ensure that
Australia achieves its international emission commitments. The government is expected to release further details
regarding the implementation and functioning of these guarantees in 2018.
SYSTEM PLANNING

The AEMO has traditionally been responsible for an annual system planning publication called the National
Transmission Network Development Plan (NTNDP). The Finkel Review recommended that the AEMO should
undertake an integrated grid plan to facilitate the development and connection of renewable energy zones. The AEMO
has decided to roll the yet-to-be released 2017 NTNDP into this new publication, called an Integrated System Plan
(ISP). The ISP will have greater focus on the role of distributed renewable generation in the grid, including particularconsideration of renewable energy zones and transmission development options. The AEMO will release the first ISP
in mid-2018 (AEMO, 2018c).
GAS MARKETS

Australia’s east coast gas market has been undergoing transformative change in recent years as new LNG plants comeonline, drastically increasing gas production and consumption and linking the domestic and international markets forthe first time. Gas prices have increased dramatically, and long-term contracts have become much harder for buyers tosecure. This has occurred due to several reasons, chief amongst which is the lower-than-expected production at
Queensland CSG fields. Higher gas consumption from the electricity sector (because of coal plant closures), higher
production costs and restrictions on fracking in some states and territories have also contributed to price rises(Environment, 2018i).
The government introduced the Australian Domestic Gas Security Mechanism in July 2017 as a temporary
measure to deal with gas shortfalls. The mechanism allows the Minister for Resources and Northern Australia, on the

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recommendation of the AEMO, the ACCC, industry and other stakeholders, to restrict LNG exports by producers thatare drawing more gas from the domestic market than they are replacing (Environment, 2018i).
The government has also allocated AUD 90 million towards numerous other measures aimed at alleviatingtightness in the gas market. These include resource assessments and supply-side reforms, in addition to improvements
to transport and data transparency (Environment, 2018j).
COAG’s Gas Market Reform Group, established in August 2016, continues to lead the design, development andimplementation of a new commercial arbitration framework for pipelines, capacity trading reforms, market transparency
reforms and wholesale market reforms, all aimed at promoting the national gas objective 1 (COAG, 2016a).
NEW ENERGY PROJECTSThe huge wave of investment in Australia’s LNG sector is nearing its conclusion. Of the seven new LNG projects tocommence construction in the last five years, only three are still under construction. Wheatstone and Prelude, off thecoast of Western Australia, are due online in mid-2018, representing 8.9 and 3.6 million tonnes per annum (Mtpa) of
capacity, while first gas at Ichthys, a two-train 8.4 Mtpa project in Darwin, is scheduled for early 2018 (OCE, 2017).
Numerous smaller coal, gas and oil projects, including the Mt Pleasant and Byerwen coal projects, Greater
Western Flank gas and Greater Enfield oil, are also under construction and will be completed in 2018. Other new energy
projects at the feasibility stage, including the enormous Carmichael coal mine in Queensland, face uncertain prospects
as companies wait to see how market conditions unfold (OCE, 2017).

1 The national gas objective is to promote efficient investment in and efficient operation and use of natural gas services for the long-term interests of consumers of natural gas with respect to price, quality, safety, reliability and security of supply of natural gas.

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AUSTRALIAREFERENCES

ABS (Australian Bureau of Statistics) (2017), Table 37: Industry Gross Value Added, Chain Volume Measures, Annual,
http://www.abs.gov.au/ausstats/abs@.nsf/mf/5206.0.
ACCC (Australian Competition and Consumer Commission) (2016), East Coast Gas Inquiry 2015,
https://www.accc.gov.au/regulated-infrastructure/energy/east-coast-gas-inquiry-2015.
–– (2018), Gas inquiry 2017-2020, https://www.accc.gov.au/regulated-infrastructure/energy/gas-inquiry-2017-2020.
AEMC (Australian Energy Market Commission) (2016), East Coast Wholesale Gas Market and Pipeline Frameworks Review,
http://www.aemc.gov.au/Markets-Reviews-Advice/East-Coast-Wholesale-Gas-Market-and-Pipeline-Frame.
AEMO (Australian Energy Market Operator) (2018a), Generation Information Page,
https://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-andforecasting/Generation-information.
–– (2018b), About AEMO, https://www.aemo.com.au/About-AEMO.
–– (2018c), Integrated System Plan, https://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planningand-forecasting/Integrated-System-Plan.
ARENA (Australian Renewable Energy Agency) (2017), ARENA Annual Report 2016-17,
https://arena.gov.au/assets/2017/10/2016-2017-arena-annual-report.pdf.
Austrade (Australian Trade Commission) (2018), Why Australia – Benchmark Report 2018,
http://www.austrade.gov.au/International/Invest/Resources/Benchmark-Report.
ATO (Australian Tax Office) (2018a), Petroleum Resources Rent Tax, https://www.ato.gov.au/Business/Petroleumresource-rent-tax.
–– (2018b), Crude Oil and Condensate, https://www.ato.gov.au/Business/Excise-and-excise-equivalent-goods/Fuelexcise/Crude-oil-and-condensate/.
–– (2018c), Exploration Development Incentive, https://www.ato.gov.au/Business/Exploration-Development-Incentive/.
–– (2018d), Research and Development Tax Incentive, https://www.ato.gov.au/Business/Research-and-development-taxincentive/.
–– (2018e), Mineral Resource Rent Tax (MRRT), www.ato.gov.au/Business/Minerals-resource-rent-tax/.
CEFC (Clean Energy Finance Corporation) (2017), Annual Report 2016-17, http://annualreport2017.cefc.com.au/.
COAG (Coalition of Australian Governments) (2016a), COAG Energy Council Gas Market Reform Package,
http://coagenergycouncil.gov.au/publications/coag-energy-council-gas-market-reform-package.
–– (2017a), National Energy Productivity Plan Annual Report 2017,
http://coagenergycouncil.gov.au/publications/national-energy-productivity-plan-annual-report-2017.
–– (2017b), The Health of the National Electricity Market Report,
http://www.coagenergycouncil.gov.au/publications/health-national-electricity-market-report.
–– (2018a), Our Role, http://www.coagenergycouncil.gov.au/about-us/our-role.
–– (2018b), Council Priorities, http://www.coagenergycouncil.gov.au/council-priorities.
Environment (Australian Government Department of the Environment and Energy) (2017a), Australian Energy Update
2017, https://www.energy.gov.au/publications/australian-energy-update-2017.
–– (2017b), Powering Forward, https://www.energy.gov.au/publications/powering-forward.
–– (2018a), Energy Security Assessments, https://www.energy.gov.au/government-priorities/energy-security/energysecurity-assessments.

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AUSTRALIA–– (2018b), IEA International Energy Program Treaty, https://www.energy.gov.au/iea-international-energy-programtreaty.
–– (2018c), International Activity, https://www.energy.gov.au/government-priorities/international-activity.
–– (2018d), The Renewable Energy Target (RET) scheme, http://www.environment.gov.au/climatechange/government/renewable-energy-target-scheme–– (2018e), Emissions Reduction Fund, http://environment.gov.au/climate-change/government/emissions-reductionfund.
–– (2018f), Emissions Reduction Fund Update, http://environment.gov.au/climate-change/publications/emissionsreduction-fund-update.
–– (2018g), Repealing the Carbon Tax, http://environment.gov.au/climate-change/government/repealing-carbon-tax.
–– (2018h), Independent Review into the Future Security of the National Electricity Market - Blueprint for the Future,https://www.energy.gov.au/publications/independent-review-future-security-national-electricity-marketblueprint-future.
–– (2018i), Why Are Gas Prices Changing? https://www.energy.gov.au/government-priorities/energy-supply/why-aregas-prices-changing.
–– (2018j), Gas Markets, https://www.energy.gov.au/government-priorities/energy-markets/gas-markets.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy Database,
http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
GA (Geoscience Australia) (2018), Australian Energy Resource Assessment, http://www.ga.gov.au/aera.
Industry (Australian Government Department of Industry, Innovation and Science) (2018a), Australian Government
Royalty,https://industry.gov.au/resource/Enhancing/ResourcesTaxation/Pages/AustralianGovernmentRoyalty.aspx.
–– (2018b), Timor-Leste and Australia Joint Petroleum Development Area,
https://industry.gov.au/resource/UpstreamPetroleum/Pages/TimorLesteandAustraliaJointPetroleumDevelopmentArea.aspx.
OCE (Office of the Chief Economist) (2015), End-Use Energy Intensity in Australia, https://industry.gov.au/Office-ofthe-Chief-Economist/Publications/Pages/Economic-analysis-of-end-use-energy-intensity-in-Australia.aspx.
–– (2017), Resources and Energy Quarterly, December 2017, Department of Industry, Innovation and Science,www.industry.gov.au/Office-of-the-Chief-Economist/Publications/Pages/Resources-and-energyquarterly.aspx/.
Snowy Hydro (2018), Snowy 2.0, http://www.snowyhydro.com.au/our-scheme/snowy20/.
Treasury (Australian Government Department of the Treasury) (2017), Review of the Petroleum Resource Rent Tax,
https://treasury.gov.au/review/review-of-the-petroleum-resource-rent-tax/

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AUSTRALIAUSEFUL LINKS

Australian Bureau of Statistics—www.abs.gov.au
Australian Energy Market Commission—www.aemc.gov.au
Australian Energy Market Operator—www.aemo.com.au
Australian Energy Regulator—www.aer.gov.au
Australian Government Department of Industry, Innovation and Science—www.industry.gov.au
Australian Government Department of the Environment and Energy—www.environment.gov.au
Clean Energy Regulator—www.cleanenergyregulator.gov.au
COAG Energy Council—http://www.coagenergycouncil.gov.au/
COAG Gas Market Reform Group—http://gmrg.coagenergycouncil.gov.au/
Energy White Paper—www.ewp.industry.gov.au
Energy.gov.au—www.energy.gov.au
Office of the Chief Economist—www.industry.gov.au/industry/Office-of-the-Chief-Economist/Pages/default.aspx

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BRUNEI DARUSSALAM

B R U N E I DA R U S S A L A M
I N T ROD U C T I ON

Brunei Darussalam is a small sultanate bordering the South China Sea and the state of Sarawak, Malaysia. The
economy has a land area of 5 765 square kilometres (km2). It is divided into four administrative districts,
namely, Brunei–Muara, Belait, Tutong and Temburong districts. Its capital city is Bandar Seri Begawan, locatedin the Brunei–Muara district. In 2015, the population was 418 000 and the gross domestic product (GDP)growth slowed to 0.6% at USD 31 billion (2010 USD purchasing power parity [PPP]). Brunei Darussalam isprosperous as it enjoys an abundance of oil and natural gas. Accordingly, it is one of the wealthiest economies
in the APEC region. Strategically located within a region with vast hydrocarbon wealth, Brunei Darussalam
has been able to finance its development programs since the discovery of oil in 1929. Crude oil and natural gas
have also dominated the economy’s foreign trade, constituting approximately 96% of the total exports, whereas
imports are dominated by machinery, transport equipment, manufactured goods and food.
The dependency on crude oil and natural gas exports for revenue remains high, which constitutes morethan 60% of the economy’s GDP. This has generated a high per capita GDP of USD 73 091 (2010 USD PPP
per capita) in 2015, which has enabled the government to continue providing the citizens a high standard ofliving, no income tax and free health and education, among other services. The government has proposed
efforts to diversify the economic structure and has introduced several reforms focusing on new foreign direct
investments (FDI).
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesb

Area (km2)

5 765

Oil (billion barrels)

1.1

Population (thousands)418

Gas (billion cubic metres)

300

GDP (2010 USD billion PPP)

31

Coal (million tonnes)–

GDP (2010 USD PPP per capita)

73 091Uranium (kilotonnes U)–

Sources: a EGEDA (2017); b BP (2017).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLYBrunei Darussalam is rich in crude oil and natural gas. In 2015, approximately 84% of the economy’s primaryenergy was met by natural gas, while oil’s share remained at 16%. The total primary energy supply declined to
4 034 kilotonnes of oil equivalent (ktoe) in 2015, which represents a decline of 3% from 4 154 ktoe in 2014.
Due to the small size of Brunei Darussalam’s population, domestic energy needs are modest; thus, themajority of natural gas and crude oil produced in Brunei Darussalam is exported. Only a small percentage ofnatural gas is allocated for domestic power generation and to the downstream petrochemical sector. Similarly,
approximately 12% of the crude oil produced is refined to produce petroleum products to meet domestic
demand, and the rest is exported.
In 2015, Japan was the largest buyer of LNG exports from Brunei Darussalam, at approximately 64%,
followed by other economies in the APEC region such as South Korea (20%), Chinese Taipei (12%) and
Malaysia (2%); a small percentage was exported to the Middle East (2%). Crude oil is exported as term cargoes,
and the main destinations are APEC economies at 76%, while the rest is destined for other Asian economies.
Thailand was the primary export destination, at 23% of total crude oil exports.

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Brunei Darussalam’s total installed electricity generation capacity from public utilities and auto producers
reached 922 megawatts (MW) in 2015. In the same year, total electricity generated was 4 666 gigawatt-hours(GWh). Almost all of the electricity was generated by natural gas (EGEDA, 2017).
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

18 194 Industry sector

153 Total power generation

4 666

Net imports and others–14 076 Transport sector

456

Thermal

4 665

4 034 Other sectors

319

Hydro

–

– Non-energy

432

Nuclear–928

Others1

Total primary energy supply
Coal
Oil
Gas

636 Final energy consumption*
3 398

Coal

–

Renewables

–

Oil

617

Others–Gas

19

Renewables–

Electricity and others292

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

Brunei Darussalam’s final energy consumption (excluding non-energy) in 2015 declined by 0.1% to 928 ktoe
from the previous year. The transport sector constituted a large share of the total energy consumption in 2015(49%). Due to the lack of public transport, per capita vehicle ownership in Brunei Darussalam is one of thehighest in the APEC region, which is equivalent to one vehicle being registered for every 2.8 Bruneians,
according to the Ministry of Communication’s Land Transport Master Plan (MOC, 2014). The low price of oil
also triggered high consumption in this sector. The economy has the lowest pump prices in South-East Asia.
The other sectors (residential, commercial and agricultural sectors combined) followed with 34% of theeconomy’s energy consumption. The remaining amount was for the industry sector (16%). In terms of theenergy source, oil constituted 66% of the final consumption, followed by electricity and others (31%) and gas(2%). Natural gas constituted 99% of the fuel type used to generate electricity, while 0.95% was generated bydiesel fuel and 0.05% from photovoltaic (PV) solar power systems.
ENERGY INTENSITY ANALYSIS

In line with APEC’s overall target, Brunei Darussalam intends to reduce 45% of its energy intensity by 2035
from the 2005 level. In 2015, primary intensity dropped to 132 tonnes of oil equivalent per million USD(toe/million USD) and final consumption intensity also declined to 45 toe/million USD, representing a yearon-year decline of 2.3% and 8.2%, respectively. Both measures experienced a significant reduction, indicating
a fall in the consumption of natural gas for activities in the non-energy sector compared to that in the previous
year. However, if intensity is measured in the absence of non-energy, final energy consumption intensity
remains unchanged. This could imply that changes in intensity are attributed to the trend in the non-energy
sector and that this sector plays a significant role in determining Brunei Darussalam’s energy intensity.

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Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

135

132

–2.3

Total final consumption

49

45

–8.2

Final energy consumption excl. non-energy

30.3

30.4

0.5

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

Brunei Darussalam heavily relies on fossil fuels to meet its energy demand. At present, approximately 99.95%
of the economy’s electricity is sourced from non-renewables and the remaining 0.05% comes from solar. The
main obstacle to renewable development in Brunei Darussalam lies in the cost. The economy’s electricity priceis heavily subsidised due to vast hydrocarbon resources used for electricity generation in its thermal power
plants.
Table 4: Renewable energy share analysis, 2014 vs 2015

929

928

Change (%)
2014 vs 2015
–0.1

929

928

–0.1

Traditional biomass*

0

0

0

Modern renewables*

0

0

0

Share of modern renewables to final energy
consumption (%)

0

0

0

2014
Final energy consumption
Non-renewables (Fossils and others)

2015

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal and so on) including biogas and wood pellets are
considered modern renewables although data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKBrunei Darussalam’s energy policy is centred on its oil and gas industry. Following the oil production peak at
254 000 barrels per day (bbl/d) in 1979, the government imposed a strict conservation policy on production
at 150 000 bbl/d in 1981. However, the policy was revised in November 1990 when the government removed
the limit on production. This increased production wherein oil production level reached 219 000 bbl/d in
2006.
The Brunei Natural Gas Policy (Production and Utilisation) was introduced in 2000 to satisfy gas export
obligations. The policy aimed to maintain gas production at a level that could sustain obligations, open new
areas for exploration and development and encourage increased exploration by new and existing operators.
Under the policy, priority is always given to domestic gas use, especially for electricity power generation.

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Brunei Darussalam’s energy sector plays a pivotal role in the realisation of Wawasan Brunei 2035 (Vision
Brunei 2035), the long-term development plan for the country. Wawasan Brunei 2035 has three main goals forthe next two decades as follows:To support and enhance the accomplishments of its well-educated and highly skilled people, as measured
by the highest international standards;

To achieve quality of life that is among the top 10 economies of the world; and

To build a dynamic and sustainable economy with an income per capita that is also among the top 10
economies of the world.

Achieving the goals of Wawasan Brunei 2035 will require a significant increase in the activity level of all
the economic sectors in the economy, including the energy sector. In line with aspirations to grow in asustainable manner, Brunei Darussalam launched its first Brunei Darussalam Energy White Paper (EWP) in
March 2014. The EWP describes a framework for strategic actions, which ensures sustainable energy toaugment Brunei Darussalam’s prosperity.
ENERGY SECTOR STRUCTURE

The Energy and Industry Department, Prime Minister’s Office (EIDPMO), formerly known as the Energy
Department, Prime Minister’s Office (EDPMO), acts as a regulator for the oil and gas industry in Brunei
Darussalam. It oversees all activities conducted by oil and gas companies in Brunei Darussalam. EIDPMO has
set four strategic goals to accelerate and enhance the economic growth of the economy as follows:Strengthen and diversify our economy;

Nurture conducive business environments;

Ensure safe and secure work environments; andDevelop an industry-ready local workforce.

The above strategic goals not only encompass goals to be achieved within the oil and gas sector but also
relate to the development of the non-oil and gas sector.
PetroleumBRUNEI, Brunei Darussalam’s national oil company, was ratified in January 2002 by theBrunei National Petroleum Company Order. It is a private limited company owned solely by the government.
PetroleumBRUNEI is given designated areas for which the company has the right to negotiate, conclude andadminister petroleum agreements.
On 24 May 2005, the Energy Division at the Prime Minister’s Office was established as the body
responsible for the formulation and implementation of Brunei Darussalam’s energy policies and other energyrelated matters. The Petroleum Unit, which oversees the development of the economy’s oil and gas sector, andthe Department of Electrical Services, which is tasked with managing and developing the economy’s electricity
sector, come under the purview of the Minister of Energy at the Prime Minister’s Office. In 2011, the Energy
Division and the Petroleum Unit merged to become the EDPMO.
ENERGY SECURITY

Brunei Darussalam recognises the need to enhance energy security and sustainability, improve energy efficiency
and accelerate the deployment of renewable energy and a clean energy supply. Consequently, the economy
works to strengthen the partnership arrangements among all its stakeholders.
Brunei Darussalam is an active member of the ASEAN. It likewise supports the implementation ofstrategies that relate to energy security as well as the diversification of supply, energy efficiency andconservation among the regions. The economy is actively working with ASEAN towards the achievement of
the targets set under the ASEAN Plan of Action for Energy Cooperation 2016–2025 (the Action Plan). This
includes flagship projects such as the ASEAN Power Grid (APG) and the Trans-ASEAN Gas Pipeline(TAGP) projects, among others.

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UPSTREAM ENERGY DEVELOPMENT

Brunei Darussalam is the fourth-largest oil producer in South-East Asia. Brunei Shell Petroleum Company Sdn
Bhd (BSP) is the main oil producer in the economy, jointly owned by the government and the Royal Dutch
Shell Company. BSP has seven offshore and two onshore oilfields. The offshore fields are Southwest Ampa,
Fairley, Fairley Baram (shared with Malaysia), Magpie, Gannet, Iron Duke and Champion. The Champion fieldholds approximately 40% of the economy’s oil reserves. It is situated within 30 metres of water about 70 km
northeast of Seria. Meanwhile, 13 km off Kuala Belait, the Southwest Ampa field holds more than half of theeconomy’s total gas reserves. The other oil and gas companies that currently operate in the concession andproduction-sharing areas are Total E&P Deep Offshore Borneo B.V. (Total), Petronas Carigali Brunei Limited
and Shell Deepwater Borneo Limited.
Brunei Darussalam has long-term plans to boost upstream production levels from 372 000 barrels of oil
equivalent per day (BOE/d) in 2013 to 430 000 BOE/d by 2017 and 650 000 BOE/d by 2035. This is inaccordance with the Brunei Darussalam EWP, where additional reserves totalling 3.5 billion barrels will betargeted by 2035. Brunei Darussalam is committed to maintaining its oil and gas reserve replacement ratio(RRR) at more than one to meet its upstream production target. Specifically, the economy will undertake
several initiatives to stimulate production, such as rejuvenating existing fields, maximising economic recovery
from mature and newly discovered fields and reviewing potential solutions for the development of
uneconomic, small and unconnected fields.
New offshore discoveries in the South China Sea are expected to prolong Brunei Darussalam’shydrocarbon production past the lifespan of its maturing fields. In a bid to develop these fields, the economy’s
oil and gas industry has opened tenders valued at more than USD 2.2 billion since early 2016. Calls for tender
have been made for the provision of information technology, security and support services and construction
and maintenance, along with the supply of advanced technology, training, seabed sampling and otherexploratory analysis. A Malaysian service operator, Icon Offshore, has won a USD 27 million contract toprovide offshore support vessels, while an Indonesian offshore services company, Wintermar Offshore
Marine, has been awarded contracts with BSP valued at USD 5.5 million to serve coastal platforms.
The economy also aims to achieve around 100 000 BOE/d from upstream international venture
investments by 2035. On 19 November 2013, PetroleumBRUNEI was awarded Block EP-1, the onshore
Kyaukkyi-Mindon area located 250 km north of Yangon, Myanmar. This covers an area of 1 135 km2.
PetroleumBRUNEI will conduct all petroleum activities in Myanmar under the production sharing agreement.
Other upstream projects for PetroleumBRUNEI abroad include an offshore block in Sarawak, Malaysia, anda shale gas project in Canada, thereby increasing international investments (PB, 2013).
DOWNSTREAM ENERGY DEVELOPMENT

Brunei Darussalam aims to increase the revenue from domestic downstream industries to BND 5 billion in
2035. The highest contribution to the existing downstream industry in the economy comes from methanol
produced from the economy’s natural gas resources as feedstock. This industry aims to contribute
approximately BND 300 million to the economy annually, which means increasing the economic output fromdownstream processing to satisfy the growing demand, especially from emerging markets. To accommodate
these growing needs, the Brunei Economic Development Board (BEDB) initiated the development ofspecialised industrial parks, such as the Sungai Liang Industrial Park (SPARK) and Pulau Muara Besar (PMB),
for petrochemicals and other downstream oil and gas activities.
The government will provide appropriate support and incentives to encourage more investors to venture
into developing and diversifying additional downstream opportunities, such as gas-based petrochemicals andcrude- and condensate-based petrochemicals. A priority initiative entitled ‘Evaluate Feasibility of Downstream
Derivatives’ was likewise established as part of the downstream energy development to ensure the achievementof this target. Enabling such activity under this initiative could function as a possible extension of thepetrochemical chain, which includes ethylene and propylene building blocks.

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ENERGY MARKETSThe government regulates the energy market in Brunei Darussalam. In view of the maturing energy markets,
especially in the oil and gas industry, the government recognises the importance of having a comprehensive
policy and regulatory framework to support the strategic objectives that have been established for the energy
sector. EIDPMO has initially identified key regulatory policies and frameworks, which include, among others,
monitoring the local content requirement in the bidding process for contracts from operators. A Local
Business Development (LBD) framework has been enforced to ensure a fair and level playing field in themarket and maximise local spin offs from oil and gas activities.
ELECTRICITY MARKET

Brunei Darussalam’s transmission system comprises three independent networks operated by two electricalutilities, the Department of Electrical Services (DES) and the Berakas Power Management Company Sdn Bhd(BPMC). The DES, under the umbrella of EIDPMO, was set up in 1921, and its functions are to manage andoversee the development of the electricity sector (DES, 2013). The BPMC, a private company, is owned by
the Brunei Investment Agency that reports to a board of directors. Brunei Darussalam’s electricity generationis almost entirely natural gas-fired. The only exceptions are the diesel power station in the Temburong District
and the 1.2 MW Tenaga Suria Brunei (TSB) PV demonstration plant. Approximately 99% of the economy’s
population is connected to the electrical grid.
ENERGY EFFICIENCYBrunei Darussalam established the Energy Efficiency and Conservation (EEC) roadmap in 2011 that specifies
comprehensive EEC action plans that will be implemented for the next 24 years until 2035. Through the
rigorous implementation of EEC key initiatives, coupled with the deployment of renewable energy (RE)programs, Brunei Darussalam will be able to reduce the nation’s total energy consumption (TEC) by up to
63%. The reduction will primarily come from a reduction of the fossil fuel supply for inland energy use via
five major sectors, namely, power, commercial, residential, transportation and industrial. This was announced
by His Majesty the Sultan and Yang Di-Pertuan of Brunei Darussalam at the United Nations (UN) Climate
Change Summit in September 2014 (RTB News, 2014). Some of the key action plans that have been and will
be undertaken to support the key initiatives are as follows (UNFCCC, 2015):

Electricity Tariff Reform
Electricity tariff reform for the residential sector was implemented on 1 January 2012 to help low-income
citizens through the minimum charge of one cent per kWh for basic electricity consumption and,concurrently, to promote energy saving and avoid energy wastage. These measures were designed to be
progressive in contrast to the nature of regressive tariffs to enhance energy saving within the reform
package. The government is also planning to initiate electricity tariff reforms in other sectors as deemed
appropriate.

Standards and Labelling Order
EIDPMO, in collaboration with the Brunei National Energy Research Institute (BNERI), is currently inthe process of developing the standard and labelling order. The objective of the order is to restrict orperhaps halt the imports of non-efficient electrical appliances and products, such as air conditioners, aswell as to educate and encourage people to opt for more energy-efficient electrical appliances andproducts.



EEC Building Guidelines for the Non-Residential Sector
The 2015 EEC Building Guidelines for Non-Residential Buildings was launched by the Ministry ofDevelopment in May 2015. All government and new buildings are obligated to adopt the guidelines inaccordance with the Energy Efficiency Index (EEI) baseline in kilowatt-hours per square metre, which

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has been set in the guidelines. With the introduction of these baselines, the energy consumption of newbuildings could be reduced up to 30%.



Fuel Economy Regulation
EIDPMO is currently working with the Ministry of Communication for the implementation of fueleconomy regulations. To support this policy initiative, the introduction of hybrid cars, fuel-efficient
vehicles (FEV) and electric vehicles has already been widely undertaken.

Financial Incentives
EIDPMO and the Ministry of Finance are examining the introduction of appropriate financial incentives
for energy-efficient appliances and vehicles in the form of tax exemptions, tax reductions or rebate
schemes for energy-efficient appliances and products.

Energy Management Policy
Brunei Darussalam is considering the adoption of an energy management policy compatible with ISO
50001.



Creation of AwarenessThe government will continue to increase awareness through energy clubs, energy exhibitions, roadshows, seminars and workshops on energy savings and best practices in the EEC for Brunei Darussalam.

Further, the government endeavours to improve Brunei Darussalam’s power generation efficiency togreater than 45% by 2020 by replacing simple-cycle power plants with a combined-cycle or cogeneration plant(CHP plant) and by establishing a structured maintenance program.
BRUNEI DARUSSALAM ENERGY CONSUMPTION SURVEY FOR RESIDENTIAL SECTOR (2015)

This is the first comprehensive energy consumption survey in Brunei Darussalam. It provides insights into theconsumption behaviour of the residential sector and recommends policy options and measures that have thegreatest impact. This project was conducted and supported by the Economic Research Institute for ASEAN
and East Asia (ERIA) in cooperation with EIDPMO and BNERI. The survey was completed in December
2015. From the survey, it was concluded that the pattern of end-use energy consumption is completely
dominated by cooling systems, followed by refrigeration, lighting and water heating. Four major policies havebeen identified, namely, standards and labelling, incentive tariff reforms, residential building energy efficiency
and greater campaign awareness.
BRUNEI DARUSSALAM DOMESTIC GAS CONSUMPTION SURVEY (2016)

Surveys on the consumption of domestic gas supplies at residences in the Belait District were conducted inlate October 2016, initiated by the Public Works Department and EIDPMO. The government commenced
the study to look for more efficient ways of operating the direct gas supply line to reduce wastage.
Approximately 10 000 households and businesses in Seria and Kuala Belait (towns in the Belait District) aresupplied domestic gas directly through pipelines instead of gas cylinders, which are used by a majority of the
population.
RENEWABLE ENERGY

Brunei Darussalam has set a long-term goal that requires 10% of the economy’s total power generation mix tocome from renewable energy sources by 2035. This represents one of the key performance indicators (KPI)
under the second series of key strategic goals. Renewable energy development in Brunei Darussalam has four
major priority initiatives as follows (EIDPMO, 2014):

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The introduction of renewable energy policies and regulatory frameworks;The growth of the market deployment of solar PV and the promotion of waste-to-energy technologies;

The growth of awareness and the promotion of human capacity development; andSupport for R&D and technology transfers.

Solar energy is by far the most promising renewable energy source, given the economy’s exposure toequatorial sunshine. In July 2010, the government commissioned a 1.2 MW solar power plant—TSB. TSB isconnected to the national power grid, which can power up approximately 200 homes with a designed installedcapacity of 1.2 MW. The plant operated as a three-year demonstration project from July 2010 to October 2013
before it managed to generate approximately 5 514 MWh of electricity, thus saving approximately 48 302
million British thermal units (MMBtu) of natural gas and avoiding approximately 3 939 tonnes of carbon
dioxide (CO2) emissions.
The economy recently completed a waste-to-energy assessment study, which estimated that municipal
solid waste production could be developed with a capacity of 10 MW. Meanwhile, for other potential alternative
energy sources, which include wind power and hydropower, they may still be subject to further R&D
collaboration among EIDPMO, BNERI and other agencies (both the government and private sectors).
Deployment of these alternative energy sources will depend on the maturity of their technologies, and they
have been integrated into the national RE roadmap based on medium-term and long-term timelines.
NUCLEAR

Brunei Darussalam does not have a nuclear energy industry.
CLIMATE CHANGE

Brunei Darussalam recognises the importance of its economic growth for energy security and environmental
sustainability. Environmental policy directions are embedded in Vision Brunei 2035. These are as follows:

Implementing the highest environmental standards for existing and new industries in accordance withthe established international standards and practices;

Strictly enforcing appropriate regulations on the maintenance of environments that affect public healthand safety; andSupporting global and regional efforts to address trans-border and regional environmental concerns.

Brunei Darussalam acceded to the United Nations Framework Convention on Climate Change(UNFCCC) in 2007 and to its Kyoto Protocol in 2009. It also associated itself with the Copenhagen Accord
in 2009. At the twenty-first session of the Conference of the Parties (COP21) to the UNFCCC, Brunei
Darussalam identified some key actions directed at reducing greenhouse gas (GHG) emissions by 2035 throughthe following goals (UNFCCC, 2015):



To reduce 63% of the economy’s energy consumption compared with the business-as-usual (BAU)
scenario;

To derive 10% of the energy mix from the utilisation of renewable energy; and

To reduce 40% of CO2 emissions from morning peak-hour vehicle use compared with the BAU scenario.

Brunei Darussalam’s net GHG emissions represented a small fraction of approximately 0.016% of global
emissions in 2010 (UNFCCC, 2016). Although the contribution to global GHG emissions is and will remain
relatively small, Brunei Darussalam was committed to play a part in combatting the adverse effects of climatechange by ratifying the Paris Agreement under the auspices of the UNFCCC on 21 September 2016. The
agreement entered into force on 4 November 2016.

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ENERGY INFRASTRUCTURE PROJECTSBrunei Darussalam seeks to maximise the potential of the economy’s oil and gas resources and take advantage
of its strategic location for trading. One of the key initiatives under Vision Brunei 2035 is to designate industrial‘cluster-specific’ sites with supporting infrastructures and facilities. The first site, established in 2007, was theSPARK, designed specifically for downstream petrochemical processing activities. The first petrochemicalplant constructed at the site, a methanol production plant, was successfully commissioned in April 2010 (BMC,2010).
The second industrial site is being developed at PMB for oilfield support services, such as an integrated
marine supply base (IMSB), fabrication yard and further downstream activities. The anchoring project will be
a USD 3.4 billion oil refinery and aromatics cracker project to be developed by the Zheijiang Hengyi GroupCo. Ltd. The project is expected to begin operation in the first half of 2019, with a production capacity of
approximately 175 000 bbl/d. The project will produce paraxylene and benzene, in addition to refined products
such as gasoline, jet fuel and diesel. In addition, a new 400 MW power plant will be built at PMB to provide
power and steam to industries, including Hengyi.
In the power sector, a memorandum of understanding was signed among the government, Brunei LNG
and BSP to expand the Lumut Co-Generation Power Station to an installed capacity of 246 MW, an increaseof 66 MW. This will meet the growing energy demand for the next 15 years and beyond based on the expected
increase in the number of households and industrial activities. The new expanded plant will boost the improved
efficiency to greater than 30% through the application of combined heat and power integration or cogeneration(EIDPMO, 2014).
Meanwhile, Brunei Gas Carriers Sdn Bhd (BGC) welcomed its fifth A-Class vessel in the third quarter of
2015. The vessel, named ‘Amadi’, follows the arrival of its sister ship ‘Amani’, BGC’s largest ship with a capacityof 155 000 cubic metres. The replacement of B-class ships owned by Brunei Shell Tankers (BST), which havea smaller capacity for transporting LNG to A-class ships, is in accordance with a strategic program by the LNG
carrier to modernise and localise its service. BGC provides LNG transportation services from Brunei
Darussalam to Japan, Korea, Malaysia and Chinese Taipei (BGC, 2015).
THE US–ASIA PACIFIC COMPREHENSIVE ENERGY PARTNERSHIPAt the seventh East Asia Summit (EAS) in 2012, former United States President Obama, in partnership with
His Majesty the Sultan and Yang Di-Pertuan of Brunei Darussalam and President Susilo Bambang Yudhoyono
of Indonesia, announced the formation of the US–Asia Pacific Comprehensive Energy Partnership(USACEP). The United States has made up to USD 6 billion available for the financing of this venture.
Under the auspices of USACEP, a new renewable and alternative power generation (RAPG) work stream
was established as part of the energy cooperation initiative of the EAS. The main aim of the RAPG work
stream is to encourage new renewable energy collaboration and cooperation in the EAS region. The RAPG
projects will coexist and complement current renewable energy activities within ASEAN and dialogue withpartners to elevate the role of renewable energy in the region. The project areas cover solar PV, wind andhydro (US DOE, 2013).

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REFERENCES

BGC (Brunei Gas Carriers) (2015), BGC—The Launching of Amadi, http://bgc.com.bn/press_release/thelaunching-of-amadi/.
BMC (Brunei Methanol Company) (2010), Brunei Methanol Company Marks a Historical Milestone with the
Inauguration of Brunei Darussalam’s Methanol Plant, 25 May 2010, http://bruneimethanol.com/news_details.php?id=38.
BP (British Petroleum) (2017), BP Statistical Review of World Energy June 2017,https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review2017/bp-statistical-review-of-world-energy-2017-full-report.pdf.
DES (Department of Electrical Services) (2013), Overview of the Department of Electrical Services,
http://www.des.gov.bn/SitePages/Overview.aspx.
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Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
EIDPMO (Energy and Industry Department, Prime Minister’s Office) (2014), Energy White Paper,
http://energy.gov.bn/Shared%20Documents/Publications/Energy%20White%20Paper%202014(1).pdf.
MOC (Ministry of Communications) (2014), Land Transport White Paper,
http://www.mincom.gov.bn/Documents/Land%20Transport%20White%20Paper/Land%20Transpo
rt%20White%20Paper%20for%20Brunei%20Darussalam%20-%20FINAL%20VERSION.pdf.
PB (PetroleumBRUNEI) (2013), International – Block EP-1, Myanmar, http://www.pb.com.bn/PB-businessesexploration-production.html.
UNFCCC (United Nations Framework for Climate Change and Convention) (2015), Brunei Darussalam’s
Intended Nationally Determined Contribution (INDC),
www4.unfccc.int/submissions/INDC/Published%20Documents/Brunei/1/Brunei%20Darussalam%2
0INDC_FINAL_30%20November%202015.pdf.
–– (2016), Brunei Darussalam’s Intended Nationally Determined Contribution (INDC),
http://unfccc.int/resource/docs/natc/brnnc1.pdf.
US DOE (US Department of Energy) (2013), U.S.–Asia Pacific Comprehensive Energy Partnership,www.energy.gov/articles/us-asia-pacific-comprehensive-energy-partnership.

26

APEC ENERGY OVERVIEW 2017

BRUNEI DARUSSALAM

USEFUL LINKS

Brunei Department of Economic Planning and Development—http://www.depd.gov.bn
Brunei Economic Development Board—www.bedb.com.bn
Brunei LNG Sdn Bhd—www.bruneilng.com/home.asp
Brunei Methanol Company Sdn Bhd - http://www.brunei-methanol.com/
Brunei Shell Petroleum Company Sdn Bhd—www.bsp.com.bn
Department of Electrical Services - http://www.des.gov.bn/Theme/Home.aspx
Energy and Industry Department, Prime Minister’s Office—www.ei.gov.bn
Ministry of Communications—http://www.mincom.gov.bn/Theme/Home.aspx
PetroleumBRUNEI—www.pb.com.bn

27

APEC ENERGY OVERVIEW 2017

CANADAC A N A DAI N T ROD U C T I ON

Canada is the world’s second largest country after Russia in terms of landmass. The Canada–US border is theworld’s longest international border and extends from the Pacific Ocean to the west, the Atlantic Ocean to theeast and the Arctic Ocean to the north. There are 10 provinces and 3 territories in Canada, with a total
population of 35.2 million (StatCan, 2016a). Most Canadians reside near the southern border. In 2015, Canada’s
gross domestic product (GDP) grew by 0.9% to USD 1 515 billion (2010 USD purchasing power parity [PPP])and GDP per capita grew by 0.1% to USD 42 273 (EGEDA, 2017).
Canada is the fourth largest energy producer in the APEC region and the fifth largest in the world after
China, the US, Russia and Saudi Arabia. The energy sector directly contributed 6.7% to Canada’s GDP in 2016
and indirectly contributed (through purchases of goods and services from non-energy industries) an additional
3.2% (NRCan, 2017a). In 2016, Canada exported CAD 86 billion worth of energy products and imported
CAD 40 billion (NRCan, 2017a). Canada is one of the world’s top four exporters of crude oil, natural gas,uranium and electricity (NRCan, 2016a).
The economy has extensive conventional and unconventional oil, natural gas and coal reserves as well as
significant uranium deposits. It has the world’s third-largest amount of proven oil reserves after Venezuela andSaudi Arabia. The reserves were estimated at 172 billion barrels, of which oil sands constituted 97% (166 billion
barrels) as of March 2017 (NRCan, 2016a). The bulk of the oil sands reserves are in the province of Alberta;
however, the province of Saskatchewan is also rich in bitumen reserves. Conventional oil reserves exist in most
Canadian provinces and territories, including Alberta, British Columbia, Saskatchewan, Ontario, Manitoba,
Nova Scotia, Newfoundland and Labrador, the Northwest Territories (NWT) and the Yukon. However,Alberta and Saskatchewan have the largest onshore reserves, while Newfoundland and Labrador has the largest
offshore reserves (NEB, 2016c).
Canada has substantial proven gas reserves, which are estimated at more than 76.7 trillion cubic feet (Tcf)
and equal to 1.2% of global reserves in 2015 (BP, 2017). The largest concentrations of gas reserves are inAlberta and British Columbia. Saskatchewan, Newfoundland and Labrador, New Brunswick, Nova Scotia, the
NWT and Yukon also have established reserves, although significantly smaller (NEB, 2016b).
Canada currently holds 8.7 billion tonnes of proven resources of coal-in-place, of which 6.6 billion tonnes
are recoverable. More than 90% of Canada’s coal deposits are located in the Western provinces, namely,
Alberta, British Columbia and Saskatchewan, while the rest is located in the eastern province of Nova Scotia(CAC, 2016).
Canada has the third-largest uranium resources in the world after Australia and Kazakhstan. As of 2015,
Canada’s uranium resources were estimated at 509 800 tonnes (WNA, 2017), most of which are located in the
Athabasca Basin of northern Saskatchewan. This basin has the world’s largest high-grade deposits (NRCan,2014). These resources are equal to 9% of the world’s known resources, which are recoverable at a price of
US$130 per kilogram. If the price of uranium were to increase in the future, additional uranium deposits would
become economically recoverable; therefore, Canada’s uranium reserves would increase.
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesc, d, eArea (million km2)

9.9

Oil (billion barrels)

172

Population (million)

36

Gas (trillion cubic feet)77

GDP (2010 USD billion PPP)

1 515

Coal (million tonnes)

6 600

GDP (2010 USD PPP per capita)

42 273

Uranium (kilotonnes U)

490

Sources: a EGEDA (2017); b StatCan (2015); c BP (2017); d CAC (2016); e NRCan (2014).

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APEC ENERGY OVERVIEW 2017

CANADAE N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Canada’s domestic energy production reached 471 330 kilotonne oil equivalent (ktoe) in 2015. This represented
an increase of 0.3% compared with that in 2014 (469 849 ktoe) (EGEDA, 2017). Fossil fuel dominated thisproduction at about 84%, with no major change compared with that in 2014. Oil, including natural gas liquids(NGL), constituted the largest share (226 233 ktoe, 48%), followed by gas (139 112 ktoe, 30%) and coal (30609 ktoe, 6.0%). The share of nuclear energy production was 5.6% (32 732 ktoe), thereby leaving a share of
approximately 10% for renewables. Renewables comprised hydro (32 732 ktoe, 6.9%); other renewables(bioenergy), including biomass, wood and waste (13 647 ktoe, 2.9%); and geothermal, solar, wind and ocean(2 566 ktoe, 0.5%) (EGEDA, 2017). Canada is a leading global producer of energy, as evident in its global
production ranks for gas (fifth), crude oil (fourth), hydro (second) and uranium (second) as of 2015 (NRCan,
2016a).
Canada is a net exporter of oil, gas, coal, uranium and electricity. The economy’s energy exports go mainly
to the US. From 2000 to 2015, energy exports grew at 4.6% per year. Exports accelerated in 2015 as seen in a
6.9% increase over 2014 (EGEDA, 2017). In 2015, Canada exported 284 423 ktoe of energy (excluding
uranium exports), which comprised crude oil and NGL (170 858 ktoe), petroleum products (22 686 ktoe), gas(65 988 ktoe), coal and coal products (18 418 ktoe), electricity (5 870 ktoe), and renewables (814 ktoe)(EGEDA, 2017). In 2015, energy exports constituted 18% (CAD 86 billion) of domestic merchandise export
revenue (NRCan, 2017a).
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

471 330 Industry sector

42 517 Total power generation

665 576

Net imports and others–199 174 Transport sector

61 384

Thermal

141 306

Total primary energy supply

270 192 Other sectors

68 207

Hydro

380 717Coal

18 418 Non-energy

21 316

Nuclear101 423

Oil

94 332 Final energy consumption

172 108

Others42 130Gas

87 026

Coal

2 457

Renewables

48 902

Oil

70 691Others

21 514

Gas

44 374

Renewables

10 547

Electricity and others

44 039Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
CRUDE OIL

Canada’s oil production has increased for the past two decades. In 2016, it was the world’s fourth-largest oil
producer. In 2015, Canada produced 226 233 ktoe of crude oil, including NGL. This was an increase of 2.9%
from 2014 (EGEDA, 2017). Oil sands production, which increased by 146% from 2005 to 2016, first surpassed
conventional production levels in 2010 and has long been the main driver of growth in Canadian production(CAPP, 2017a). Production from oil sands, which are mainly located in the Athabasca oilfields in Alberta, hasgrown consistently since it began in 1967. In 2016, its production reached 2.4 million barrels per day (Mbbl/D),

29

APEC ENERGY OVERVIEW 2017

CANADAan increase of 1.5% over that in 2015 (CAPP, 2017a). Conventional oil production in 2016 was 1.5 Mbbl/D,
a decrease of 2.6% from 2014 (CAPP, 2017a).
Although Canada’s crude oil and equivalent production is geographically dispersed, 94% of the
production came from Western Canada, of which 66% was from the oil sands in 2016. The bulk of Canadiancrude oil and equivalent production occurred in Alberta (74%), followed by Saskatchewan (12%), Manitoba(1.0%), British Columbia (0.6%) and the NWT (0.2%) (CAPP, 2017a). Offshore production in the Atlantic
Ocean (Hibernia, Terra Nova and White Rose) constituted 5.5%, except for small-scale production in Ontario(<0.1%) and the Atlantic provinces (<0.1%). Pentanes plus constituted 6.8% of total crude oil and equivalent
production (CAPP, 2017a).
In 2015, the economy’s oil exports, including NGL, (170 858 ktoe) increased over those in 2014 by 12.7%
and with a slight increase of 0.3% in petroleum products (22 686 ktoe) (EGEDA, 2017). The main market was
the US.
GAS

Canada holds large proven natural gas reserves. It is the world’s fifth-largest producer and fourth-largest
exporter of natural gas (NRCan, 2016a). In 2015, Canada’s natural gas production reached 139 112 ktoe, anincrease of 1.1% from 2014 (EGEDA, 2017). This increase in production extends the growth from 2013, whengas production began to ramp up again after a seven-year period of decline (IEA, 2017b). In terms of exports,
the volume of its gas exports was 65 988 ktoe, an increase of 1.0% compared with that in 2014 (EGEDA,
2017).
Western Canada constituted 99% of the economy’s gas production in 2016, including Alberta as thelargest producer (67%), British Columbia (30%) and Saskatchewan (1.6%) (CAPP, 2017b). Eastern Canada’s
gas production was mainly offshore in the Atlantic Ocean (1.2%). Gas production in Ontario has been
declining, representing 0.1% of the total gas production in 2016 (CAPP, 2017b).
Although conventional natural gas reserves are shrinking, technological advances and rapid investmentin the Western Canadian Sedimentary Basin have renewed the growth potential from shale gas, tight gas andcoal-bed methane. Shale gas is emerging as the new low-cost source of natural gas in North America, requiring
greater investment and research for its development. In Canada, shale gas resources are found in British
Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, New Brunswick and Nova Scotia. In 2015,
British Columbia continued to see most of its current drilling and production activities in the northeast in theMontney and Horn River shale basins, with unconventional gas constituting almost 80% of the total gas
production (NRCan, 2016b). Although Alberta’s production increased by 1.9% in 2016 over that in 2015, it
declined in all areas except the Upper Mannville, Duvernay and Montney formations (wet gas) and from shalewells (AER, 2017).
COAL

Annual coal production has experienced minor fluctuations since 2004 (BP, 2017). In 2015, Canada produced
30 609 ktoe of coal, a decrease of 13.5% from its 2014 production (EGEDA, 2017). All of Canada’s coalproduction in 2015 took place in Western Canada, including Alberta (43%), British Columbia (43%) and
Saskatchewan (14%) (NRCan, 2016a).
Canada is a mid-size coal producer. Approximately 45% of its annual production of 62 million tonnes(Mt) is metallurgical (coking coal). This is used in steel manufacturing and largely exported, while the other
55% is thermal coal, which is used domestically for electricity generation (CAC, 2017).
Canada exported 59% (18 206 ktoe) of its coal production in 2015, a 12% decline from its 2014 exports(EGEDA, 2017). Coking coal constituted 91% of the exports (EGEDA, 2017). In 2015, Canada exported
CAD 3.5 billion of coal, of which 72% went to Asia. The remainder was exported to a number of European
countries, the US, Latin America, the Middle East and Australia (ISEDC, 2017).
URANIUM

Canada is among the three leading producers of uranium, along with Kazakhstan and Australia. Collectively,
these three exporters constituted about 72% of total global output in 2016 (WNA, 2017). Canada maintained
its position as the world’s second-largest uranium producer in 2016. Canada produced 14 039 tonnes of30

APEC ENERGY OVERVIEW 2017

CANADAuranium metal (tU) in 2015 (WNA, 2017), constituting 22% of the global production (WNA, 2017). Canada’s
2015 uranium metal production increased by 46% from 2014 (WNA, 2017). Current production is entirely
from the Athabasca Basin of northern Saskatchewan (NRCan, 2014).
The mining and milling of uranium is a major industry (CAD 2 billion in 2015) (NRCan, 2016a). The twolargest-producing uranium mines in the world are both located in Canada; these are McArthur River (6 928tU) and Cigar Lake (6 666 tU), producing 22% of the total world output in 2016 (WNA, 2017).
RENEWABLE ENERGY

Canada is a world leader in the production and use of renewable energy. The economy has substantial
renewable energy resources, including bioenergy, hydro, solar, wind, geothermal and ocean energy. In 2015,
the economy’s total renewable production was 48 743 ktoe, consisting of hydro (32 732 ktoe); bioenergy andwaste (13 445 ktoe); and solar, geothermal, wind and ocean (2 566 ktoe) (EGEDA, 2017). Production was
2.4% below the 2014 level (EGEDA, 2017). Renewables constituted almost 11% of the total indigenous energy
production in 2015 (EGEDA, 2017).
Hydro is the most important source of renewable energy in Canada, supplying 57% of Canada’s electricity
generation in 2015 (EGEDA, 2017). In 2016, Canada’s installed hydraulic capacity was over 80 859 MW(StatCan, 2017). The installed small capacity was approximately 4 131 MW in 2016 (NRCan, 2017b).
Canada has access to large and diversified biomass resources for energy production owing to its large
landmass covered with active forests and utilised by agricultural industries. In 2015, bioenergy was the second
most important form of renewable energy, with biofuels and renewable waste representing 5.0% of Canada’s
total primary energy supply (EGEDA, 2017).
Canada had 70 bioenergy power plants, with a total installed capacity of 2 475 MW in 2016 (NRCan,
2017b). Most of this capacity is built around the use of wood biomass, spent pulping liquor and landfill gas.
Biofuel is also a growing form of bioenergy in Canada and constituted 2% of the world’s biofuel (ethanol andbiodiesel) production in 2014, making Canada the fifth-largest producer after the US, Brazil, the European
Union and China (NRCan, 2017b). The federal government, alongside the provinces, has introduced
regulations on renewable content to increase future production and the use of biofuels.
Wind is also an important renewable energy source whose provincial leaders are Ontario, Québec andAlberta (NRCan, 2016a). However, other provinces with wind potential are increasing the share of wind energy
in their power mix. Prince Edward Island (PEI) is a major electricity importer from New Brunswick, whichuses coal and nuclear, among others. PEI’s indigenous electricity generation is almost entirely wind, but thisaccounts for only 17% of its consumption (NRCan, 2015b).
Canada has vast areas with significant potential for wind resources to make the expansion of windgenerated power economical. Installed wind power capacity has expanded rapidly in recent years and isestimated to grow at a rapid pace given that the government initiatives are in place and support its growth. In
2016, Canada had nearly 6 100 wind turbines in operation in 283 wind farms, with a total installed capacity of
11 973 MW. In 2017, Canada added 10 projects that increased capacity by 341 MW to reach 12 239 MW ofwind energy capacity (CanWEA, 2018).
Solar energy has also experienced continuous growth both in thermal and photovoltaic (PV) power.
Cumulative PV power capacity grew to 2 662 MW in 2016 (IEA, 2017a). Ontario was the leading province interms of solar capacity (99% of total installed capacity) (IEA, 2017a). Offgrid capacities were not reported in2013 but were estimated at approximately 1% of the total installed capacity (IEA, 2017a). Other Canadianprovinces, including British Columbia, Alberta and Saskatchewan, were also expanding their solar capacity in2016.
Canada has access to a significant energy source in the form of ocean waves and tides because of its
proximity to the Atlantic and Pacific oceans. The province of Nova Scotia has one of the world’s few tidal
power plants, generating 20 MW of electricity, and an in-tidal technology demonstration project. Roughly, 13
MW of tidal current capacity is expected to be installed in the Bay of Fundy, Nova Scotia in the upcoming
years (NRCan, 2017a).

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APEC ENERGY OVERVIEW 2017

CANADA

Geothermal power has not experienced the momentum of solar, wind and biomass. A number of heatand power generation projects are being considered in Alberta, British Columbia, Saskatchewan, the NWT and
the Yukon where the highest temperature geothermal resources are located. Demonstration projects are under
way in Western Canada, with commission planned in the 2020 timeframe. In 2010, there were over 95 000
ground-source heat pumps with an installed capacity of about 1 045 MW of thermal energy (NRCan, 2017b).
NRCan has financially supported the demonstration projects in British Columbia, the NWT, the Yukon andAlberta.
FINAL ENERGY CONSUMPTION

Canada’s final energy consumption in 2015 reached 172 108 ktoe, a decrease of 1.9% from that in 2014
(EGEDA, 2017). This makes Canada the fifth largest energy consumer in APEC after China; the US; Russia;
and Japan (EGEDA, 2017).
A combination of smaller sectors, including residential, commercial and public services, together with
agriculture and non-specified others, constituted the largest share of total final consumption (68 207 ktoe,35%), followed by the transport sector (61 384 ktoe, 32%), and the industrial sector (42 517 ktoe, 22%)
(EGEDA, 2017). Non-energy (fuels used as raw materials and not consumed as fuel or transformed intoanother fuel), which is excluded from final energy consumption, was 21 316 ktoe in 2015 (EGEDA, 2017).
Fossil fuels constituted the largest share in final energy consumption (68%), comprising petroleum
products (70 691 ktoe, 41%), gas (44 374 ktoe, 26%) and coal and coal products (2 457 ktoe, 1.4%) in 2015
(EGEDA, 2017). The remainder was the share of renewables (10 547 ktoe, 6.1%) and electricity and others(44 039 ktoe, 26%), of which the share of renewable electricity and others was 27 564 ktoe (EGEDA, 2017).
Factors contributing to Canada’s higher consumption of energy relative to that of other industrialised countries
include its cold climate, long periods of heating, long distances between major cities, extensive use of private
vehicles and the prevalence of energy-intensive industries.
POWER GENERATION

Canada generated 665 576 gigawatt-hours (GWh) of electricity in 2015, a decrease of 0.4% from the previous
year (EGEDA, 2017). Renewables constituted the largest share of this generation (63%), with hydro as the
major contributor (57%). Other renewables included solar, wind and geothermal. The share of nuclear was
15%, which increased the combined share of non-emitting power generation to 79%. The share of oil, gas andnatural gas-fuelled thermal generators was 21% (EGEDA, 2017). Coal constituted the largest share of the latter(46%), followed by coal (45%) and other fossil fuels such as diesel, light fuel oil, heavy fuel, wood and spent
pulping liquor (8.9%) (StatCan, 2017).
Canada has been increasing the share of renewables, including hydroelectricity, for electricity generation
since 2000. For example, some provinces have introduced policies and programs to promote renewable energy
while discouraging the continued use of coal-fired power plants. In 2013 and early 2014, Ontario, Canada’s
largest energy consumer, shut down its remaining coal-fired power plants (NEB, 2015).
In November 2015, Alberta also announced a new policy to accelerate the 2012 federal plan to phase out
coal-fired power generation. Alberta’s plan will result in the retirement of six coal-fired electricity plants ortheir conversion to natural gas by 2030; the original federal schedule would have allowed the plants to retire
according to a pre-determined schedule ranging from 2036 to 2061 based on the end of useful life
(approximately 50 years) (Alberta Energy, 2015; Canada Gazette, 2012). The decision was announced alongwith a comprehensive climate change plan discussed in more detail below under ‘Climate Change’.
In 2016, the federal government additionally announced its plan to accelerate the phase out of coal-fired
electricity generation in Canada by 2030. Flexibility in achieving this goal will be allowed through thenegotiation of equivalency agreements with the provinces (GOC, 2017). For example, an agreement-inprinciple was reached with the federal government that will allow Nova Scotia to burn some coal after thedeadline during periods of high demand in exchange for deeper sectoral reductions elsewhere in the economy(PNS, 2016).
As part of the 2013 Long-Term Energy Plan, Ontario intends for nuclear to continue to be a major
source for the province’s electricity supply. To this end, the province has announced a CAD 25 billion
investment into the refurbishment of 10 nuclear reactors: four at the Darlington Nuclear Generating Station

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APEC ENERGY OVERVIEW 2017

CANADAand six at the Bruce Nuclear Generating Station. These refurbishments will add about 25–30 years to theoperational life of each unit. Refurbishment at Darlington began in October 2016 with one reactor, with workon the second reactor beginning in 2017 (PO, 2016a; OPG, 2017). Refurbishment at Bruce is expected to startin 2020. This investment will annually displace 31 to 52 Mt of greenhouse gas (GHG) emissions relative tocoal- or gas-fired electricity.
Low natural gas prices, the rapidly decreasing cost of renewable energy and new regulations that limit theuse of coal have all made Canada’s electricity sector increasingly ‘greener’ (NEB, 2015). Canada is the APEC
region’s and the world’s second-largest hydroelectricity producer after China (IEA, 2017b). Canada’s rich water
resources enable many parts of the economy to rely on hydropower.
The electricity networks of Canada and the US are highly integrated, and the US is a net importer ofelectricity from its northern neighbour. In 2015, Canada exported 5 870 ktoe of electricity to the US while
importing 750 ktoe (EGEDA, 2017). This makes Canada APEC’s largest exporter of electricity and the world’s
second-largest exporter of electricity after Germany (IEA, 2017b).
The bulk of the electricity trade with the US occurs among the provinces of Québec, Ontario, Manitoba
and British Columbia with their neighbouring American states (NEB, 2017). The Site C Clean Energy Project(C$10.7 billion) in British Columbia is expected to provide 1 100 MW of clean electricity capacity andproducing about 5 100 gigawatt hours of electricity each year. New capacity additions and low domestic
electricity demand resulted in record-high Canadian net exports, reaching 73 terawatt-hours (TWh) in 2016
(NEB, 2017). In 2015, the National Energy Board (NEB) received the first application for a new international
power line (IPL) since 2005, the ITC Lake Erie Connector from Ontario to Pennsylvania (NEB, 2016b).
According to public sources, four additional IPLs are under consideration, with three located in Québec andone in Manitoba (NEB, 2016b). In 2018, it was announced that Hydro Québec had been successful in its bid
to deliver 1 900 MW of hydropower to the New England grid via the proposed Northern Pass Transmission
Line (HQ, 2018).
E N E RG Y I N T E N S I T Y A NA LY S I S

A number of factors contribute to the energy intensiveness of Canada’s economy. These factors include its
vast geography, cold climate and an industrial structure with a high rate of energy-intensive industries. The
economy’s abundant fossil energy reserves and renewable capacity (particularly hydro) at relatively low costs
also play a role.
Nevertheless, Canada has been successful in gradually reducing its energy intensity over the past few
decades. Primary energy intensity and final energy consumption intensity fell by 4.0% and 2.8% from 2014,
respectively (EGEDA, 2016). This was mainly because of a significant decrease in the energy intensity of theindustrial (pulp and paper, mining and quarrying, and construction), transport (road and rail) and residential
sectors, which registered the largest sub-sectoral reductions in their energy intensity compared with that in2014. Canada experienced a decline in GDP in the first half of 2015, contributing to the decline in energy use
because of job losses and production curtailments in the natural resource sectors (NEB, 2016a). Increasingenergy efficiency and reducing energy intensity have been policy goals for the Canadian Government as ameans to mitigate climate change and conserve energy.
Table 3: Energy intensity analysis, 2015
EnergyEnergy intensity (toe/million USD)
2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

186

178

–4.0

Total final consumption

131

128

–2.4

Final energy consumption excl. non-energy

117

114

–2.8

Source: EGEDA (2017).

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APEC ENERGY OVERVIEW 2017

CANADA

RENEWABLE ENERGY SHARE ANALYSISThe share of modern renewables in final energy consumption remained flat in 2015 at 20.4% because bothmodern renewables and final energy consumption declined proportionately year-over-year. Use of traditional
biomass also remained flat, while modern biomass declined by 5.4% from 2014 to 2015 (EGEDA, 2017).
Table 4: Renewable energy share analysis, 2014 vs 2015

175 475

172 108

Change (%)
2014 vs 2015
–1.9

136 746

133 997–2.0

Traditional biomass

3 001

3 001

0

Modern renewables

35 72935 110

–1.7

20.36

20.40

0.2

2014
Final energy consumption (ktoe)
Non-renewables (Fossils and others)

Share of modern renewables to final energy
consumption (%)

2015

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD).. All other renewables (hydro, geothermal and so on) including biogas and wood pellets are
considered modern renewables, although data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKCanada’s federal government and those of its 10 provinces and 3 territories all have a role in shaping the
economy’s energy policy. The fundamental principles include respect for jurisdictional power granted under
the Constitution Act of 1867 and targeted intervention in the market process to achieve specific policy
objectives (for example, pipeline regulation) through regulation and other means (GOC, 1867; NEB, 2015).
The Canadian provinces are the owners of ground resources and mineral rights within provincial
boundaries, excluding the resources located in aboriginal lands and frontier lands (that is, national parks andinternational waters) in accordance with sections 91 and 92 of the Canadian Constitution (GOC, 1985a; NEB,2015). The provincial governments have the primary responsibility for shaping policies in their jurisdictions;consequently, energy policy varies from jurisdiction to jurisdiction. Unlike the provinces, the three territories
do not own the ground resources but share partial management responsibility. In addition to frontier lands,
the federal government is responsible for regulating uranium mining and nuclear energy,
interprovincial/international trade and commerce, trans-boundary environmental impacts and interprovincial
work (for example, pipelines) as well as developing policies in the national interest (economic development,
health and safety and energy security) (GOC, 1985b; NEB, 2015).
Energy policy at the federal level involves a number of government agencies that are responsible fordevelopment and implementation. Natural Resources Canada (NRCan) is the federal department that is
mandated to ‘ensure that Canada’s resource sector remains a source of jobs, prosperity, and opportunity within
the context of a world that increasingly values sustainable practices and low carbon process’(PMO, 2015). The
NEB is an independent federal regulator responsible for pipelines, energy development and trade issues in the
Canadian public interest. The Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) is the independent
joint agency of the governments of Canada and Nova Scotia and regulates petroleum activities in the Nova
Scotia Offshore Area (CNSOPB, 2018). The Canadian Nuclear Safety Commission (CNSC) regulates the useof nuclear energy and materials to protect health, safety, security and the environment and implements
Canada’s international commitments on the peaceful use of nuclear energy. Other important government

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APEC ENERGY OVERVIEW 2017

CANADA

organisations include Environment and Climate Change Canada, Fisheries and Oceans Canada, Indigenous
and Northern Affairs Canada and Global Affairs Canada.
ELECTRICITY MARKETS

Federal and non-federal actors have distinct roles in the Canadian electricity market. The federal governmentis responsible for electricity exports, international and designated interprovincial power lines and nuclear
policy, including regulation and safety. These issues are especially important because the Canadian market isinterconnected at many points with the US, forming a larger grid (NEB, 2018). The provinces and territories
have jurisdiction over the generation, transmission and distribution of electricity within their boundaries. Suchjurisdiction also encompasses restructuring initiatives and electricity prices (NEB, 2018).
The electricity industry in most provinces is highly integrated. The bulk of generation, transmission anddistribution services are provided by one or two dominant utility providers. Some of them are privately owned,
while many are Crown corporations owned by the provincial governments. Exceptions exist in the provincesof Alberta, which has moved to full wholesale and retail competition, and Ontario, which has established ahybrid system with competitive and regulated elements.
In November 2016, Alberta announced the addition of a capacity market to co-exist with the current
energy-only market. The Alberta Electricity System Operator (AESO) had recommended the implementationof a capacity market to provide greater revenue certainty for generators, thereby encouraging investment in
new generation capacity while maintaining the competitive market structure used to set wholesale prices(AESO, 2018). A capacity market will serve to support the recommendations of the Climate Leadership Plan
as the province moves to phase out coal-fired generation by 2030 and increase the penetration of renewablegeneration in the electricity mix. The AESO will be responsible for designing and implementing the capacity
market. This process began with stakeholder engagement and market design in 2017, and will be followed by
the first round of procurement in 2019 with contracts awarded by 2020–21 (AESO, 2018).
Retail electricity prices vary across the provinces in terms of their levels and the mechanisms by which
they are set. Provinces with an abundant supply of hydroelectricity generally have the lowest prices. In mostprovinces, the regulator sets the prices according to a formula that determines the cost of service (COS) plus
a reasonable rate of return. There are two exceptions: in Alberta, retail electricity prices are derived from acompetitive wholesale market; in Ontario, retail prices are set by a combination of market spot prices and a
dynamic price component (global adjustment) set to cover the costs of guaranteed rates to generators (NRCan,
2016f). Transmission and distribution rates across all provinces generally follow the COS operating model
described above and are passed on to customers based on fixed and variable components.
ENERGY MARKETOIL AND NATURAL GAS

Canada’s wellhead oil and natural gas prices have been fully deregulated since the conclusion of the Western
Accord and the Agreement on Natural Gas Markets and Prices between the Canadian federal government andthe Canadian energy-producing provinces in 1985. The latter opened up the oil and gas markets to greater
competition by permitting more exports, allowing users to buy directly from producers and unbundling
production and marketing from transportation services (NEB, 1996). Oil and gas pipeline networks continue
to be regulated as natural monopolies.
The fiscal regime applied to the Canadian oil and gas industry comprises a combination of corporate
income taxes and royalty payments. As of 2016, the following general corporate income tax rates applied to
the key oil and gas regions.

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Table 4: Corporate income tax rates, 2017
CIT rates

BritishColumbia

Alberta

Saskatchewan

Newfoundlandand Labrador

Nova Scotia

Federal

15%

15%

15%

15%

15%

Provincial

11%

12%

12%

15%

16%

Total

26%

27%

27%

30%

31%

Sources: Crisan and Mintz (2016).

Canada does not allow corporations to file consolidated tax returns; each corporation must compute andpay taxes on a separate legal entity basis. Non-capital losses (business losses) can be carried back 3 years andcarried forward 20 years. Capital gains are subject to tax at one-half the capital gain (taxable capital gain) at
regular income tax rates. Capital losses are exclusively deductible against capital gains and can be carried backthree years and forward indefinitely or until the company is acquired. Non-capital losses can be deductedagainst taxable capital gains (EY, 2017).
Royalty regimes (or rent-based taxes) are set by the owner of the resource, typically the applicableprovince, but a small percentage has petroleum rights owned by surface owners (freehold land) or First
Nations. The resource owner leases the land to potential developers in exchange for a fee (land sale) and royalty
agreement. Parcels of crown land are auctioned off to the highest bidder for a fixed period, often with clauses
tied to maintaining an active interest in the parcel (that is, drilling or production). Royalty regimes vary bothby province and by commodity and are typically paid based on a combination of well productivity and wellhead
price (EY, 2017). Royalties paid are deductible for tax purposes.
Table 5 describes the basic structure of royalty regimes across Canada, as published in a report by Chen
& Mintz (2012) and updated to reflect recent changes to existing structures in the report by Crisan & Mintz(2016), both of which were published through the University of Calgary, School of Public Policy.
Table 5: Summary of regional royalty regimes, 2017
Province

Royalty

Rent-based tax

BritishColumbia

For conventional oil and gas, the royalty is based ongross revenue. The royalty rate differs first by productcategory, such as density of oil or type of gas (that is,conservation vs. non-conservation gas) and by wellage (except for heavy oil and conservation gas).
Formulation of the royalty rate for a given productcategory differs between oil and gas. For oil, theroyalty rate is sensitive mainly to productivity; for gas,
it is sensitive only to price. For certain high-cost shalegas projects, there is a pre-payout of 2% royalty on
gross revenue (refer to next column).

For certain high-cost shale gas projects, a
newly introduced net profit royalty
program with four tiers of royalty rates
applies: a pre-payout of 2% royalty on
gross revenue and three post-payout tiers
associated with a royalty that is thegreater than 5% of gross revenue and ahigher rate of net revenue (that is, 15%,
20% or 35%, depending on the tierorder). To reach each of the three tiers of
net royalty, a progressive return
allowance applies.

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Province

Royalty

Rent-based tax

Alberta

For conventional oil and gas, under the new regime,
the royalty rate on sales will remain price-sensitive but
unrelated to volume until a threshold is reached(royalty rates decline when production drops below
194 cubic metres per month or approximately 40
barrels per day). A cost recovery allowance, sensitive
to well depth but otherwise based on industry
experience, will be provided instead of various drillingincentives. The new system includes a consolidationof royalty rates for fuel types produced from a well, as
well as a 5% minimum royalty on sales until the costallowance is used up. Further, the government has alsoannounced two new programs—the Enhanced
Hydrocarbon Recovery Program and the Emerging
Resources Program—that will provide an allowancefor eligible costs with a corresponding royalty rate of
5%. Once the cost allowance is depleted, the newroyalty rates will apply.

For oil sands only, in addition to a prepayout gross royalty, there is a net royalty
of 25–40% after payout depending on
the price level of the oil. The regime
remained unchanged after a review in2015.

Saskatchewan

The crown royalty and the freehold production tax(FPT) on oil and gas are determined using formulas
containing parameters that are adjusted monthly by
the government. Both royalty and FPT are sensitive to
price and well productivity and differ by product interms of their vintage and characteristics (for example,
type of product, well and location). The FPT is lower
than the crown royalty by a production tax factor(PTF), which varies by the type of product and ranges
from 6.9–12.5%.

None.

Newfoundlandand Labrador

The province introduced a new, generic offshore-oil
royalty regime in November 2015 based on the Rfactor approach (revenue over accumulated costindex). The system includes a basic royalty rate ranging
from 1.0–7.5% applied to gross revenue as the project
starts producing oil, increasing as the project recovers
more of its costs. After costs have been recovered, a
net royalty ranging from 10–50% will be applied to net
revenue varying by the R-factor, and the basic royalty
becomes a credit against net royalties.

A two-tier net royalty (20% and 10%),along with a two-tier return allowance,
applies after payout. Tier 1 net royalty
applies after all the project costs and thebasic gross royalty and the compounded
Tier 1 return allowances are exhausted.
Tier 2 royalty becomes payable after the
payout of both gross royalty and Tier 1
net royalty along with the Tier 2 return
allowance. The return allowance is 5%
above LTBR for Tier 1 and 15% above
LTBR for Tier 2.

The revenue-based or gross royalty is two-tiered: 2%
before payout and 5% after payout. It is deductible forcalculating the base for the net-revenue royalty. Notethat regardless of the revenue and profit level reached,
the 2% gross royalty applies for a minimum of 24months, and the 5% gross royalty applies for aminimum of 36 months. This implies that there is no
net royalty or rent tax payable for the first five years
after the commencement of production.

The two-tier net royalty rate is 20% and30%, depending on the net-revenue tierreached. Even after the net royalties
become payable, only the greater rate of
the 5% of gross revenue and 20% or 35%of the net revenue is payable. To reacheach of the two tiers of the net royalty
scheme, a progressive return allowance
applies: 20% above LTBR for Tier 1 and
45% above LTBR for Tier 2.

(Updated)(Updated)

Nova Scotia

Sources: Chen & Mintz (2012); Crisan & Mintz (2016).

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Canada has three expenditure pools that are particularly relevant to the oil and gas sector.


Oil and gas rights expenditures are accumulated in a pool called a Canadian Oil and Gas Property
Expense (COGPE), which are deductible at up to 10% on a declining balance bases.

Drilling and completion expenditures are accumulated in a pool called Canadian Development
Expense (CDE), which are deductible at up to 30% per year on a declining balance basis.



Exploration expenditures are accumulated in a pool called Canadian Exploration Expense (CEE) –immediately deductible in the year incurred.

Although Canada does not currently export LNG, an LNG tax was conceptualised and enacted in British
Columbia, which went into effect on 1 January 2017. It involves profits from an LNG source applied only toa ring-fenced set of activities from the input of feed gas to a sale from the British Columbia Coast (EY, 2017).
The tax is two-tiered: a Tier 1 tax of 1.5% applies to an LNG operator’s net operating income, and a Tier 2 tax
of 3.5% applies to net income. The Tier 1 tax is creditable against the Tier 2 tax such that the maximum
aggregate tax payable is the Tier 2 rate. This tax is not deductible under federal or provincial income tax
legislation (EY, 2017). In addition, a natural gas income tax credit, 3% of natural gas purchased for operations,
was introduced to reduce the corporate income tax (CIT) in British Columbia (EY, 2017).
Indirectly, the energy sector is subject to general, provincial and harmonised sales taxes as well as climate
related policies such as carbon taxes or cap-and-trade systems. However, businesses paying GST/HST are
eligible to receive input tax credits (ITCs) to the extent that purchases are for consumption, use or supply incommercial activities. Climate policies will be discussed in more detail in the ‘Climate Change’ section.
COAL

Canada is rich in coal resources. The largest known reserves are located in the Western provinces, which arealso Canada’s principal producers. Together with provincial-level law and regulations, 35 federal acts andregulations relate to the mining industry (CAC, 2016).
Among the many existing guidelines, a regulation adopted in August 2012 places a performance standard
on new coal-fired electricity. This should further reduce coal consumption in Canada but not necessarily coalproduction. The regulation, adopted under the Canadian Environmental Protection Act 1999 (GOC, 1999), isa performance standard that sets an emission intensity level equivalent to natural gas combined cycle (NGCC)
technology, a high-efficiency type of natural gas generation, at 420 tonnes per GWh (GOC, 2012). It also
contains a caveat to encourage new technology for the reduction of GHG emissions whereby units thatincorporate carbon capture and storage (CCS) technology can apply to receive a temporary exemption fromthe performance standard until 31 December 2024 (GOC, 2012).
Canada—jointly with the United Kingdom—launched the Powering Past Coal Alliance in November
2017 on the margins of the United Nations Climate Change Conference in Bonn, Germany (COP23). The
Alliance brings together a range of government, business and non-government partners committed toachieving the sustainable phase out of traditional coal power.
ENERGY EFFICIENCY

The federal and provincial governments have joint responsibility for energy efficiency, but their roles andresponsibilities vary and target different aspects. Each province has ministries responsible for administering
energy and environmental policies and programs, including energy efficiency programs. Examples of energy
efficiency programs include energy-efficient building codes, equipment standards and consumer rebates. The
foundation of all provincial policies rests upon the federal Energy Efficiency Act 1992, which was amended in2009 to expand its scope and effectiveness (GOC, 1992). This act provides for the creation and enforcementof regulations on the energy efficiency of products and supports the replacement of the least efficient productswith high-efficiency, cost-effective ones.
NRCan through its Office of Energy Efficiency (OEE) administers the Energy Efficiency Act 1992 andrelated efficiency issues at the federal level. The aim is to improve the utilisation of energy by ‘leading Canadiansto [improve] energy efficiency at home, at work and on the road’ (NRCan, 2016c).

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Since 2011, the federal government has committed CAD 3 million to support alternative fuels used in
the transport sector (NRCan, 2015c). Federally, an additional CAD 1.5 billion of funding was available for theperiod 2008–17 to support the production of renewable alternatives to gasoline and diesel for the developmentof a competitive domestic industry (NRCan, 2015c).
Additionally, the Federal Buildings Initiative (FBI) is a Natural Resources Canada initiative. It was
implemented in 1991 and aimed at assisting federal departments and agencies to reduce the energy
consumption and GHG emissions of their facilities (NRCan, 2015d). This voluntary program provides
knowledge, training and expertise that helps custodial departments through the process of undertaking energy
efficiency retrofit projects in their buildings and assists them to plan for an energy performance contract thatallows major retrofits to be self-financing. No upfront capital funds are required as future energy savings pay
for the investment. As of 2015, over 80 retrofit projects attracted hundreds of millions of dollars in private
sector investments. These projects have resulted in an impressive 15% to 20% energy savings on average.
Annual savings of CAD 44 million have been reinvested into programs for Canadians while reducing theimpact of government operations on the environment (NRCan, 2015d).
CLEAN ENERGY RESEARCH AND DEVELOPMENTThe Government of Canada is taking a comprehensive approach to clean energy research, development, anddemonstration (RD&D). Budget 2017 funded seven program streams, which focused in whole or in part on
clean technology innovation. Actions on clean energy innovation support the Pan-Canadian Framework on
Clean Growth and Climate Change, which includes Clean Technology, Innovation, and Jobs as one of fourpillars.
As the federal lead on clean energy innovation, Natural Resources Canada (NRCan) funds and performs clean
energy research, development, and demonstration. Public research and development on clean energy
technologies is led by the CanmetENERGY and CanmetMATERIALS federal laboratories. Theselaboratories are located across Canada, and undertake RD&D that reflects Canada’s geographic and industrial
strengths.
NRCan also funds industry-led RD&D to advance emerging technologies across the energy sector. Programs
such as the Energy Innovation Program and the Green Infrastructure programs support innovations in clean
electricity, low carbon transportation, energy efficient buildings, and industry. NRCan’s Clean Growth
Program will support clean technology RD&D in natural resource operations. These innovation programs
target innovations that can reduce environmental impacts, while enhancing competitiveness and creating jobs.
Other federal organizations, including the Natural Sciences and Engineering Research Council (NSERC) andSustainable Development Technology Canada (SDTC) also contribute to advancing clean energy innovationin Canada.
The federal government is also implementing cross-cutting measures to enhance Canada’s clean energy
innovation ecosystem. These include the Clean Growth Hub, an interdepartmental effort to streamline client
services, improve program coordination, and track outcomes. Further, NRCan is implementing the Clean
Technology stream of the Impact Canada Initiative to pilot new, outcomes-focused programs, such as prizebased challenges. This program will leverage experimentation and rigorous evaluation to pilot innovative
approaches and scale ‘what works’.
Federal investments are complemented by greater alignment with partners at the provincial, territorial, andinternational levels. For example, through the Clean Growth Program, the Government of Canada is forming‘Trusted Partnerships’ with provincial and territorial funding bodies to pool resources, share risks, andstreamline delivery. Through international initiatives such as Mission Innovation, Canada is collaborating with
global partners to accelerate clean energy innovation.
NUCLEAR POWER

Nuclear energy is an important component of Canada’s energy mix. In 2015, nuclear energy accounted for
15% of its electricity generation (EGEDA, 2017). Canadian nuclear power generation is concentrated in theprovinces of Ontario (18 reactors) and New Brunswick (one reactor). In 2012, Gentilly 2, Québec’s only
nuclear plant, was permanently shut down and put in a safe storage state following the decision of the provincial

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APEC ENERGY OVERVIEW 2017

CANADAenergy utility provider, Hydro-Québec, to discontinue refurbishment because of the high cost (CNA, 2014).
Hydro-Québec is now proceeding with a 50-year decommissioning plan.
Nuclear energy falls within federal jurisdiction, unlike other energy sources. The federal government is
responsible for all regulation of nuclear materials and activities along with supporting R&D. Concerned with
the impact of nuclear activities on health, safety, security and the environment, the federal government has put
in place a comprehensive nuclear legislation framework. The latter comprises the Nuclear Safety and Control
Act 1997, Nuclear Energy Act 1985, Nuclear Fuel Waste Act 2002 and Nuclear Liability Act 1985 1 (NRCan,2017c). They provide the framework for developing nuclear energy in Canada.
The federal government is the central body that regulates nuclear energy. However, the decision to invest
in nuclear power plants for electricity generation rests with the provinces (in concert with relevant provincial
energy utilities) (NRCan, 2017c). Although there are currently no projects to build new nuclear power plants,
nuclear energy remains an option for certain provinces in light of Canada’s commitment to phase out coalfired power plants and through the development of new technologies, such as small modular reactors. In
addition, investments of CAD 26 billion will be made for the refurbishment of 10 nuclear reactors in Ontario:
four at the Darlington Nuclear Generating Station and six at the Bruce Nuclear Generating Station. These
refurbishments will add about 25–30 years to the operational life of each unit. Refurbishment at Darlingtonbegan in 2016 with one reactor, and commitments on subsequent reactors will consider the cost and timing ofpreceding refurbishments, with appropriate off-ramps in place. Refurbishment at Bruce is scheduled to startin 2020.
CLIMATE CHANGE

Canada is fully committed to address climate change in a meaningful manner while ensuring thecompetitiveness of its economy (GOC, 2018a). Climate change is a complex issue making Canada’s approach
multifaceted and layered at the provincial, federal and international levels. Canada’s international commitments
support and drive action at the federal and provincial levels. Canada is a signatory to the United Nations
Framework Convention on Climate Change (UNFCCC) and has also committed to fulfilling the GHG
reduction target stemming from the Twenty-First Conference of the Parties (COP21) in December 2015 (theParis Agreement).
Section 91 of the Constitution Act, 1867 gives the federal government the authority to make laws on abroad range of issues. Section 92 sets out the issues for which the provinces may make laws. The environment
is not explicitly listed in either section. As a result, there is often overlap and uncertainty in terms of which thelevel of government is responsible for various aspects of the environment. Based on a number of Supreme
Court of Canada decisions, protection of the environment is recognised as a matter of shared jurisdiction
between the Parliament and provincial legislatures.
Since 2015, Canada has seen significant changes to its climate policy, most notably with the Pan-Canadian
Framework on Clean Growth and Climate Change (the Pan-Canadian Framework), which was collaboratively
developed by federal, provincial and territorial governments and with input from Canadians, including
businesses, non-governmental organisations and Indigenous Peoples.
PAN-CANADIAN FRAMEWORK ON CLEAN GROWTH AND CLIMATE CHANGE

As a first step towards implementing the commitments Canada made under the Paris Agreement, First
Ministers released the Vancouver Declaration on Clean Growth and Climate Change on 3 March 2016.
Through the Vancouver Declaration, working groups were established to develop options for pricing carbon
pollution; complementary actions to reduce emissions; adaptation and climate resilience; and clean technology,
innovation and jobs (GOC, 2016).
As a result of these efforts, the Pan-Canadian Framework was adopted by First Ministers on 9 December
2016. It is a comprehensive plan to reduce emissions across all sectors of the economy, accelerate clean
1 The Nuclear Liability and Compensation Act (NLCA), which entered into force on 1 January 2017, repealed and replaced the previous

Nuclear Liability Act of 1985. The NLCA provides stronger legislation in order to deal more effectively with liability for a nuclear accident
within Canada and allows Canada to join the International Atomic Energy Agency (IAEA) Convention on Supplementary Compensation
for Nuclear Damage. The NLCA increases the operator’s liability limit from CAD 75 million under the previous Nuclear Liability Act to
CAD 1 billion, an amount to be phased in from CAD 650 million in 2017 to CAD 1 billion in 2020.

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APEC ENERGY OVERVIEW 2017

CANADAeconomic growth and build resilience to the impacts of climate change (GOC, 2016). The actions outlined in
the Pan-Canadian Framework will contribute to Canada’s goal of reducing emissions to at least 30% below the2005 levels by 2030.
The Pan-Canadian Framework builds on the leadership of provinces and territories and the diverse arrayof policies and measures already in place across Canada to reduce GHG emissions in all sectors of the economy.
Pricing carbon pollution is central to Canada’s climate plan. The Government of Canada has outlined abenchmark for pricing carbon pollution that will build on existing provincial systems and expand carbon
pricing across Canada in 2018. Provinces and territories may choose to implement a price-based system or a
cap-and-trade system. Jurisdictions with a price-based system should have a minimum price of CAD 10 per
tonne in 2018, rising to CAD 50 per tonne by 2022. Provinces with cap-and-trade systems must have (i) a 2030
emission-reduction target greater than or equal to Canada’s 30% reduction target and (ii) declining (morestringent) annual caps to at least 2022 that correspond, at a minimum, to the projected emission reductions
resulting from the carbon price that year in price-based systems. Revenue generated by carbon pricing willremain in the jurisdiction of origin. The federal government plans to introduce new legislation and regulations
to implement a carbon pollution pricing system—the backstop—to be applied in jurisdictions that do not havecarbon pricing systems that align with the benchmark (GOC, 2016).
The Pan-Canadian Framework includes commitment for a review of the overall approach to pricing
carbon by early 2022 to confirm the path forward. An interim report will be completed in 2020. As an earlydeliverable, the review will assess approaches and best practices to address the competitiveness of emissionsintensive, trade-exposed sectors (GOC, 2016).
In addition to carbon pricing, complementary mitigation measures are included in the framework.
Expanding the use of clean electricity and low-carbon fuels, as well as increasing energy efficiency, arefoundational actions that will reduce emissions across the economy.
To increase the use of low-carbon fuels, the federal government, working with provincial and territorial
governments, industry and other stakeholders, will develop a clean fuel standard to reduce emissions fromfuels used in transportation, buildings and industry.
Using a mix of regulations and investments, Canada will also continue to drive down emissions fromelectricity. This will include new regulations to accelerate the phase out of traditional coal units by 2030 and
performance standards for natural gas-fired electricity. These actions will be complemented by investments to
reduce diesel use in rural and remote communities, supporting emerging renewable energy sources andmodernise Canada’s electricity systems, including in smart grid and energy storage technologies, and build new
and enhanced transmission lines to connect new sources of clean power with places that need it (GOC, 2016).
In addition to transitioning to lower-carbon fuels and clean electricity in the built environment,
transportation and industrial sectors, Canada will take action to reduce energy use by improving energy
efficiency, fuel switching and supporting innovative alternatives. In the built environment sector, this will
include developing ‘net-zero energy ready’ building codes to be adopted by 2030 for new buildings; retrofitting
existing buildings based on new retrofit codes and providing businesses and consumers with information onenergy performance; and improving energy efficiency of appliances and equipment.
Actions in the transportation sector include continuing to set increasingly stringent standards for lightand heavy-duty vehicles, in addition to taking action to improve efficiency and support fuel switching in therail, aviation, marine and off-road sectors. Canada will also be developing a zero-emission vehicle strategy by
2018; investing in infrastructure to support lower carbon and zero-emission vehicles; and investing in public
transit and other infrastructure to support shifts from higher- to lower-emitting modes of transportation (GOC,
2016).
To reduce emissions from industrial sectors, Canada is developing regulations to achieve a reduction inmethane emissions from the oil and gas sector, including offshore activities, by 40–45% by 2025. Federal,provincial, and territorial governments will work together to help industries improve their energy efficiency
and invest in new technologies to reduce emissions, including in the oil and gas sector. Canada has also
committed to finalising regulations to phase down the use of HFCs in line with the Kigali Amendment to theMontreal Protocol (GOC, 2016).

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Other actions in the Pan-Canadian Framework involve protecting and enhancing carbon sinks, including
those in forests, wetlands and agricultural lands; identifying opportunities to generate renewable fuel fromwaste; and demonstrating leadership by reducing emissions from government operations and scaling up the
procurement of clean energy and technologies. The framework also includes support for clean technology andinnovation that promote clean growth, including early-stage technology development; establishinginternational partnerships; and encouraging ‘mission-oriented’ research to help generate innovative new ideas
and create economic opportunities. Other complementary actions include support for RD&D or clean
technology in Canada’s natural resource sectors, and a Smart Cities Challenge (GOC, 2016).
The Pan-Canadian Framework also recognises the importance of building climate resilience and sets out
measures to help Canadians understand, plan for and take action to adapt to the unavoidable impacts of climatechange. For example, the federal government will establish a new Canadian Centre for Climate Services andwork with provinces and territories and other partners to build regional adaptation capacity and expertise thatwill make it easier for governments, communities, and businesses to access and use climate data andinformation to make adaptation decisions. Measures to build resilience through infrastructure include climateresilient codes and standards and a fund to build natural, large-scale infrastructure projects that support
mitigation of natural disasters, extreme weather events and climate resilience (GOC, 2016).
With the understanding that Indigenous Peoples and coastal and northern regions are particularly
vulnerable to climate impacts, action is also being taken to help these communities. This includes support for
Indigenous Peoples to monitor changes in their communities and take action to address climate impacts,
including repeated and severe flooding. In addition, targeted funding will be provided to enhance resilience innorthern communities by increasing capacity to adapt and improve the design and construction of northern
infrastructure (GOC, 2016).
In addition, the Pan-Canadian Framework highlights specific provincial and territorial actions to reduce
GHG emissions, implement carbon pricing and accelerate clean growth as well as identifies areas to explore
further federal–provincial–territorial collaboration.
PROVINCIAL

Each province develops and implements policies, regulations and initiatives in an effort to mitigate climatechange by reducing GHG emissions and supporting the transition to clean growth. The below examples ofregulations and programs focused on reducing direct GHG emissions include those highlighted in the PanCanadian Framework as well as new initiatives post-adoption of the framework.
British Columbia: The province introduced a revenue-neutral carbon tax in 2008, which is applied tothe purchase or use of fossil fuels within the province at a current rate of CAD 30 per tonne of CO 2
equivalent (PBC, 2016a). In 2015, British Columbia formed a Climate Leadership Team that reported
32 considerations for updating the current climate plan. In August 2016, the province announced 21
new measures to reduce net annual emissions by up to 25 Mt by 2050 but did not increase the priceof the carbon tax as recommended, citing competition with other jurisdictions. Examples of themeasures adopted include a reducing fugitive and vented methane emissions by 45% by 2025 ininfrastructure built before 2015, increasing the low-carbon fuel standard and transitioning to 100%
clean energy on the integrated electricity grid by 2025 (PBC, 2016b). British Columbia’s Budget
Update 2017 indicted it would be ending the revenue neutrality requirement to fund its climate action
commitments (PBC, 2017).

Alberta: In November 2015, Alberta announced the results of its Climate Leadership Plan (CLP) panel
recommendations, which included a CAD 20/tonne economy-wide carbon price beginning in 2017,
which increases to CAD 30/tonne in 2018 (GOC, 2018a). The price will continue to increase
thereafter, in real terms, as long as comparable action is taken in competing jurisdictions. The CLP
included provisions to address secondary impacts of the policy, including rebates for low-income
earners, output-based allocations for trade-exposed energy intensive industries and transitional
support for coal communities (PA, 2015). The output-based allocation system replaced the Specified
Gas Emitters Regulation on large facilities. The province also announced a cap on GHG emissions
from oil sands production (excluding upgrading and cogeneration) of 100 Mt per year, a commitment
to phase out coal-generated electricity by 2030 and a target to competitively procure 5 GW of42

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renewable energy capacity by 2030. In 2018, the results of the first renewable energy program procured
600 MW of electricity at a weighted average bid price of CAD 37 per MWh (AESO, 2018).


Saskatchewan: The provincial power utility, SaskPower, has made the world’s largest per capita
investment in CCS technology at its electricity generating facility at Boundary Dam. Since October
2014, the plant has captured over 1.9 Mt of carbon dioxide (CO2) (SaskPower, 2018b). The province
is also home to all of Canada’s active uranium mines, operating under the province’s Mineral Industry
Environmental Protection Regulations. Saskatchewan uranium fuels nuclear power plants in Ontario,
New Brunswick and other plants internationally, displacing between 230 and 550 Mt of the world’s
GHG emissions each year. In 2015, Saskatchewan announced a goal to double the percentage of
renewable capacity to 50% by 2030. The province also plans to procure 60 MW of solar capacity in2018 and has a target of 30% wind capacity by 2030 (SaskPower, 2018a). Saskatchewan has said it will
apply a sector-specific output-based performance standard on facilities emitting in excess of 25 Mt of
CO2-e per year (CEC, 2017).



Manitoba: In October 2017, Manitoba announced its provincial Climate and Green Plan with a carbon
price of CAD 25/tonne in 2018 with output-based allowances for large industrial emitters (PM, 2017).
The price will be held constant until 2022 when the plan will be reviewed. This price will bring
Manitoba in line with the federal carbon price floor in 2018; however, it will fall below the floor in
2019.



Ontario: Ontario joined the cap-and-trade market operating in Quebec and California in 2018 and its
system covers facilities and natural gas distributors with emissions of 25 Mt or more per year,
including fuel suppliers that sell more than 200 litres of fuel per year and electricity importers.
Emission allowances are distributed to participants that are not a) electricity generators or involvedin electricity importation and transmission, b) producing or supplying petroleum, or c) distributing
natural gas. Ontario has also announced that it will create a green bank to finance low-carbon energy
technologies to reduce pollution from buildings (PO, 2016b).



Quebec: Quebec has an economy-wide cap-and-trade system that is linked with California. In 2015,
Quebec adopted a 37.5% reduction target for emissions below the 1990 levels by 2030 (GOC, 2018a).



New Brunswick: The province has GHG emission reduction targets that reflect a total output of 10.7
Mt by 2030 and 5 Mt by 2050. New Brunswick also plans to phase out coal-fired generation as soon
as possible (PNB, 2016). New Brunswick’s environment minister has said that consumers will not pay
a new direct carbon tax, but rather the province will repurpose a portion of existing gas and fuel taxes
to act as a carbon price in accordance with the federal price floor. Large industrial emitters now face
the federal government’s standards as of 2018 (PNB, 2017).



Nova Scotia: The Greenhouse Gas Emissions Regulations 2009 places a cap on electricity sector
emissions from all facilities, with targets that have been set until 2030. In November 2016, Nova
Scotia and the Government of Canada agreed to negotiate a new equivalency agreement regarding
federal coal-fired electricity regulations in light of the federal intent to accelerate the phase out ofcoal-fired electricity generation by 2030. In December 2016, Nova Scotia committed to establish a
cap-and-trade program at the beginning of 2019 for large industrial facilities, the electricity sector,
petroleum product suppliers and natural gas distributors to comply with the pan-Canadian approachto pricing carbon pollution (PNS, 2018).

Newfoundland and Labrador: In 2016, the province created a new fund for clean technology, fundedthrough a form of carbon pricing on large industry (PNFLD, 2016). The Management of Greenhouse
Gas Act was passed in June 2016 and aims at reducing GHG emissions from large-emitters. In
November 2017, Newfoundland and Labrador announced that it will release a carbon pricing plan in
Spring 2018 (Telegram, 2017).

INTERNATIONAL

Canada has been active on the international climate change stage. Prior to the Paris Agreement., Canada signed
the Copenhagen Accord (2009) and committed to reducing GHG emissions to 17% below the 2005 levels by
2020 (EC, 2013). Since the end of the Doha round of negotiations under the UNFCCC in December 2012,43

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Canada has continued its engagement in the negotiations to support the establishment of a fair andcomprehensive global climate change regime, leading up to the signing of the Paris Agreement in 2016.
In 2015, Canada announced it would contribute CAD 2.65 billion over the next five years to help
developing countries tackle climate change. The contribution supports the commitment made under the 2009
Copenhagen Accord to work to mobilise climate finance to reach USD 100 billion annually by 2020 (GOC,
2018a). In addition, Canada helped secure an agreement amongst the 197 signatories to the Kigali agreement,
an amendment to the Montreal Protocol, to reduce the use of factory-made HFC gases.
From 3 September to 9 September 2017, Canada hosted the 46th session of the Intergovernmental Panelon Climate Change (IPCC) in Montréal. Hundreds of scientists and representatives from 195 countries
gathered to advance the science of climate change and decide the scope of the sixth IPCC assessment report.
The IPCC reports provide the most up-to-date international scientific knowledge on climate change and play
an important part in supporting the implementation of the Paris Agreement and the Pan-Canadian Frameworkon Clean Growth and Climate Change (IPCC, 2017).
Canada has been a member of IPCC since its inception in 1988. Canada makes significant scientificcontributions to the IPCC, with Canadian scientists holding leadership positions on the IPCC’s scientificadvisory body and Task Force on National Greenhouse Gas Inventories and serving as authors for IPCC
reports.
The Ministerial for Climate Action (MOCA) was launched in 2017 by Canada, China and the European
Union as a forum for over 30 ministers from major economies and key players on climate change to discuss
the ambitious implementation and help build common ground on on-going multilateral negotiations. The first
MOCA took place in September 2017 in Montreal, Canada.
N OTA B L E E N E RG Y D E V E L O P M E N T S
REGULATORY DEVELOPMENTS

On February 8th, 2018, the Government of Canada introduced an integrated bill, Bill C-69, An Act to enact
the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act
and to make consequential amendments to other Acts, to amend the Navigation Protection Act and to repeal
certain Acts and make consequential amendments to other Acts.
The proposed changes aim to address the following issues:








Rebuilding public trust: The proposed legislation aims to rebuild trust by increasing public
participation in project reviews so that Canadians can help shape the project design, provide input
into the project plan and assess the science used to make decisions. In addition, improved earlyplanning would lead to improved project design, and provide companies more certainty about what’s
expected of them from the start of the review process.
Investor confidence: The intent of the proposed legislation is to protect Canada’s environment
while improving investor confidence, strengthening the Canadian economy and creating good
middle-class jobs by providing a more efficient and predictable process. With better rules, companies
would have more clarity about what is required of them, and project reviews would be morepredictable and timely, encouraging investment in Canada’s natural resources sectors. Project reviews
would benefit from early planning, where the government would clarify how to engage. Indigenous
peoples effectively, and identify potential issues with project proposals up-front—all leading to more
timely decisions.
Advancing reconciliation with Indigenous peoples: Under Bill C-69, there would be early andregular engagement and partnership with Indigenous peoples based on recognition of Indigenous
rights and interests from the start. Consideration of Indigenous traditional knowledge would be
mandatory and the government would protect the confidentiality of Indigenous traditional knowledge(e.g. sacred site locations) and respect Indigenous laws and protocols for its use.
Public participation: The new early planning and engagement phase would provide clarity on what
is required and more certainty about the process ahead. The government would ensure that
Canadians’ views are heard from the start and improve participant funding programs for Indigenous44

APEC ENERGY OVERVIEW 2017







CANADApeoples and the public. Independent reviews would be done where there is strong public concern or
the results of a study are uncertain.
Assessing what matters to Canadians: Project reviews would consider not just impacts on theenvironment, but also on social and health aspects, Indigenous peoples, jobs and the economy overthe long-term. The government would also conduct gender-based plus analyses. Project decisions
would be guided by science, evidence, and Indigenous traditional knowledge. The regulator would
evaluate regional and strategic issues outside of project reviews (e.g. climate change, biodiversity,
species at risk), the cumulative effects of development and provide context for impact assessments.
Project reviews would consider how projects are consistent with our environmental obligations andclimate change commitments, including the Paris Agreement on Climate Change. The government
would also undertake a strategic assessment for climate change to provide guidance on how to
consider greenhouse gas emissions in individual project reviews.
One project – one review: The government would streamline the process and coordinate with theprovinces and territories to reduce red tape for companies and to avoid duplicating efforts inreviewing proposed projects. The proposed Bill will enhance cooperation with provinces andterritories by focusing on enhanced harmonization and collaboration, including early engagement andmore flexible timelines; renewing bilateral cooperation agreements to support harmonized processes;
and maintaining provisions for substitution. The new Impact Assessment Agency of Canada would
be responsible for leading impact assessments of designated projects (on the project list) projects andwork collaboratively with life-cycle regulators, like the Canadian Energy Regulator (CER), to draw
upon their expertise and ensure that safety and other key regulatory factors are considered as part ofa single, integrated review.
New Canadian Energy Regulator: Under the new legislation, the CER would replace the National
Energy Board (NEB) to support greater investment certainty; build confidence through open,
accessible, inclusive, and transparent public participation processes; provide predictable timelines
and clear expectations for energy projects; and advance Indigenous reconciliation objectives.
Canadians, investors and companies would have certainty that good projects can move forward,
creating jobs and building a stronger economy, while ensuring the environment is protected for future
generations.

The new proposed rules must still be passed by Parliament. Until the new rules come into effect, existing laws
and interim principles for project reviews will continue to apply to projects under review. The government
will seek input from Canadians on regulations and policy changes required to accompany the legislation. Oncethe new rules come into effect, the government will not be revisiting project decisions made under previous
legislation.
PIPELINE DEVELOPMENTS

Oil exports through pipelines are a major means for securing new markets for the long-term success of
Canada’s landlocked oil economy, which is mainly based in Alberta, Saskatchewan and Manitoba. Although
the industry is experiencing growth in production from oil sands and new light oil prospects, its location is not
ideal. The producing reserves are far from the major refining hub on the US Gulf Coast and ocean ports, which
would provide access to the expanding overseas market. The governments and industry are working together
to find options to access markets. Consequently, several pipeline proposals are in the regulatory process or
have recently received approval.
The federal government granted approval to two pipeline projects in 2016, the expansion of Kinder
Morgan’s Trans Mountain Pipeline, flowing from Edmonton, Alberta to Vancouver, British Columbia, andthe expansion of Enbridge’s Line 3 Pipeline from Edmonton, Alberta to Superior, Wisconsin. During the sameannouncement, Enbridge’s Northern Gateway pipeline project (greenfield construction) was rejected. Prime
Minister Trudeau cited Alberta’s recent Climate Leadership Plan as vital to the approval of both pipeline
expansions (CP, 2016).
In 2017, TransCanada’s Keystone XL Pipeline project received the presidential permit required from the
US Trump Administration. The pipeline also cleared a regulatory hurdle in Nebraska in November 2017.
However, TransCanada has not yet finished negotiating with landowners along the route, and construction has
yet to begin.

45

APEC ENERGY OVERVIEW 2017

CANADA

ARCTIC AND OFFSHORE ENERGY

Exploration by the oil and gas industry and the Geological Survey of Canada have long indicated a strong
potential for petroleum discoveries in Canada’s northern region, particularly in the Arctic section. However,the costs of developing the fields and transporting oil and gas to markets have been quite high. In particular,
the low oil prices in the previous decades and transportation bottlenecks have made discoveries uneconomical
to develop (NRCan, 2007).
Canada’s oil and gas industry in the north, including offshore drilling in the Arctic, is regulated by the
NEB, as set out in the Canada Oil and Gas Operations Act (COGOA), Canada Petroleum Resources Act(CPRA) and National Energy Board Act. However, Canada’s Atlantic offshore oil and gas industry is regulatedby the CNSOPB and the Canada-Newfoundland and Labrador Offshore Petroleum Board. It is important tonote that a 1972 federal moratorium restricts offshore field development off the Pacific coast of Canada, where
there is an estimated 9.8 billion barrels of recoverable resources (NRCan, 2016d).

46

APEC ENERGY OVERVIEW 2017

CANADA

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47

APEC ENERGY OVERVIEW 2017

CANADA

GOC (Government of Canada) (1867), VI. Distribution of Legislative Powers, http://lawslois.justice.gc.ca/eng/const/page-1.html/.
–– (1985a), Canada Oil and Gas Operations Act, http://laws-lois.justice.gc.ca/eng/acts/O-7/.
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–– (2016), Pan-Canadian Framework on Clean Growth and Climate Change,
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HQ (Hydro Québec) (2018), Massachusetts request for proposals – Hydro-Québec energy selection confirmed,
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IEA (2017a), National Survey Report of PV Power Applications in Canada 2016, http://www.ieapvps.org/index.php?id=93.
–– (2017b), Energy Statistics of OECD Countries.
IPCC (Intergovernmental Panel on Climate Change) (2017) IPCC-46 and Working Group I, II, III Sessions,Montreal, Canada, 6 - 10 September 2017,https://www.ipcc.ch/scripts/_session_template.php?page=_46ipcc.htm.
ISEDC (Innovation, Science and Economic Development Canada) (2017), Trade Data Online,
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NEB (National Energy Board) (1996), Natural Gas Market Assessment: Ten Years After Deregulation,
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asMarketAssessment.pdf.
–– (2015), Canada Energy Dynamics 2014, https://www.neb-one.gc.ca/nrg/ntgrtd/mrkt/dnmc/2014/indexeng.html.
–– (2016a), Canada’s Energy Future 2016: Energy Supply and Demand Projections to 2040 [January 2016],
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–– (2016b), Canadian Energy Dynamics: Highlights of 2015 - Energy Market Analysis, https://www.nebone.gc.ca/nrg/ntgrtd/mrkt/dnmc/2015/index-eng.html#s12.
–– (2016c), Crude Oil Reserves, https://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2013/ppndcs/pxlrsrvs-eng.html.
–– (2017), 2016 Electricity Exports and Imports Summary, https://www.nebone.gc.ca/nrg/sttstc/lctrct/stt/lctrctysmmr/2016/smmry2016-eng.html.
–– (2018), NEB Electricity, www.neb-one.gc.ca/bts/ctrg/gnnb/lctrct/index-eng.html.
NRCan (National Resources Canada) (2007), Arctic Oil and Gas,
www.gac.ca/PopularGeoscience/factsheets/ArcticOilandGas_e.pdf.
–– (2014), About Uranium, http://www.nrcan.gc.ca/energy/uranium-nuclear/7695.

48

APEC ENERGY OVERVIEW 2017

CANADA–– (2015a), CanmetENERGY, www.nrcan.gc.ca/energy/offices-labs/canmet/5715/.
–– (2015b), Wind Energy R&D Park and Storage System for Innovation in Grid Integration,www.nrcan.gc.ca/energy/funding/current-funding-programs/cef/4979.
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–– (2016a), Energy Fact Book: 2016-2017,https://www.nrcan.gc.ca/sites/www.nrcan.gc.ca/files/energy/pdf/EnergyFactBook_2016_17_En.pdf.
–– (2016b), Shale and Tight Resources in Canada, https://www.nrcan.gc.ca/energy/sources/shale-tightresources/17669.
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–– (2016d), Offshore Oil and Gas, www.nrcan.gc.ca/energy/offshore-oil-gas/5835.
–– (2016e), Small Hydropower, www.nrcan.gc.ca/energy/renewable-electricity/small-hydropower/7363.
–– (2016f), About Electricity, http://www.nrcan.gc.ca/energy/electricity-infrastructure/about-electricity/7359.
–– (2017a), Energy and the Economy, http://www.nrcan.gc.ca/energy/facts/energy-economy/20062#L4.
–– (2017b), About Renewable Energy, www.nrcan.gc.ca/energy/renewable-electricity/7295.
–– (2017c), Nuclear Energy, www.nrcan.gc.ca/energy/uranium-nuclear/7711
OPG (Ontario Power Generation) (2017), Darlington Refurbishment Enters Next Major Phase,https://www.opg.com/darlington-refurbishment/Pages/20171219_RefurbNextPhase.aspx.
PA (Province of Alberta) (2015), Alberta Climate Leadership: Report to Minister,
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PBC (Province of British Columbia) (2016a), How the Carbon Tax Works,
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–– (2016b), Climate Leadership Plan: August 2016,
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–– (2017), Budget 2017: September Update,
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PM (Province of Manitoba) (2017), A Made-in-Manitoba Climate and Green Plan,
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PMO (Office of the Prime Minister of Canada) (2015) Minister of Natural Resources Mandate Letter,
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PNB (Province of New Brunswick) (2016), Transitioning to a Low-Carbon Economy: New Brunswick’s Climate
Change Action Plan, http://www2.gnb.ca/content/dam/gnb/Departments/env/pdf/ClimateClimatiques/TransitioningToALowCarbonEconomy.pdf.
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PNS (Province of Nova Scotia) (2016) Nova Scotia Reaches Climate Change Agreement,
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PNFLD (Province of Newfoundland and Labrador) (2016), Provincial Government Announces Plan for Greenhouse
Gas Emissions Reductions, http://www.releases.gov.nl.ca/releases/2016/exec/0607n02.aspx.
PO (Province of Ontario) (2016a), Nuclear Refurbishment Begins at Darlington Generating Station,
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49

APEC ENERGY OVERVIEW 2017

CANADA–– (2016b), Ontario’s Five Year Climate Change Action Plan: 2016-2020,
http://www.applications.ene.gov.on.ca/ccap/products/CCAP_ENGLISH.pdf.
–– (2018), Cap and Trade, https://www.ontario.ca/page/cap-and-trade.
SaskPower (2018a), Renewables Roadmap, http://www.saskpower.com/our-power-future/renewablesroadmap/.
–– (2018b), BD3 Status Update: January 2018, http://www.saskpower.com/about-us/blog/bd3-status-updatejanuary-2018/.
StatCan (Statistics Canada) (2015), Land and Freshwater Area, by Province and Territory, www.statcan.gc.ca/tablestableaux/sum-som/l01/cst01/phys01-eng.htm.
–– (2016a), Differences Between Statistics Canada's Census Counts and Population Estimates,
http://www.statcan.gc.ca/eng/hp/estima?HPA=1–– (2016b), Table 127-0009: Installed Generating Capacity, by Class of Electricity) Producer—Annual (kilowatts),
http://www5.statcan.gc.ca/cansim/a26?lang=eng&id=1270009.
–– (2017), Table 128-0014: Electricity Generated from Fossil Fuels—Annual (Gigawatt Hour),
http://www5.statcan.gc.ca/cansim/a26?lang=eng&id=1280014.
Telegram (The Telegram) (2017), Newfoundland and Labrador’s Carbon Pricing Plan to be Unveiled Next Spring,
http://www.thetelegram.com/business/newfoundlands-carbon-pricing-plan-to-be-unveiled-nextspring-ball-158276/.
UNIDO (United Nations Industrial Development Organization) (2016), World Small Hydropower Development
Report 2016,
http://www.smallhydroworld.org/fileadmin/user_upload/pdf/2016/Americas_Northern/WSHPDR_
2016_Canada.pdf.
WNA (World Nuclear Association) (2017), World Uranium Mining Production, http://www.worldnuclear.org/information-library/nuclear-fuel-cycle/mining-of-uranium/world-uranium-miningproduction.aspx.

50

APEC ENERGY OVERVIEW 2017

CANADAUSEFUL LINKS

Atomic Energy of Canada Ltd—www.aecl.ca
Canada Gazette—www.gazette.gc.ca
Canada-Nova Scotia Offshore Petroleum Board—http://www.cnsopb.ns.ca/
Canadian Nuclear Laboratories—www.cnl.ca
Canadian Nuclear Safety Association—http://nuclearsafety.gc.ca
Canada Newfoundland and Labrador Offshore Petroleum Board http://www.cnlopb.ca/
Environment and Climate Change Canada—www.ec.gc.ca
National Energy Board—www.neb.gc.ca
Natural Resources Canada—www.nrcan-rncan.gc.ca
Statistics Canada—www.statcan.ca
Transport Canada—www.tc.gc.ca

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APEC ENERGY OVERVIEW 2017

CHILE

CHILE
I N T ROD U C T I ON

Chile joined APEC in November 2004 and is one of the two South American member economies. It is locatedin the south-west of South America, occupying a long narrow land area between the Andes Mountain to theeast and the Pacific Ocean to the west. Chile shares borders with Peru to the north, Bolivia to the northeast
and Argentina to the east. Its coastline runs along the Pacific Ocean for 6 435 km, with an average width of
175 kilometres (km) and a land area of 756 102 square kilometres (km2). Administratively, Chile is divided into
54 provinces and 15 regions, headed by regional governors appointed by the president. In 2017, the economy’s
population was 17.6 million, and 40.5% of the population resided in the Metropolitan Region (INE, 2018).
Chile’s economic growth is based on solid macroeconomic fundamentals, such as fiscal responsibility, an
independent central bank with an explicit inflation target and a floating exchange rate system. Chile has almost
tripled its gross domestic product (GDP) per capita from USD 8 175 in 1990 to USD 21 279 in 2015 (2015
USD purchasing power parity [PPP]). It is one of the fastest growing economies in South America, with anaverage annual growth rate of 3.1% between 2000 and 2015. In 2015, Chile’s GDP reached USD 378 billion(2015 USD PPP), which represents an increase of 2.3% from the 2014 levels. Chile’s economic activity is highly
correlated with final energy consumption, where the industry sector accounted for 42% of final energy
consumption in 2015 and represented around 24% of Chile’s economic activity (INE, 2017).
Despite the diverse geography and abundant natural resources, the territory is very limited in fossil fuelresources, making Chile a net importer of fossil fuels; thus, one of its mainstay priorities revolves around a
steady energy supply. Fossil fuel reserves are limited, so nearly the entire fossil fuel supply is imported (around
64% of total primary energy supply [TPES] in 2015). Chile imports 98% of its oil, 84% of its gas and 79% of
its coal, but despite high oil and gas import dependence, hydro and non-conventional1 renewables contributed
about 40.3% of TPES in 2015 (EGEDA, 2017).
Table 1: Key data and economic profile, 2015
Key dataa

Energy reservesb

Area (km2)

756 092

Oil (million barrels)

11.8

Population (million)

18

Gas (million cubic metres)

8.1

GDP (2010 USD billion PPP)

378

Coal (million tonnes)

171

GDP (2010 USD PPP per capita)

21 279Uranium (kilotonnes U)

3.7

Sources: a EGEDA (2017); b CCHEN (2013).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

According to the Expert Group on Energy Data Analysis 2017 (EGEDA 2017), Chile’s TPES increased by
2.5% from 2014 to 2015 to reach 36 113 kilotonnes of oil equivalent (ktoe). Approximately 42.4% of thisenergy volume was supplied in the form of crude oil and its by-products, 20% as coal, 11% as natural gas andthe remaining 26.8% as other sources, particularly renewables including biomass, solar, wind and hydropower.
Given its limited natural endowment in hydrocarbons, Chile is a net importer of primary energy, especiallyfossil fuels. Its net primary energy imports represent 65% of the TPES, having increased by nearly 1.5% from2010 to 23 988 ktoe in 2015.

1 Solar, wind, biomass and biogas.

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APEC ENERGY OVERVIEW 2017

CHILE

Final energy consumption (excluding non-energy) increased in 2015, reaching 24 923 ktoe, 2.6% higher
than 2014. Fossil fuel consumption increased by 2.5% from 2014 to 2015; in fact, 55% (13 774 ktoe) of the
final energy consumption (excluding non-energy) is represented by oil, followed by 14.8% by gas (1 384 ktoe)
and 1.3% by coal (322 ktoe). The remaining final energy consumption comes from renewable energy (15%)
and electricity and others (23%). According to the National Oil Company (ENAP) studies, endorsed by theUnited States Geological Survey (USGS), the existence of a non-conventional gas potential in Magallanes was
confirmed, which could amount to 8.3 trillion cubic feet (tcf). This value doubles the volume of gas extracted
from the Magallanes basin during the 70 years of operation of ENAP, which reached 4.2 tcf. This ensures the
future supply of thermal consumption in the region and generates significant industrial and economic activity(ENAP, 2016).
FINAL ENERGY CONSUMPTION

In 2015, Chile’s final energy consumption was 24 923 ktoe, representing an increase of 2.6% from the previous
year.
By sector, total final consumption in the industrial sector accounted for 42%, transport accounted for
34% and others (including the residential, commercial and public sectors) accounted for 23%. The remaining
1% represented non-energy use, including agriculture and other.
By energy source, around 55% of Chile’s final energy consumption was met by oil consumption, which
was primarily consumed by the transport and industrial sectors, followed by electricity and other sources (23%),
natural gas (5.5%) and coal (1%). Oil consumption increased by 5.4% from 2014 and electricity consumption
decreased by 0.1% (EGEDA, 2017).
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

12 906

Industry sector

10 601

Net imports and others

23 988Transport sector

8 446

Thermal42 515

Total primary energy supply

36 113

Other sectors

5 876

Hydro

23 881

Coal

7 165

Non-energy

226

Nuclear-Oil

15 294

Final energy consumption*

24 923

Others

8 991

Gas

3 980

Coal

322

Renewables

9 674

Oil

13 774

0

Gas

1 384

Renewables

3 695

Electricity and others

5 748

OthersPower generation (GWh)
Total power generation

75 387

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in power
plants is assumed to be comprising renewables.
ENERGY INTENSITY ANALYSIS

Energy intensity has been declining since 2000, indicating a more efficient use of energy sources. Chile’s energy
intensity in terms of primary energy supply in 2015 was 96 tonnes of oil equivalent per million USD(toe/million USD), increasing by 0.2% from 95 toe/million USD in 2014. The energy intensity for total
consumption decreased by 1.5%, from 68 toe/million USD in 2014 to 67 toe/million USD in 2015.

53

APEC ENERGY OVERVIEW 2017

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Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

EnergyChange (%)

2014

2015

2014 vs 2015

Total primary energy supply

95

96

0.2

Total final consumption

68

67

–1.5

Final energy consumption excl. non-energy

65.7

65.9

0.3

Source: EGEDA (2017)
RENEWABLE ENERGY SHARE ANALYSIS

In 2015, the share of modern renewable energy to final energy consumption was 18%, a decrease of 1
percentage point from the previous year.
Table 4: Renewable energy share analysis, 2014 vs 201524 291

24 923

Change (%)
2014 vs 2015
2.6

Non-renewables (Fossils and others)

17 80018 722

5.2

Traditional biomass*

1 835

1 706

–7.0

Modern renewables*

4 655

4 495

–3.5

Share of modern renewables to final energy
consumption (%)

19%

18%

–5.9%

2014
Final energy consumption (ktoe)

2015

Source: EGEDA (2017)* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies, which often have adverse effects on human health. This definition is applicable to all APEC member
economies, including those that are members of the Organisation for Economic Cooperation and Development (OECD)and those that are not (Non-OECD). All other renewables (hydro, geothermal, and so on), including biogas and woodpellets, are considered modern renewables, although data on wood pellets are limited.
E N E RG Y P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

Since the 1980s, Chile has embarked upon developing an economy based on international trade and the rulesof the free market. It has reaped various benefits as the economy has grown significantly. From the 1980s to
2014, Chile has more than doubled its income per capita and has been one of the fastest growing economies
in Latin America. In addition, it provides a business environment conducive to foreign investments, given its
streamlined administrative processes and simplified tax payments.
Being an open-market economy, Chile is highly integrated with other world markets. Its participation infree trade agreements has increased its options for sustainable development, as evidenced by increased tradeopportunities, reduced dependency on mineral exports and the creation of trade products with higher valueadded.
In line with these principles, Chile’s energy policy is based on the development of a free market economy
and oriented towards enhancing its economic efficiency and energy security by reducing its vulnerability tosupply disruptions and its high dependence on imports.

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APEC ENERGY OVERVIEW 2017

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The Chilean Parliament approved the creation of a Ministry of Energy in November 2009 and the new
Ministry of Energy started operations in February 2010. This ministry centralises the functions of developing,
proposing and evaluating public policies in this area, including the definition of objectives, regulatory
framework and strategies to be applied, as well as the development of public policy instruments.
Energy 2050, launched in July 2014, was a participatory process to formulate the Energy Policy. The
process lasted a year and a half and brought together more than 4 000 people, both energy experts and citizens,
to establish a common vision regarding the energy of the future (Ministerio de Energia, 2018a). By December
2015, which was at the end of the process, the Chilean Ministry of Energy presented ‘Chile’s Energy Policy’ toguide energy policy in the economy for the long term. The policy is an effort to establish a long-term vision
on energy policy. Note that this long-term policy was approved by Supreme Decree N°148, which emanatedfrom the Presidency of the Republic and was endorsed by all ministries involved, making it a state policy. The
main goal of Energy 2050 is to document Chile’s long-term energy policy, which has been validated in an open
participative process with Chilean citizens. The policy addresses the citizens’ concerns, and aims to work
towards improving energy security and reliability. The creation of this document is envisaged across thefollowing stages and goals:
1.

Energy Road Map: This road map, completed in September 2015, was oriented to create agreements
and build a shared long-term vision for the sector under the concepts of sustainability and inclusion.
It originated as a proposal from an Advisory Committee convened by the Ministry of Energy and wasused as input to formulate Chile’s Energy Policy. According to the Energy Road Map, the economy’s
future energy policy needs to consider the following features:
 Compatibility with the environment and communities;
 Universal and equitable access; Essential conditions for development; Opportunity for innovation;
 Efficient production and consumption and Energy security.

2.

Energy 2050–Chile’s Energy Policy: Released in December 2015, this policy describes the four pillars
of Chile’s energy policy that will help to achieve a vision of Chile’s energy sector by 2050 that is reliable,
inclusive, competitive and sustainable:
 Quality and security of supply; Energy as a driving force for development;
 Environmentally friendly energy and Energy efficiency and energy education.

The main goals of Energy 2050 are summarised in the following table.
Table 5: Main goals of Energy 2050 by 2035 and 2050
By 2035
Interconnection with other Andean
Region Electric Interconnection
System members (Chile, Peru,
Ecuador and Colombia are member
countries, and Bolivia is an observercountry) and with other SouthAmerican economies, particularly
Mercosureconomies(Brazil,Paraguay, Uruguay, Argentina,
Bolivia [in the accession process]and Venezuela).

By 2050

Current Status a
In 2016, Chile sent natural gas to Argentina
via national pipelines located in the north andcentral areas of the country.

EnergysectorGHG
emissionsbelow
limitsestablished in the economywide goals.

55

In February 2016, the economy began toexport electricity with Argentina. This
exchange follows the authorization of theCompany AES Gener S.A. to export electric
power to Argentina as stipulated in Supreme
Decree N° 7 (July 2015).

APEC ENERGY OVERVIEW 2017

By 2035

CHILE

By 2050

Current Status a
In December 2017, Chile and Argentina
signed a protocol agreement to exchange
electricity and gas between the countries.
In 2016, disruptions totalled 6.5 hours, which
was a decrease of 8.5 hours from 2015.

Energy disruption reduced to lessthan four hours per year in any
locality in Chile, except in cases offorce majeure.

Energy disruption reduced toless than one hour per year in
any locality in Chile, except incases of force majeure.

Continuous and reliable access toenergy services for all vulnerable
dwellings.

Universal and equitable accessto reliable and modern energy
services.

No information

All developed projects haveassociation mechanisms between
project developers and communities
to foster local development andbetter performance.

Territorial, regional and local
planning and management
tools conforming to theenergy policy are in place.

No information

Be among the five OECDeconomies having the lowest
average electricity prices at theresidential and industrial levels.

Be among the three OECDeconomies having the lowest
average electricity prices at theresidential and industrial
levels.

No information

At least 60% of electricity generationfrom renewable sources.

At least 70% of electricity
generation from renewablesources.

Overall, in 2016, 35% of electricity
generation in Chile came from renewable
resources

A 30% GHG emissions intensity
reduction in comparison with 2007.

Energydecoupled
growth.

Energy consumption in 2015 decoupledfrom GDP growth in a 30% approximately.

All large energy consumers(industry, mining and transport) toapply energy efficiency measures.

All new buildings will be
constructed as per theOrganisation for Economic
Co-operation
andDevelopment(OECD)
standardsofefficientconstruction
and
smart
systemsofenergymanagement.

No informationAllmunicipalities
toadopt
regulations declaring traditional
biomass as solid fuel.

100% of the main categories
of appliances sold in the
Chilean market are energy
efficient.

No information

All new auctioned vehicles for
public passenger transportation to
be evaluated under energy efficiency
standards.

Energyconservation
measures are implemented inall sectors.

No information

consumption
from
GDP

Sources: a Ministerio de Energia (2018b); La Tercera (2017)56

APEC ENERGY OVERVIEW 2017

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Nuclear energy is not a short-term option under Energy 2050, but further research has been proposed
to be considered in the next policy review. A complete revision of the Energy Policy will start in 2019 and thefinal document will be ready by 2020.
MARKET DESIGNPETROLEUM-BASED FUELS REGULATORY FRAMEWORKThe Gas Services Law (D.F.L N° 323 of 1931), amended by Law 20 999, establishes a regime of tariff freedom
regulated by concessionary gas distribution companies with eventual tariffs. A concessionaire company will becharged when it exceeds the maximum limit of profitability set by the law equivalent to the Cost of Capital
Rate, whose minimum floor is 6%, plus an additional margin of three percentage points. Said maximum
profitability will be controlled by the National Energy Commission (Comisión Nacional de Energía or CNE),
through an annual profitability check process. For Magellan and Chilean Antarctica, the law contemplates apermanent pricing regime that must be carried out by the CNE four times a year.
On the other hand, the Gas Services Law regulates a change in gas company supplier, easing the transferof personal property that is on the client's property. For these purposes, the CNE will issue a four-year
valuation report on the movable facilities intended to provide residential gas service.
Likewise, the CNE determines the parity and reference prices of fuels weekly for the purposes of theapplication of the Fuel Price Stabilisation Mechanism created by Law 20 765, as well as the Oil Prices
Stabilisation Fund of Law 19 030 and its respective amendments. Parity prices are determined weekly forgasoline fuels of 93 and 97 octane, diesel oil and liquefied gas (Law 20 765) and domestic kerosene (Law 19030).
On the other hand, the reference prices are expected values that reflect the price of the respective fuels
without considering short-term volatility. These reference prices are determined for the case of Law 20 765
based on the past and future average values of crude oil representative of a relevant market, and an average ofpast values of refining differentials, transportation costs, insurance, customs duties and other expenses andcosts of admission, as appropriate and in the case of Law 19 030, as the weighted sum of three components:i) historical weighted component of parity prices for the last four semesters; ii) projection component of theshort-term parity price (one year) and iii) long-term parity price projection component (10 years) (CNE, 2018a).
ELECTRICITY REGULATORY FRAMEWORKThe General Law of Electric Services (LGSE–Ley General de Servicios Eléctricos) mainly sets the legal basefor the electricity sector. The law was originally enacted in the early 1980s, where all basic principles of thepresent energy regulation were defined. The law privatises the electricity industry, introduces competition into
the generation sector and separates the industry’s generation, transmission and distribution segments.
Privatisation of the state-owned utilities began in 1986 and was completed by 1998. These principles haveremained valid until now despite minor changes. Chile was the first country in the world to deregulate its powerindustry, with the incorporation of free market principles (CNE, 2018a).
The LGSE has been amended several times with different modifications.
1. Short Law I, Law 19 940 (Ley Corta I) – March 2004: It introduces modifications to the LGSE withthe main objective of regulating the decision-making and the development of the expansion of thetransmission of electricity. It also establishes incentives for non-conventional sources and small
generation units.
2. Short Law II, Law 20 018 (Ley Corta II) – May 2005: It introduces modifications to the LGSE withthe main objective of stimulating the development of investments in the generation segment throughsupply bids made by distribution companies.
3. Law NCRE (Ley ERNC): It introduces modifications to the LGSE, establishing short- and long-term
policy targets for the share of renewable energy in total electricity generation. The short-term target,
initially adopted in 2008 by Law 20 257, stated that, between 2010 and 2014, 5% of the energy shouldcome from non-conventional renewable energy (NCRE), increasing by 0.5% annually from 2015 in

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APEC ENERGY OVERVIEW 2017

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order to reach 10% by 2024. In 2013, the share was increased by Law 20 698 to 20% by 2025. The
Law defines the following energy sources as NCRE: biomass, hydropower with capacity less than 20
MW, geothermal, solar, wind, marine energy and other means of generation determined by the CNE.
4. Transmission Law, Law 20 936–July 2016: It introduces a major reform to the LGSE. The law
enhances the role of the state in energy planning and the expansion of the transmission system–thestate now assumes certain functions that were previously in the hands of the private sector. The law
introduces several new regulatory changes for Chile’s electricity sector. It created the National Electric
Coordinator (Coordinador Eléctrico Nacional, CEN), a unified independent system operator. It
supports grid expansion and cross-border connections and a long-term energy planning (LTEP)
process for a time span of at least 30 years. Transmission expansion planning processes carried out
by the CNE use one or more results from the LTEP. In the remuneration of the transmission system,
tolls are borne completely by the consumers and defined the mechanisms to determinate the Cost of
Capital Rate, which could fluctuate between 7% and 10% after taxes.
WHOLESALE ELECTRICITY MARKETThe wholesale electricity market in the Chilean system has two components:
1. Spot market: generators buy and sell electricity.
2. Financial contract market: large consumers and distributors buy electricity from the generators.
The Spot Market (or market for short-term transactions) consists of the purchase/sale of electricity at
marginal cost and is operated by the CEN. Only generators may sell or buy electricity on the spot market.
Power plants are dispatched in a merit order using regulated estimates of their marginal costs (audited variable
costs). This is mainly to avoid the negative impacts of very high levels of market concentration. The marginal
costs of the system are calculated on an hourly basis for each node of the system.
The financial contract market has two components: one for large customers and another for distributors.
Generators can sell their electricity to large consumers at prices freely agreed between the parties. In contrast,electricity sales to distribution companies with regulated customers are organised through tenders for longterm supply.
Wholesale competition in Chile occurs in the ‘contract market’, in which generators sell electricity freely
to large (non-regulated) customers, and through tenders to distributors that supply small (regulated) customers.
Around half of the electricity demand in Chile is supplied under these tenders.
Customers connected to the grid through a local distribution company, with power connection between 0.5
and 5 MW, can choose between being a regulated or a non-regulated customer for a period of four years.
Regulated customers: Regulated price considers the distribution fee, node price based on the marginal
cost of energy of the respective tender, capacity charge and transmission charge.



Non-regulated customers: These customers are free to negotiate directly with the power generationcompanies, but will have to stay in the free market for at least four years and inform the distributor
at least a year in advance.

DISTRIBUTION

This sector is organised through concessions and there are 26 distribution companies. The distribution sector
induces the existence of natural monopolies based on geography. These companies are subject to the fixing of
their energy charges, which are obtained from an analysis carried out by the CNE every four years. Distributionenergy charges are calculated by comparison with a model company, so that distributors receive a return for
all of their efficient costs: capital, operation, maintenance and administration. Similar to energy prices,
distribution charges are also subject to an equalisation mechanism to ensure similar distribution charges across
Chile.
The government is working on a proposal for a new distribution law that would ensure the modernisationof the distribution sector. The objective is to encourage the development of a more efficient and intelligent

58

APEC ENERGY OVERVIEW 2017

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distribution grid, to introduce new technologies and new companies and to expand business opportunities inthe sector.
TENDERS FOR LONG-TERM ELECTRICITY SUPPLYThe New Electricity Act on Energy Auctions (Law 20 805) establishes the process of open energy auctions,encouraging the entrance of new players and electricity generation technologies. This improvescompetitiveness and promotes better price mechanisms in favour of end users in the electricity market for
regulated users (CNE, 2018a).
Following are the main features of these tenders:a.

The energy tenders provide the opportunity to acquire 20-year PPAs and materialise new generation
investments;b.

The coming long-term tenders will lead to supply starting five years after the supply contract, giving
enough time for the construction of new projects;c.

Different generation projects and efficient technologies will be able to participate due to the several
supply blocks offered andd.

Prices may be revised if taxes or laws change.

The auction winners in 2017 will start delivering energy to the grid from 2022 to 2041. In 2017, the average
price per MW/h was USD 32.5, the lowest since 2006. The average price since 2012 has decreased from 134.2
USD/MWh to 32.5 USD/MWh.

14,00012,00010,000
8,000
6,000
4,000
2,000
0

140
120
100
80
60
40
20
0
2006

2007

2008

2010

2012

Auctioned Energy

2013

2014

2015

2016

US$/MWhGWh/Year

Figure 1: Energy Auctions 2006–2017.

2017

Nominal price offered

Source: Empresas Electricas (2018)
E N E RG Y M A R K E T S

In 2015, Chile’s total net installed electricity capacity was 19 874 MW, representing an increase of 5% from2014, with thermal power plants representing 58% of the total capacity. The remainder was accounted mainly
by hydropower and others (33% and 9%). Note that, in 2005, solar photovoltaic (PV) and onshore windtechnologies made no contribution to the total electricity capacity. Therefore, 10 years later in 2015, solar andwind generation started appearing, with low contributions of 3% and 5%, respectively.
In 2017, Chile's overall net installed electricity capacity was 23 232 MW, with thermal power plants
representing 54% of the total capacity, hydropower 29%, onshore wind 6% and PV 9% (the missing 2% isfrom contributions by other technologies).
Chile had two main electricity systems–the Greater Northern Interconnected System (SING) and theCentral Interconnected System (SIC), nowadays the interconnection between these two systems created a newnational electricity system (SEN). In addition, Chile has medium-sized electricity systems–the Aysén System,59

APEC ENERGY OVERVIEW 2017

CHILE

which covers the consumption of Region XI, and the Magallanes System, which supplies Region XII, as wellas two medium-sized electricity in Los Lagos Region (X) and in the Eastern Island (Region V).
All the above-mentioned systems provide a total of 33 097 km of transmission lines, where 220 kV lines
account for 51%, followed by 110 kV lines at 18% and 500 kV lines at 8% of the total.
OIL

Oil is the most dominant fuel in Chile, accounting for 42% of TPES and 55% of total final consumption(excluding non-energy). Domestic production accounted for less than 2% of the supply (234 million cubic
metres) and the rest was imported.
Considering the low domestic production, nearly all of Chile’s crude oil supply (15 294 ktoe) in 2015
came from imports, which also included by-products such as diesel, gasoline and liquefied petroleum gas (LPG)(EGEDA, 2017). In fact, Chile heavily relies on imports to satisfy its oil demand; 47% of the imported crude
oil comes from Brazil, followed by 28% from the US and the rest from other countries.
From 2007 to 2008, oil consumption faced an abrupt increase, driven by the need to compensate thecurtailment of natural gas imported from Argentina. Nevertheless, the share of oil was about 53% in 2007 anddecreased to 42% in 2015 due to the increase in renewable energy and coal.
The transport sector is the largest oil consumer, accounting for 58% in 2015 (Ministerio de Energia,
2017). Road transport consumes 84% of the total oil products, followed by air transportation at 12%.
Industry is the second-largest oil consumer, accounting for 27% in 2015, and its consumption has
increased by 76% over the past decade. Mining is the largest oil-consuming industrial sector.
NATURAL GAS

Natural gas is the fourth dominant fuel used in Chile, accounting for 11% of TPES and 5.6% of total final
consumption (excluding non-energy). Domestic gas production accounts for 23% of the primary energy
supply.
Considering the low domestic production, nearly all of Chile’s natural gas supply (3 980 ktoe) in 2015
came from imports (EGEDA, 2017). In fact, Chile heavily relies on imports to satisfy its gas demand, where
72% of the imported natural gas comes from Trinidad and Tobago, followed by the US at 17% and the rest
from other countries.
In 1997, Chile imported exclusively from Argentina. By 2004, gas supply hit a peak of 7 011 ktoe and fell
to a low of 2 108 ktoe in 2008. The so-called ‘gas crisis’ had started and Argentina began restricting the supplyof natural gas. After this crisis, a group of private and public Chilean companies worked together to build LNG
terminals to avoid dependence on its neighbour country. Quintero LNG was built in the Valparaiso region andMejillones LNG was built in the Antofagasta region. Mejillones LNG has a storage capacity of 175 000 m3(one tank) with a regasification capacity of 5.5 million m3/d, and Quintero LNG has a storage capacity of 334
000 m3 (two tanks) with a regasification capacity of 15 million m3/d (Ministerio de Energia 2018 c).
Industry is the largest gas consumer, accounting for 19% in 2015 (Ministerio de Energia 2017), followedby the service and residential sectors, which consume 16%.
Between May and August 2016, Chile supplied natural gas to Argentina, with a total flow of 360 million
cubic metres (mcm). Between May and June, 86 mcm were supplied through the Norandino gas pipeline andanother 274 million m3 between June and August through the GasAndes gas pipeline (Ministerio de Energia,
2018c).
COAL

Coal is the third dominant fuel in Chile, accounting for 20% of the TPES and 1.3% of total final consumption(excluding non-energy). Domestic coal production accounts for 29% of the primary energy supply.
Considering the low domestic production, nearly all of Chile’s coal supply of 7 165 ktoe in 2015 camefrom imports (EGEDA, 2017). In fact, Chile heavily relies on imports to satisfy its coal demand; 42% of theimported coal comes from Colombia, followed by Australia (29%) and the US (22%).

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APEC ENERGY OVERVIEW 2017

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By 2004, the coal supply was 2 704 ktoe, increasing to 4 403 ktoe in 2008. In fact, after the ‘gas crisis’,the increasing coal use for power generation helped to maintain the security of electricity supply and reduced
the use of expensive diesel fuel. In the last 10 years, the coal supply has increased by 165% (7 165 ktoe).
The industry sector is the largest coal consumer, accounting for 3.5% in 2015. In 2015, domestic
production accounted for 29% of the total supply (Ministerio de Energia, 2017).
RENEWABLES

Chile has abundant renewable resources, being the second dominant fuel contributing economy to the TPES,
with a total of 9 674 ktoe (27%) in 2015 and accounting for 15% of total final consumption (excluding nonenergy) (EGEDA, 2017). Chile’s primary supply of non-fossil energy in 2015 mainly consisted of biomass,solar, wind and hydropower. From 2005 to 2015, the renewable energy supply in the TPES grew by 36% (2554 ktoe).
In December 2017, the Ministry of Energy published the LTEP process, which detailed the vast untapped
potential for solar (PV and concentrated solar power), onshore wind, geothermal and hydro. PV potential was
estimated at 829 GW, concentrated solar power (CSP) at 510 GW, onshore wind power at 37 GW, geothermal
at 2 GW and hydropower at 6 GW. Note that the study defines these potential areas with electricity generation
potential based on renewable energy resources, which are based on the georeferencing and characterisation of
usable resources for renewable energy in consideration of some technical, territorial and environmental
constraints through the combined use of geospatial information (Ministerio de Energia, 2018d). Figure 2 below
shows the vast untapped potential for solar (PV and CSP), onshore wind, geothermal and hydro.
Figure 2: Potential renewable resources in Chile

Source: Ministerio de Energia (2018d)

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APEC ENERGY OVERVIEW 2017

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At the end of December 2017, Chile had an installed capacity of 4 110 MW of NCRE, with solar andwind representing 8% and 6%, respectively, and a total of 1 455 MW is under construction. The installedcapacity of NCRE represents 19% of the total (SING and SIC) installed capacity and 19% of the total systemgeneration (CNE, 2018b).
Table 6: NCRE units in operation and under construction
Energy Source

Operation (MW)a

BiogasBiomass
CSP
Geothermal
Hydro (<= 20 MW)
Solar PV
Wind
Total

56
410

Construction (MW)b

110
24
485
1 825
1 310
4 110

107
746
492
1 455

Sources: a CNE (2018b); b Ministerio de Energia (2018d)
ELECTRICITY SECTOR

One of the main economic foundations of the LGSE and its regulation is the promotion of competition in theelectricity sector in all activities wherever possible.
The analysis of the technical and economic characteristics of the generation, transmission and distribution
segments shows that a high degree of competition can be achieved in the generation segment due to its scarce
economies of scale. This is followed by the transmission segment, where the characteristic of natural monopoly
with important economies of scale is recognised but in which competition can be achieved through tenders oftransmission works. Finally, there is a distribution segment with clear natural monopoly characteristics that the
LGSE regulates exhaustively without leaving activities of this segment with competition rules, except whensuperimposed concessions that can eventually lead to limited competition are allowed.
The regulatory framework for Chile’s electricity supply industry is based on the principle of competitivemarkets for generation and supply. Private companies wholly serve the electricity market, while the government
remains a regulator, policy-maker and technical support to identify the requirements to meet the projecteddemand growth. The Ministry of Energy is the main governmental institution in charge of the energy sector in
Chile. The ministry supports its actions through the National Energy Commission (Comisión Nacional deEnergía or CNE) and the Superintendence of Electricity and Fuels (Superintendencia de Electricidad y
Combustibles or SEC). The CNE is a technical organisation that acts as a regulator of the Chilean Energy
Market, analyses prices, tariffs and technical norms that may affect energy production, generation, transportand distribution, and provides advice to the government through the Ministry of Energy in any field related tothe energy sector for its development. SEC monitors the compliance of legal regulatory requirements andtechnical standards.
In Chile, marginal cost pricing was adopted as a way to emulate competition so that the marginal costs
resulting from dispatch operate at minimum cost, which is done regardless of the ownership of the facilities
and the contracts’ purchase/sale of electricity, and allows the delivery of appropriate signals to producers andconsumers. This means that consumers, on one hand, receive electricity at the lowest possible price with thequality and safety of service established in the current legal regulations, and on the other hand, that thegenerators can obtain profit according to the risks they face.
In this way, the electricity market was organised with a dispatch of the generating units at minimum cost,
totally independent of the ownership of the facilities and the electricity purchase and sale contracts; with a spot
market price in which only generators and transmission companies participate and with a contract market inwhich all of the demand should be covered and in which generation companies, transmission companies,
distribution companies and unregulated customers or ‘free customers’ participate.

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APEC ENERGY OVERVIEW 2017

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Generation companies are defined as companies that own generation plants and whose energy istransmitted and distributed to final consumers. Generation companies sell their production to distribution
companies, unregulated clients or other generation companies, having the option to sell their surpluses to thespot energy market. The transmission system in Chile has open access, giving transmission companies the rightto impose the payment of tolls over the available transmission capacity. Finally, the distribution companies
operate under a ‘distribution public concession regime’ with service obligations and regulated tariffs for the
regulated customers. Chilean regulation defines regulated customers as those with a connected capacity of
below 500 kW. Those who have a connected capacity of over 5 000 kW can negotiate the energy price directlywith generation companies. Those who fall in between (500 to 5000 kW) can choose either regulated or
unregulated tariffs for periods of no less than four years.
Chile used to have four main separated electricity systems (CNE, 2018b):
SIC and SING had their own system operators, which were originally controlled by the largest generatorsand transmission companies in each system. Nowadays both systems are interconnected, conforming the
National Electricity System (SEN).
1.

2.

Greater Northern Interconnected System (SING – Sistema Interconectado del Norte Grande):a.

Serves the desert mining regions in the north and covers an area equivalent to 25% of Chile’s
continental territory, in which about 6% of the population of Chile lives;b.

Total installed capacity of 5 0288 MW, 84% thermal (45% coal, 35% natural gas and 5% oil anddiesel), 15% renewables (11% PV, 4% onshore wind) and one geothermal plant.

Central Interconnected System (SIC–Sistema Interconectado Central):a.

Serves the central part of the country and reaches about 92% of the population, with more than
70% of customers under a regulated tariff;b.

Total installed capacity of 17 603 MW, 45% thermal (13% coal, 17% natural gas and 15% diesel),
38% hydro, 8% PV, 7% onshore wind and 2% biomass.

Table 7: Units in operation, under construction and tender projects, 2017
EnergySourceBiogasBiomass
Coal
DieselFuel Oil
Geothermal
Hydro
LNG
Other
PV
CSP
OnshoreWind

Operation
(MW)a
56
410
4 746
2 854
142
24
6 645
4 961
95
1 825

Construction(MW)b

TenderProjects (MW)c

746
110

579

1 310

492

2,405

375
16

1,094
284

Total
(MW)
56
410
5 121
2 870
142
24
7 739
5 245
95
3 150
110
4 207

Total
23 0683 117
2 984
29 169Sources: a CNE (2018b) –unit in test are not considered in operation, b and c Ministerio de Energia (2018d)

The Aysén and Magallanes systems serve small areas in the extreme southern part of the country.
3.

Aysén: Total installed capacity of 62 MW; 57% diesel, 37% hydro and 6% onshore wind;

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APEC ENERGY OVERVIEW 2017

4.

CHILE

Magallanes: Total installed capacity of 104 MW; 98% thermal (82% natural gas and 15% oil) and 2%
onshore wind.

The construction of the interconnection between the two main systems of Chile (SING and SIC) wasstarted in August 2015, with an investment of USD 7 000 million. The new electric system would have a lengthof 3 100 km from Arica to Chiloe, supplying electricity to more than 97% of the national population. This
milestone came true on 21 November 2017, and will provide security to the system and lower the prices of theelectricity tariff. As a result, SEN was created with an independent system coordinator (CEN).
NUCLEAR ENERGY

In 1965, Chile created the Chilean Nuclear Energy Commission (Comisión Chilena de Energía Nuclear or
CCHEN) to address problems related to the production, acquisition, transfer, transport and peaceful uses ofatomic energy. CCHEN regulates, authorizes and supervises the national nuclear and radioactive facilities
catalogued as first category as well as the operators working on them. CCHEN also helps protects people andthe environment carrying out monitoring, surveillance, calibration, managing radioactive waste and providing
training in the radiological area. CCHEN operates the research reactor RECH-1 located in the Santiago
metropolitan region, which have been used for research, radioisotopes production and other civil purposes.
Its main duties are as follows:

To provide technical and legal advice to the government on nuclear issues related to energy and radiation;

To conduct research and development in peaceful uses of nuclear energy;To regulate, control and supervise nuclear facilities andTo undertake technology transfer and its applications.

Given the energy requirements of the Chilean economy, the use of nuclear energy has been subject toconcerted debate. In 2007, the Nuclear Energy Working Group was formed to study the feasibility of theimplementation and use of nuclear energy in Chile. This study concluded that according to international
experience and despite the risks of earthquakes faced by Chile and potential waste management problems,
nuclear energy is a viable option (MINREL, 2007).
In 2010, the study ‘Nuclear Electricity: Possibilities and Challenges’ (MINREL, 2007)stated that thedevelopment of nuclear energy in Chile should aim to close identified gaps: ‘… technological, institutional andfundamental knowledge such as complete geological information of the economy, modify the current legal andregulatory institutions, implement a plan to meet the human resources necessities and finalise othercomplementary studies’. The study also concludes that public approval is not only a fundamental requirement
but also the biggest challenge faced before considering nuclear power as an energy alternative. If these
problems are solved by the mid-2010s, the study estimates that nuclear power plants can be included as partof Chile’s energy matrix by 2024.
The Presidential Advisory Commission for Electricity Development was established in 2011. One of themain conclusions of a study undertaken by it is that nuclear power would be a ‘strategic insurance that would
ensure sustainable energy supply in the long term’. The study predicted that nuclear energy could become partof Chile’s energy matrix as early as 2030. In the National Energy Strategy 2012–30, the Chilean government
enacted a moratorium on nuclear energy to generate electricity (MMA, 2012).
In January 2015, the Government of Chile created the Nuclear Power Energy Committee, which prepared
the report ‘Nuclear Power Generation in Chile: Towards a Rational Decision’ (CCHEN, 2015). This reportagrees with a previous report from 2010 in that the economy must continue working to close the gaps inhibiting
the proper implementation of nuclear energy. Furthermore, the report states that the possibility of using nuclear
energy should not be discarded without a ‘rational and comprehensive analysis and considering all relevant
aspects of this technology and the feasibility of its use in Chile’. Finally, the report concludes that social approvalis crucial to start any project involving nuclear energy development in Chile.
Clearly, from the perspective of the Chilean government, despite the exclusion of nuclear energy fromthe final Energy Agenda in 2014, its possible use in the future has not been ruled out. In fact, the need for
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recognised. Energy 2050 notes that nuclear energy is not a short-term option for Chile at present and its uptake
depends on further research regarding security and economic rationality, as well as community acceptance.
For this reason, CCHEN has been appointed to conduct a process for developing the required
information in ways that a nuclear power option could be considered in the next review of energy policy, which
will take place in 2020. For accomplishing this task, the Strategic Development and Nuclear Power Office wascreated in CCHEN on March 2016 and resources were allocated for performing studies on the main relevant
topics.
ENERGY EFFICIENCYEnergy efficiency (EE) is among Chile’s priorities as it works towards achieving its key goal of enhancing its
energy security. These efforts also encompass the stabilisation of demand growth through EE measures.
In terms of EE, the Ministry of Energy is responsible for the development of policies and guidelines,
including the promotion and enhancement of economy-wide efficient energy use as a means of contributing
to the achievement of this goal. Furthermore, in pursuing these objectives, the Ministry of Energy entrusts theChilean Energy Efficiency Agency, which is responsible for implementing many of these policies by promoting,disseminating and implementing dedicated programs, opening new markets and exploring opportunities in thefield of energy efficiency and developing EE markets to recognise and reward leading EE companies. The
current goal is to foster the efficient use of energy as an energy resource. The government has established a
20% savings goal by 2025 after considering the expected growth in energy consumption for the economy.
The Energy Policy defines long-term goals by 2035 and 2050 in EE. These goals are organised in thefollowing 11 alignments:
 Forming a robust market of consultants and enterprises of energy services; Applying progressively energy management tools validated by competent entities;
 Using local available resources and exploiting the potential energy in the productive process; Efficiently incorporating EE standards in design, construction and conditioning; Promoting smart control systems and owning energy production in ways to apply to buildings withefficient solutions; Strengthening the efficient edification market and moving towards more productive and efficient
local markets; Improving EE of vehicles; Promoting more efficient transportation alternatives;
 Ensuring the availability of massive and clear information regarding rights and duties of consumers,
including alternative energies and methods;
 Designing, implementing and tracking of an energy education strategy jointly with the different
initiatives developed by the Ministry of Energy and related institutions; Developing professional and technical human capital for the production.
The agenda states short-term concrete activities to encourage EE, which considers measures to extend
the development of EE projects, including the continuity of the Action Plan on Energy Efficiency 2020,
published in 2012 (Ministerio de Energia, 2012). These measures are applicable to industry and mining,transport, buildings, end-use devices and heating.
Table 8: Chile’s action plan on energy efficiency, 2020

Industry and mining

TransportPromote energy management systems

Promote energy cogeneration

Encourage efficient technologies

Technical assistance in industry and mining projects

Improve EE standards for light- and heavy-duty vehicles

Use new transport technologies in heavy-duty vehicles

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Buildings

End-use devices

Heating

CHILE



Promote public transportation

Promote electric vehicles

Technical assistance in transport projects

Encourage efficient technologies



Improve thermal insulation in buildings without EE standards

Promote energy management in buildingsTraining to relevant actors in the construction chainPromote building labellingPromote EE in street lightingExtend appliance labelling

Establish minimum energy performance standard (MEPS)

Promote minimum lighting efficiency standards throw specificprograms focused in low income households

Encourage new technologies in the use of firewood

Improve firewood qualityImprove the knowledge in the regarding the correct use of
firewood and its process

Source: Ministerio de Energia (2012)

The government is implementing the Action Plan for Energy Efficiency 2020. Since 2012, theSuperintendent of Electricity and Fuels certifies security, emission levels and EE standards on firewood home
appliances, which have been part of the institutional framework for EE policies owing to the importance offirewood in residential consumption in Chile (Ministerio de Energia, 2012). In addition, the Chilean
government approved the Minimum Energy Efficiency Standards Act, which applied to refrigerators andlamps in 2014, in early 2017 to three-phase induction electric motors up to 10 horse-powers, as well as aminimum standard for air, conditioning systems and in late 2015, the government banned thecommercialisation of incandescent bulbs. New regulations on vehicle labelling, water heating and appliances
have also been approved.
The agenda also considers the implementation of programs focused on EE with subsidies for housing
thermal insulation, the promotion of energy efficiency in public buildings (especially hospitals until 2017,
currently extended to all public buildings), the replacement of public lighting with more efficient technologies
and massive campaigns to teach the proper use of energy to the population.
CLIMATE CHANGE

Chile became a signatory to the United Nations Framework Convention on Climate Change (UNFCCC) in
1992 and ratified the Kyoto Protocol in 2002. In December 2008, Chile published the National Action Planon Climate Change 2008–12, which assigns institutional responsibilities for adapting, mitigating andstrengthening Chile’s response to climate change (MMA, 2008). According to the results of vulnerability studies
conducted by the Ministry of the Environment (MMA in Spanish), the effects of climate change can besummarised as follows:

There has been a decrease of up to 75% in precipitation in some regions, a temperature increase of up to
1.5% and a decrease to 77% of the flow rate in some regions.



There is a marked reduction in the recorded population of a vast majority of species.

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

CHILE

Regions that are predominately small in area and have low levels of technological access show the greatest
vulnerability to climate change.

While Chile’s contribution to global carbon emissions is very low, at around 0.2% of the total CO2 emitted
globally in 2013 (WRI, 2017), its territory is highly vulnerable to the effects of climate change. Glacial melting,shifts in rainfall patterns, expanding deserts and greater frequency of El Niño weather patterns will have an
impact on the economy’s water supply, food production, tourism industry and migration, as well as on its
socioeconomic development and energy security. In this regard, Chile’s action plan identified hydroelectric
resources, food production, urban and coastal infrastructure and energy supply as the four most vulnerable
areas to climate change, where adaptation would be required.
To the date, nine sectoral Climate Change Adaptation Plans have been approved, the last one in February
2018 corresponding to the Energy Sector2.
The government’s National Determined Contribution (NDC) is to reduce greenhouse gas (GHG)
intensity by 30% by 2030, based on the 2007 levels. The NDC goals are established on intensity-based targets
in tonnes of CO2 emissions per unit of GDP. To reach the targets outlined in the INDC and to ensure thesustainability of Chile’s energy future, the government prepared its second National Action Plan for Climate Change
2017-22 (MMA, 2017). This plan contains the following action lines and objectives.
Table 9: National Action Plan for Climate Change 2017–22.
PLAN
Adaptation

Mitigation

Implementation means

Climate change at the regional andmunicipal levels

OBJECTIVESStrengthening the country's capacity to adapt to climate change, improving theknowledge of its impacts and the vulnerability of the country and generating
actions to minimise negative effects and take advantage of positive effects,
promoting economic and social development and ensuring environmental
sustainability.
Creating the enabling conditions for the implementation, compliance andfollow-up of Chile's GHG emission reduction commitments to the UNFCCC,
and to contribute consistently to the country's sustainable development andlow growth in carbon emissions.
Creating the enabling conditions to implement the climate change mitigation
and adaptation actions at a national and subnational level in the transversal
elements related to institutional and legal areas,, technology transfers, capacitybuilding and technical assistance, financing and international negotiation.
Developing the necessary institutional and operative elements and capacity
building to advance the management of climate change in the territory,
through regional and municipal governments, and incorporating all social
actors.

Source: MMA (2017)

In 2013, GHG emissions were 109 MtCO2-e, increasing by around 114% from 1990 levels and 19% since2010. The main GHG emitted was CO2 (79%), followed by CH4 (11%). The energy sector is the main emitter(77%), primarily due to the utilisation of coal in power plants and diesel in the transport sector (MMA, 2017).
The National Energy Policy 2050, includes goals to adopt the necessary mitigation and adaptation actions
to achieve a sustainable and clean energy sector and to help to achieve the emission reduction targets set in
Chile’s Nationally Determined Contribution. Regarding climate change, this policy is explicit in terms of setting
medium- and long-term goals. For instance, it states that this policy will contribute to the COP 21 commitmentof reducing the intensity of GHG emissions in Chile by 30% in 2030 compared to 2007 levels and commits
the implementation of a GHG Emissions Mitigation Plan for the energy sector and of a plan to adapt theenergy sector to the impacts of climate change. For 2050, it states that ‘GHG emissions of the energy sector
are consistent with international thresholds and national NDCs’.
2 This plan is currently being revised and edited.

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The Energy Sector Mitigation Action Plan (committed under the Energy Policy 2050), by the Ministry ofEnergy in collaboration with to other Ministries such as Transport, Economy, Mining, Housing, Environment,
among others, and with the support of the Partnership of Market Readiness (PMR) Policy Analysis Work
Programme, was approved in October 2017 by the Sustainability Ministries Council and its main goal is toaddress the energy sector’s share of responsibility in achieving the economy’s first NDC by proposing packagesof measures on relevant sectors such as electricity production, transport, industry and mining, as well as
commercial, public and residential.
Carbon pricing is important here, since, in combination with energy reform, it can provide important
incentives for clean technology investments, and therefore, for a transition to decarbonise the economy. In
this regard, the National Energy Policy states the analysis of other carbon pricing instruments to internalise
the environmental externalities associated with existing and future energy infrastructure. In this context, thepolicy explicitly notes that through the PMR initiative, in collaboration with the World Bank, economic andmarket-based instruments will be evaluated, such as emission trading systems (ETS or Cap & Trade), which
aim to reduce CO2 and other GHG emissions in the energy sector.
Embedded in the Energy Policy are the relevant related goals on renewables and energy efficiency, which
will have a great impact on reducing GHG emissions and achieving the economy’s commitments.
Additionally, in 2017, the Chilean government applied a carbon tax of USD 5 per tonne of CO2 emitted,
thus affecting thermal plants with an installed capacity equal to or greater than 50 MW. The increase in therelative price of electricity will promote the use of less contaminant energy sources, encouraging energy
consumers to implement energy efficiency measures and low-carbon technologies.
N OTA B L E E N E RG Y D E V E L O P M E N T S

In February 2016, it began to trade electricity with Argentina. As stipulated in Supreme Decree N° 7, July 2015,
the Ministry of Energy authorised the company, AES Gener S.A., to export electric power to Argentina. Chile
has a transmission line from Andes throw Salta in 345 kV, of 390 kilometres with a capacity of 350 MW. In
2016 Chile had exported approximately a total of 100 825 MWh (CDEC SING, 2016) and 36 MWh in 2017
(Coordinador Eléctrico Nacional [CEN], 2017).
Chile also exported gas to Argentina in 2017. The agreement between both governments establishes theexport of 5.5 million m3 of natural gas per day to Argentina between May and September and the export ofelectricity from the Chilean north to Argentina, from Mejillones, Chile to Salta, Argentina. This interconnection
will supply about 200 MW to the National Interconnected System in Argentina. The new law approved by the
Chilean Congress maintains current gas tariff freedom but sets a cap rate equivalent to the capital cost rate plus
a spread of 3%. The National Energy Commission shall review the capital cost rate every four years. When adistribution company exceeds the cap rate, tariff regulations and direct discounts to consumers will be applied.
The Gas Service Act was established in 1931 and has remained in force through 2016 with some modifications.
According to the Ministry of Energy, the current regulation is not adequate under the new gas scenario because
it does not considerThe pricing methodology and procedure;The method and procedure to assess companies’ rentability;

The method for calculating the fair capital cost rate (CCR); andA mechanism to settle disputes between the regulatory agency and gas distribution companies.

The interconnection between the two main systems of Chile (SING and SIC), with an investment of
USD 7 000 million, was completed on 21 November 2017. The new electric system will have a length of 3 100
km from Arica to Chiloe, supplying electricity to more than 97% of the national population. This milestone
will enhance security to the system and lower the prices of the electricity tariff. As a result, a national electricity
system (SEN) and an independent system coordinator (CEN) were created.

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REFERENCES

CCHEN. Energia Abierta. 2015.
http://dataset.cne.cl/Energia_Abierta/Estudios/Minerg/14.Generaci%C3%B3n%20Nucleoelectri
ca%20en%20Chile,%20Hacia%20una%20decisi%C3%B3n%20racional.pdf.
—. Uranium and Thorium Resources in Chile Prospection and Recovery Experiences. 2013.
www.unece.org/fileadmin/DAM/energy/se/pp/unfc_egrc/unfc_ws_IAEA_CYTED_UNECE_S
antiago_July2013/10_July/2_Orrego_Uresources_Chile.pdf.
CNE. 2018 a. https://www.cne.cl/tarificacion/hidrocarburos/.
— 2018 b. https://www.cne.cl/estadisticas/electricidad/.
EGEDA. APEC Energy Database. 2017. http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
El Mercurio. EMOL. 2018. http://www.emol.com/noticias/Economia/2016/02/02/786490/USGS-unpotencial-de-hidrocarburos-noconvencionales-en-Magallanes.html.
Empresas Electricas. Empresas Electricas A.G. 2018. https://www.electricas.cl/temasestrategicos/licitaciones/.
Energia Abierta. Balance Nacional de Energia. 2018 a. http://energiaabierta.cl/visualizaciones/balance-deenergia/.
INE. Instituto Nacional de Estadisticas, 2017 Estadísticas. www.ine.cl.
— 2018 CENSO. http://www.censo2017.cl.
Ministerio de Energia.
— 2012 Plan de Acción de Eficiencia Energética 2020.
www.amchamchile.cl/UserFiles/Image/Events/octubre/energia/plan-de-accion-de-eficienciaenergetica2020.pdf.
— 2018 a Energia 2050. http://www.energia2050.cl/es/.
— 2018 b Energia 2050. http://www.energia2050.cl/wp-content/uploads/2017/04/Informe-Seguimiento2016.pdf.
— 2018 c Division de Seguridad y Mercados Energeticos. http://energia.gob.cl/.
— 2018 d Planificacion Energetica de Largo Plazo. http://pelp.minenergia.cl/.
MINREL. Ministerio de Relaciones Exteriores - La Opción Núcleo Eléctrica en Chile. 2007.
www.minrel.gob.cl/minrel/site/artic/20110826/asocfile/20110826141156/informe_2_.pdf.
MMA. Ministerio de Medio Ambiente— 2008 Plan de Acción Nacional de Cambio Climático 2008-2012. www.mma.gob.cl.
— 2012 Estrategia Nacional de Energía 2012-2030. http://portal.mma.gob.cl/wpcontent/uploads/2014/10/3_Estrategia-Nacional-de-Energia-2012-2030_Energia-para-elFuturo.pdf.
— 2016 Segundo Informe Bienal de Actualización de Chile sobre el Cambio Climático. http://portal.mma.gob.cl/wpcontent/uploads/2016/11/2016_2IBA_CL.pdf.
— 2016 Plan de Acción Nacional de Cambio Climático 2017-2022. http://portal.mma.gob.cl/wpcontent/uploads/2016/04/Anteproyecto-PANCC-2017-2022-FINAL-2016-04-18.pdf.
UNCTAD. «United Nations Conference on Trade and Development.» Conference on Trade and Development—
World Investments Report 2015.
http://unctad.org/en/Pages/DIAE/World%20Investment%20Report/World_Investment_Report.aspx, 2015.

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USEFUL LINKS

Chilean Commission of Energy (CNE)—www.cne.cl
Chilean Energy Efficiency Agency (AChEE)—www.acee.cl
National Electric Coordinator—https://www.coordinador.cl/
Government of Chile—www.gobiernodechile.cl
Ministry of Economy, Development and Reconstruction—www.economia.cl
Ministry of Energy—www.minenergia.cl
Ministry of Environment—www.mma.gob.cl
Nuclear Energy Chilean Commission (CCHEN)—www.cchen.cl
National Energy Commission (CNE)—www.cne.cl
National Institute of Statistics (INE)—www.ine.cl
National Oil Company (ENAP)—www.enap.cl
Superintendence of Electricity and Fuel (SEC)—www.sec.cl

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CHINA
I N T ROD U C T I ON

China is one of the world’s most important emerging economies. It is located in north-east Asia and is borderedby the East China Sea, Yellow Sea, and South China Sea. Its population of 1.4 billion is approximately onefifth of the world’s population. China has a land area of approximately 9.6 million square kilometers (km2) withdiverse landscapes, which comprise mountains, plateaus, plains, deserts and river basins. Its total maritime area
is 4.7 million km2, and the length of its coastline is 32 400 km (NBS, 2017).
After reforming and opening up its economy in 1978, China entered a new period of high-speed growth.
Its entry into the World Trade Organization (WTO) in 2001 further contributed to its prosperity in the first
decade of the twenty-first century. In 2004, China overtook Japan as the leading Asian exporter. In 2009, China
surpassed Germany to become the world’s leading exporter. By 2016, China’s merchandise exports constituted
13.6% of the world’s merchandise exports (WTO, 2017). In 2015, China’s GDP was USD 18 230.91 billion(2010 prices and 2010 purchasing power parity [PPP]), with the primary, secondary and tertiary industries
constituting 9%, 40%, and 51%, respectively (EGEDA, 2017; NBS, 2017).
With its huge population and booming economy, China plays an increasingly important role in the world’s
energy markets. According to British Petroleum (BP), China’s energy consumption grew by 1.3% in 2016. This
was less than one-third of the 10-year average growth rate of 5.3% and the slowest annual rate of growth since1998 (BP, 2017). However, China remained the world’s largest energy consumer and constituted 23% of the
global energy consumption and 34% of the net global energy growth in 2016 (BP, 2017). Its per capita primaryenergy consumption, at 1.23 tonnes of oil equivalent (toe) in 2015, is far lower than that of most developed
economies and below APEC’s average of 1.66 toe (EGEDA, 2017).
China is relatively rich in energy resources, particularly coal. According to BP statistics published in June
2017, China had total proven coal reserves of approximately 244 010 million tonnes (Mt), total proven oil
reserves of 25.7 billion barrels and proven natural gas reserves of 5.4 trillion cubic meters (tcm) (BP, 2017). In
addition, China has 400 gigawatts (GW) of economic hydropower potential, more than any other economy.
Coal and oil resources have been utilised more extensively than natural gas and hydro for power generationand industrial development.
The reserves per capita of coal, oil and gas are well below the worldwide average levels. The limitationsof its energy reserves per capita force China to conserve its resources. From 2000 to 2015, the compound
annual growth rate (CAGR) of final energy consumption was 7.9% and the CAGR of GDP was 9.6%
(EGEDA, 2017).
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesc

Area (million km2)

9.6

Oil (billion barrels)

25.7

Population (million)

1 371

Gas (trillion cubic metres)

4.8

GDP (2010 USD billion PPP)

18 231

Coal (million tonnes)

244 010GDP (2010 USD PPP per capita)

13 295

Uranium (kilotonnes U)

272.5dSources: a EGEDA (2017); b NBS (2016); c BP (2017); d Recoverable resources, WNA (2017)
Note: Data for coal reserves is as of end 2016
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

China’s primary energy supply has expanded sharply since 2001. This expansion was mainly driven by rapid
economic growth, especially in energy consumption by heavy industry. In 2015, the total primary energy supply

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increased by 0.4% compared with that in 2014, reaching 2 898 million tonnes of oil equivalent (Mtoe), including
net imports and others. Most of the growth came from oil, natural gas, renewables and others, while theindigenous production decreased slightly compared with that in 2014. Coal was the dominant source,
constituting 68%, followed by oil (19%), renewables (6.4%), gas (5.9%) and others (1.5%) (EGEDA, 2017).
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

2 424 581 Industry sector

Net imports and others

485 141 Transport sector

Total primary energy supply
CoalPower generation (GWh)
1 018 791 Total power generation

5 814 573

252 625

Thermal

4 284 188

2 897 571 Other sectors

420 573Hydro

1 130 270

1 963 150 Non-energy

167 974

Nuclear170 789

1 691 989

Others229 326

Oil

535 193 Final energy consumption*

Gas

171 190Coal

652 230

Renewables

184 602

Oil

403 682

Others43 437

Gas

109 575

Renewables

27 653

Electricity and others

498 849

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.

China has been the world’s second-largest economy in terms of electric power generation capacity since1996. Its electric power industry experienced a serious overcapacity problem in the late 1990s, largely due tolower consumption after the closure of inefficient state-owned industrial units that were major consumers ofelectricity. Subsequently, however, a power supply shortage developed because of rapid economic expansion
after 2001. From 2000–15, electricity generation output increased quickly from 1 356 terawatt-hours (TWh) to
5 815 TWh, of which thermal power generation constituted 73.7% of the total power generation. In 2016,
installed generation capacity reached 1 650 GW (NBS, 2017).
The power supply structure has diversified, with wind power and nuclear energy generation increasing
rapidly. In 2016, total power generation in China was 6 142TWh. Thermal power constituted 72.2% (4434 TWh of the total generation); conventional hydropower constituted 19.4% (1 191 TWh); nuclear energy
constituted 3.5% (215 TWh); wind power constituted 3.9% (239 TWh); and photovoltaic (PV) constituted 1.0%
(61 TWh) (NBS, 2017).
FINAL ENERGY CONSUMPTION

Total final consumption in China reached 1 860 Mtoe in 2015, 0.8% higher than that in 2014. The industrial
sector was the largest consumer, constituting 55% of the total final energy consumption, followed by othersectors (including residential, commercial and agricultural) at 23% and the transport sector at 14%. The
remaining 9% was contributed by non-energy use (EGEDA, 2017). By energy source, coal constituted 39% of
the final energy consumption (excluding non-energy), followed by electricity and others (30%), oil (24%), gas(6.5%) and renewables (1.5%).
In the Thirteenth Five-Year Plan for energy development, China set its annual energy consumption
growth target at an average of 2.5% during 2016–20, 1.1 percentage points lower than the 3.6% during 2011–
15. As a result, the total energy consumption will be contained within 5 billion tonnes of oil equivalent by 2020.

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ENERGY INTENSITY ANALYSIS

China has reduced its energy intensity in the last two decades. Compared to 1990, the intensities of primaryenergy supply and total final consumption in 2015 reduced by 59% and 64% respectively. These are the biggest
reductions among the APEC economies. However, energy intensity is still very high, and there is a lot of room
for improvement (EGEDA, 2017).
In 2015, China eliminated more than 5.27 GW of backward thermal power plants, 49.7 million tonnes(Mt) of backward cement production capacity and 101.7 Mt of out-dated coal mining production capacity(MIIT, 2017). With these efforts, the intensity of total final consumption decreased by 5.7% from 2014 to2015. The government also introduced policies on energy structural optimization and overall energy efficiency
improvement in the industrial sector, contributing to a lower energy intensity from the industrial sector.
However, because of the booming economy and transportation needs, vehicle purchases remain high, which
has resulted in increased energy intensity in the transportation sector.
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)

Total primary energy supply

169

159

2014 vs 2015
–6.1

Total final consumption

108

102

–5.7

Final energy consumption excl. non-energy

99

93

–6.0

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSISAs a result of China’s policy support to promote clean energy and a more diversified energy structure, China’s
final energy consumption of modern renewables increased 5.0% from 2014 to 2015, the largest increase among
APEC economies. China’s traditional biomass consumption increased 5.5% due to economic development
and an increasing per capita energy consumption. To mitigate such increase, China has been working on
shutting down backward thermal power capacity and heavily polluted fossil fuel consumption terminals, suchas out-dated steel and cement production lines, China’s non-renewable energy consumption only increased by
0.13%. This is mainly due to declining coal consumption, despite the rapid increase in the consumption of oil
and natural gas between 2014 and 2015.
Table 4: Renewable energy share analysis, 2014 vs 2015
2014

2015

1 683 868

1 691 989

Change (%)
2014 vs 2015
0.48

1 565 083

1 567 181

0.13

Traditional biomass*

18 04419 032

5.5

Modern renewables*

100 740

105 776

5.0

6.0

6.3

4.5

Final energy consumption (ktoe)
Non-renewables (fossil fuels and others)

Share of modern renewables to final energy
consumption (%)

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal, and so on), including biogas and wood pellets, areconsidered to be modern renewables, although data on wood pellets are limited.

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P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

China’s energy consumption is growing rapidly in line with robust economic development and accelerated
industrialisation. Energy has become an important strategic issue for China’s economic growth, social stability,
and security. China aims to be a low-carbon economy. The structural transformation of energy is the key toeconomic restructuring, which is also an important indicator of social progress. Achieving the goal of a lowcarbon and orderly energy structure is the basis of China’s energy strategy.
During the Twelfth Five-Year Plan for National Economic and Social Development (2011–15), China
secured an annual GDP growth rate of 7.8% and an annual energy consumption rate of 3.6%. Further, theinstallation scale of hydropower, nuclear power, wind power and solar power has increased by factors of 1.4,
2.6, 4.0 and 168.0 fold, respectively. The Thirteenth Five-Year Plan for National Economic and Social
Development (2016–20) was approved by the National People’s Congress in March 2016 (NDRC, 2017a). It
has four major energy-related objectives:Enhance energy supply capability;

Make a breakthrough with key technology;

Greatly increase the share of non-fossil fuel consumption; andMake a breakthrough in the clean use of fossil fuels.

The Energy Thirteenth Five-Year Plan is a specification of the Master Plan for the energy sector, withmore detailed targets that will provide a better guide for policymaking, government spending and projectplanning in the sector. The State Council approved it in December 2016 and the National Energy
Administration (NEA) unveiled it in January 2017 (NDRC, 2017b). Clean and low-carbon energy will accountfor most of the newly added energy supplies during 2016–20. By 2020, China expects an annual energy
consumption of fewer than 5 billion tonnes of coal equivalent (tce) from 4.3 billion tce in 2015. This will ensurethat the average annual growth rate remains below 3% in the coming five years.
ORGANISATIONThe National Energy Committee is a high-level body that coordinates overall energy policies. The committee,
chaired by the premier, is in charge of formulating China’s energy strategy and deliberating on major issues inenergy security. In March 2013, the State Electricity Regulatory Commission (SERC) merged into the NEA
under the administration of the National Development and Reform Commission (NDRC). The NEA iscurrently composed of 13 departments and has an authorised staffing complement of 250 civil servants. It is
responsible for developing and implementing energy industry planning as well as industrial policies andstandards. In addition, it is in charge of administering the energy sector, which includes coal, oil, natural gas
and other forms of power such as nuclear energy and new and renewable sources of energy. The NEA has
also assumed responsibility for the Office of the National Energy Committee. The NEA has 6 regional
regulatory bureaus and 12 provincial-level regulatory offices overall. Formerly under SERC, this administration
takes the responsibilities of regulating local and state-owned energy enterprises. Some departments within the
NDRC also contribute to energy conservation and climate change issues.
In 2009, China established the National Energy Conservation Centre under the NDRC to provide
technical support to the government for the implementation of energy efficiency and conservation
management initiatives. Its main duties include energy efficiency and conservation policy research; theassessment of fixed asset investment projects; information dissemination; the promotion of technologies,
products, and new mechanisms; label management; and international cooperation in the field of energy
conservation.
LAW

The laws relating to energy in China include the Coal Law (issued in 1996 and revised in 2013), Electricity Law(issued in 1995 and revised in 2015), Renewable Energy Law (issued in 2005 and revised in 2009), Energy
Conservation Law (issued in 1997 and revised in 2007) and Environmental Protection Law (issued in 1989 and74

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revised in 2014). The Energy Law is a comprehensive legal basis for the energy sector and is currently underconsideration. The Standing Committee of the National People’s Congress endorsed the amended version of
the Renewable Energy Law on 26 December 2009, which originally took effect on 1 April 2010. It more clearly
defines the responsibilities of the power grid and power generation enterprises. It also emphasises thecompletely secure purchase of power from renewable energy sources and the establishment of a development
fund for renewable energy. The amendment provides that power grid companies receive all of the revenue
generated from the surcharge on retail power tariffs. In addition, it sets a minimum target for the amount of
renewable electricity, which grid companies must buy from renewable energy projects (Qiu and Li, 2012).
The Oil and Natural Gas Pipeline Protection Law endorsed on 25 June 2010, went into effect on 1
October 2010. This requires that oil and pipeline companies take safety measures while constructing pipelines.
These measures include ensuring the quality of construction materials, conducting regular patrols of pipelines
and promptly eliminating any hazards.
The State Council approved the Regulation on Electricity on 15 February 2005. It became effective on 1
May 2005. This regulation clarifies the content and responsibilities of electricity regulation.
The State Council approved the Regulation on the Administration of Urban Gas on 19 November 2010.
It went into effect on 1 March 2011. This regulation clarifies the responsibilities and duties of gas operators,
unifies gas market management into a regular channel and sets the basis for local government activities.
ENERGY SECURITY

China has been endeavouring to guarantee itself and its industries long-term access to sufficient energy andraw materials. Currently, China’s energy portfolio mainly comprises domestic coal, oil, and gas from domestic
and foreign sources and small quantities of uranium. China has also created a strategic petroleum reserve tosecure emergency supplies of oil for temporary prices and supply disruptions. Chinese policy focuses on
diversification to reduce oil imports, which rely almost exclusively on producers in the Middle East.
On 13 June 2014, Chinese President Xi Jinping presided over the sixth meeting of the Leading Group
for Central Financial Work, stressing that energy security is a global and strategic issue related to economic andsocial development. To enhance China’s energy security, Xi Jinping proposed the promotion of a revolution
in energy production and consumption. This revolution is a long-term strategy and contains the following five
major requirements:

The promotion of an energy consumption revolution, which curbs irrational energy consumption.
This involves the firm control of total energy consumption; the effective implementation of an energysaving priority principle; energy saving throughout the whole process of economic and social
development and the adjustment of the industrial structure; significant emphasis on urban energysaving; the establishment of the concept of thrifty consumption; and the acceleration of the formationof an energy-saving society.



The promotion of an energy revolution and the establishment of a multi-supply system. This system
is based on domestic supply, with the goals of ensuring safety; vigorously promoting the efficient useof clean coal; focusing on the development of non-coal energy; forming a multifaceted coal, oil, gas,
nuclear, new energy and renewable energy supply system; and strengthening the energy transmission
and distribution network and storage facilities.



The promotion of an energy technology revolution and industrial upgrading. This is based on theeconomy’s conditions and follows the new trend of the international energy technology revolution.
The goals are guided by the principles of green, low-carbon energy; promote technological, industrial
and business model innovation; vigorously promote high-tech fields; and cultivate technology andrelated industries to upgrade the status of energy as domestic industry’s new growth point.

The promotion of an energy system revolution, which is achieved through fast-track energy
development. The goals are not to stagnate or retreat but to develop the revolution, thereby reducing
energy commodity attributes, constructing a market structure and system that have effective
competition, ensuring that the formation of the market structure and system is mainly determined by75

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the market mechanism of energy price, transforming government energy regulation and establishingand improving the energy law system.
All-round strengthening of international cooperation to achieve energy security in accordance withthe foregoing requirements. On the precondition that energy production is mainly domestic, theguideline sets forth to strengthen international cooperation in all aspects of the energy production andconsumption revolution and make effective use of international resources.

In the Thirteenth Five-Year Plan for Energy Development, energy security is set as a clear target. The
plan targets to keep China’s energy self-sufficiency rate above 80% by the end of 2020, which was 84% in 2015.
Since China’s crude oil supply and natural gas supply heavily depend on imports through pipelines or marinetransportation, the government expects to control China’s dependence rate on foreign oil and natural gas
through energy structure adjustment and efficiency improvement. APERC projects that China’s oil and natural
gas import will continuously increase in the next couple of decades due to the rapid increase in domestic
consumption and population growth. To achieve such goals during the Thirteenth Five-Year Plan, energy
supply-side reform and advanced fossil fuel geological exploration are considered as effective solutions. On theother hand, domestic shale gas, coal-bed methane, combustible ice utilisation and production developments
are also potential possibilities to decrease China’s energy dependence rate on foreign resources.
ENERGY MARKET

Energy market reform is a key driving force behind the acceleration of China’s move towards a market-based
economy. Therefore, the Chinese Government has promoted such reform in the past few years. The Chinese
Government has announced that the entire range of projects included in the National Energy Plan is open to
private investment, except where prohibited by laws and regulations. In 2010, the State Council issued a report
titled Several Opinions of the State Council on Encouraging and Guiding the Healthy Development of Private Investment. This
report encourages private capital to participate in the exploration and development of energy resources, oiland gas pipeline network construction, power plant construction, coal processing, energy conversion, therefining industry and a comprehensive, new renewable energy industry.
COAL MARKET

Owing to the abundant domestic reserves and low cost, coal has always been the primary energy fuel in China.
However, due to seriously deteriorating air quality in recent years, China has been stepping up its efforts to
reduce coal consumption to cope with air pollution issues and climate change.
In October 2013, several organisations, including government think tanks, research institutes, andindustry associations, jointly launched the China Coal Consumption Cap Project. This project aims to develop
a comprehensive roadmap and policy package to cap coal consumption.
In November 2014, China’s State Council launched the Energy Development Strategy Action Plan
(2014–20). This sets the target for capping coal consumption at no more than 4.2 billion tce, with the share ofcoal in primary energy consumption kept below 62%.
In November 2015, the China Coal Cap Project issued a report entitled the China Coal Consumption Cap
Plan and Research Report: Recommendations for the Thirteenth Five-Year Plan. This report presents recommendations
for controlling and reducing China’s coal use to below 3.8 billion tonnes and 3.4 billion tonnes by 2020 and
2030, respectively. In addition, the report recommends that the economy’s total energy consumption should
be at or lower than 4.7 billion tonnes of standard coal equivalent by 2020 and that the share of coal within
primary energy consumption during this period should be reduced to less than 57%.
China also began its ‘supply-side reform’ in recent years to cut unnecessary and outdated production
capacity. One of this reform’s target is to avoid overcapacity of supply in the coal mining industry. From 2015
to 2017, China shut down many small and inefficient coal mines and merged several private mines into stateowned enterprises (SEOs) to improve efficiency and control overall production.
Furthermore, in December 2015, the Chinese State Council pledged to upgrade coal-fired power plants
to cut pollutant discharge by 60% before 2020, thereby saving approximately 100 Mt of raw coal and reducing
carbon dioxide (CO2) emissions by 180 Mt annually. In addition, China aims to cut the total coal consumption
to below 65% of the total primary energy consumption by 2017 as part of an energy supply structural

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transformation (SCC, 2015). According to a statement by the NDRC, the NDRC targeted a capacity cut of
250 Mt for 2016, a reduction that was met ‘ahead of schedule’ in late November.
OIL MARKET

China surpassed the United States as the world’s largest oil importer in April 2015. According to Chinese
customs data, crude oil purchases from overseas reached a new record of 7.4 million barrels per day (Mbbl/D)
in April. This is approximately 7.7% of the world’s oil consumption per day and exceeds United States’ importsof 7.2 Mbbl/D. Larger shipments from Iran, Oman, and Abu Dhabi partly contributed to the soaring increasein oil imports in China.
Although China faces slowing economic growth, oil consumption is still rapidly increasing. Hence, its
state-owned oil traders, such as Unipec and China Oil, have been gaining increased visibility in the global crude
oil market.
However, with China’s high dependence on overseas oil imports of more than 60%, it must establish
strategic oil reserves to secure its energy supply. As of the middle of December 2015, China’s strategic crude
oil reserves had reached 26 Mt or approximately 191 million barrels. This occurred at a time of low oil prices.
Consequently, China has taken advantage of the lower prices to stockpile crude oil.
According to the Statistics Bureau, the reserves are stored in seven above-ground facilities in Zhoushan,
Zhenhai, Dalian, Huangdao, Dushanzi, Lanzhou and Tianjin and one underground facility in Huangdao, witha total capacity of 29 million cubic metres (mcm) (or approximately 180 million barrels) (FT, 2015; Reuters,2015).
NATURAL GAS MARKET

Natural gas has not been a major component of China’s primary energy supply. However, its share in theeconomy’s energy mix has been increasing rapidly. In the first half of 2015, the consumption of natural gas
was 91 billion cubic metres (bcm). This represented a rise of 2.1% from the same period in 2014 and was 5.5%of the energy mix. Production in the same period increased by 3.8% year-on-year to 66 bcm.
Securing a stable gas supply is one of China’s energy strategies. Thus, China has been encouraging thetransportation of gas from areas with significant resources (such as Western China, Russia, and Central Asia)
to East China, where gas consumption is high and an energy shortage is apparent.
China’s first west-east gas pipeline was built by the China National Petroleum Corporation (CNPC) andcompleted in October 2004. At 4 200 km, this is China’s longest natural gas pipeline, with one trunk line andthree branch lines. The pipeline has an annual capacity of 600 billion cubic feet per year (Bcf/y).
In August 2007, the CNPC announced proposals for a second west-east gas pipeline with a capacity of
1.1 trillion cubic feet per year (Tcf/y) and a length of more than 5 480 km, including the trunk line and eightmain branch lines. This natural gas pipeline now transports gas from Central Asia and Western China’s Xinjiang
Province to the south-eastern provinces. The western section of the line runs parallel to the first west-east gas
pipeline to Zhongwei in North-Central China. The eastern section transports natural gas from Zhongwei tosouthern Guangdong Province and Shanghai in the east.
To meet rising gas demand in China, the CNPC began constructing the third west-east gas pipeline witha capacity of 1.1 Tcf/y. The western section of the pipeline was launched in 2014. The eastern section was inoperation by the end of 2015. This pipeline runs parallel to the second pipeline for most of its length and ends
in the south-eastern province of Fujian (EIA, 2015; Primeline, 2015).
In addition, the NDRC announced a reduction in the wholesale price of natural gas for non-residential
users in November 2015. This lowers the gas price by an average of USD 0.1 (or approximately 28%) per cubic
metre. This reduction was prompted by the decrease in gas procurement costs following the fall in oil and gas
prices. It is also intended to make natural gas an alternative to coal for electricity generation. The NDRC
predicts total operational cost savings of CNY 43 billion for industrial users, power generation companies,
concentrated heating suppliers, taxi drivers, commercial entities, service providers and others in thedownstream market.

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The ‘shifting from coal to gas’ policy significantly impacts China’s natural gas market. Between 2015 and2017, NDRC and the Ministry of Environmental Protection jointly issued a series of policies to promoteresidential users and commercial enterprises to replace their coal-fired boilers and facilities with natural gasfired facilities to solve the serious air pollution during winter in the northern area of China. This caused a large
spike in demand for natural gas and the LNG prices tripled from October 2017 to December 2017, leading toa large-scale natural gas shortage across the whole economy.
To meet the rapidly rising demand for natural gas, China increased its LNG imports since the 2000s andbecame the second-largest LNG importing economy after Japan in 2017. In the recent decade, China invested
more money in LNG facilities, such as regasification stations, large-scale LNG marine carriers and LNG
terminals to expand its LNG import ability. These facilities are mainly concentrated along the eastern coastal
areas.
In addition, the NDRC has also announced that the gas pricing mechanism will be reformed byintroducing ‘benchmark city station gate prices’ for non-residential gas. These will replace the rigid ‘ceiling city
station gate prices’. The benchmark prices could either increase by up to 20% or decrease to the level decided
by suppliers and purchasers. On 1 Sept 2017, NDRC further lowered the city benchmark city station gate
prices of non-residential natural gas by 100 RMB/1,000 cubic metres. (NDRC, 2017c).
ELECTRICITY MARKET

The main objectives for electricity market development in the Thirteenth Five-Year Plan are to accelerate
structural reformation and innovation, transform to green energy and relax the regulations regarding electricity
supplies. To reach these objectives, there are five major strategies (CNSTOCK, 2015).


The innovation of the electricity market structure. In 2015, the Chinese Government finalised the‘Deepening Reform of the Power Sector’, a policy document co-signed by the Central Committee of
the Communist Party and the State Council to accelerate the innovation of the electricity market
structure. Further, an investment regime must be established by opening public bidding in a specificorderly manner, thereby developing innovation for the electricity market and its business model.



Coherent development. The development of the electricity market and economics in upstream anddownstream industries must be coordinated in a way that emphasises electricity consumption rather
than supply. The planning of the electricity market, regional strategy, transmission lines and energy
fuel allocation for peak hours must be strengthened.

Continuation of green development. The objectives are to continue increasing the share of non-fossil
fuels in power generation, optimise the energy mix for power generation with hydropower and nuclear
energy as the prioritised choices in the energy mix, promote green transformation in the power
generation structure and develop a low-carbon approach to secure a stable and economic supply ofelectricity in the long-term.

Continuation of the open market. Domestic and international resources and markets must be
combined to implement a ‘One Belt, One Road’ strategy, especially to export nuclear energy,hydropower, and thermal power to overseas markets.

Allocation concerning development. Trading in the electricity market must begin by establishing anelectricity market trade platform, enhancing the service level of the electricity industry and accelerating
the upgrade of the power distribution network.

Furthermore, on 30 November 2015, China announced reforms of its electricity sector to improve
competition in the marketplace. These reforms will end the monopoly of electricity distribution by SOEs. The
government will expand pilot programs related to the cost of building transmission lines, thereby allowing
electricity consumers to directly negotiate with electricity generators (OilPrice, 2015). In November 2015, theNEA issued a draft document called ‘Basic Rules for Electricity Market Operations’, which calls for expansionof longer-term markets based on contracting between generators on one side and large end users or retailcompanies on the other.
In summary, electricity market reform has mainly taken the form of expanded direct trading. This is partly
in reaction to pressure from large users for lower electricity prices. Given their interest in finding a use for

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excess capacity, coal-fired generators have also been supportive of the emphasis on direct trading. Policymakers
have proceeded cautiously so far, limiting the access of relatively inefficient end users, in line with China’s
longstanding policies on differential pricing.
China’s power sector has faced a severe overcapacity problem. Slowing demand for electricity due to theeconomic downturn and the slashing of energy-intensive industries have caused widespread under-utilisationof existing power generation capacities, which are seeing their lowest utilisation hours since 1978. The situation
has prompted regulators to consider putting a two-year ‘freeze period’ in the Energy Thirteenth Five-Year Planfor the approval of any new coal-fired power projects. The NEA promised to keep coal-based power capacity
below 1 100 GW by 2020, setting an upper limit for new coal capacity.
ENERGY EFFICIENCYIn June 2015, the Chinese Government announced its intention to develop an energy revolution that focuses
on reducing energy consumption, increasing energy supply and improving energy efficiency. With regard to
the energy efficiency improvement policy, there are two major strategies (USCBC, 2017).
Eliminate inefficient facilities. In May 2014, the NEA issued a notice called the ‘2014 Elimination of
Outdated Production Capacity for the Power Industry’. Shortly after this notice was issued, provinciallevel NDRCs launched implementation plans. Meanwhile, the central government has made plans todevelop large-scale power plants and combine heat and power stations to replace small power stations.
At the State Council executive meeting in June 2014, Prime Minister Li Keqiang stated that new coal
power plants would be prohibited in the Beijing, Tianjin and Hebei regions. Instead, large-scale coal
power plants in Central and Western China will play a more significant role in power production andtransmission.

Establish a market-oriented energy pricing mechanism. Energy inefficiency in China is mainly causedby governmental control of energy pricing and the monopoly of SOEs. To encourage competition
and weaken the power of SOEs, the Chinese Government will invite more private companies into thesector through a bidding process for power transmission, distribution and sales as part of the policy
reform.

On 23 April 2015, the State Council introduced 80 pilot projects to attract private investments toinfrastructure projects. These projects include hydropower, wind power, PV power, oil and gas pipelines,
energy storage facilities, the modern coal chemical industry and the petrochemical industry. The State Council
indicated that these projects would be put out to public tender to attract private capital through joint ventures,
sole proprietorship or franchise arrangements. With regard to the next step, the government will release more
projects from other sectors. These will include oil and gas exploration and water conservancy.
Carbon-trading schemes are also being used by the central government to promote market-based energypricing structures. Since October 2011, China has launched pilot carbon markets in two provinces (Hubei andGuangdong) and five cities (Beijing, Tianjin, Shanghai, Chongqing and Shenzhen). China is now preparing toroll out carbon markets on an economy-wide basis. Under the Draft National Regulation, the Chinese carbon
market will be a two-tier system where the applicable central government department will be responsible forregulating and supervising the Chinese carbon market at the economy level. The central government will
determine GHG categories, the scope of industries, and the criteria of the companies or entities that the
Chinese carbon market will cover. It will also approve, supervise and regulate the carbon exchanges. The local
governments will have primary responsibility for implementation and monitoring in their jurisdictions. On 19
December 2017, China formally launched the national carbon market, and the first phase of this market only
covers power stations.
RENEWABLE ENERGY

China’s renewable energy sector is growing faster than its fossil fuels and nuclear energy sector. In 2015, China
became the world’s largest producer of PV power at 43 GW installed capacity. China also led the world in the
production and use of wind power and smart grid technologies, generating almost as much water, wind, andsolar energy as all of France’s and Germany’s power plants combined.

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China will spend CNY 2.5 trillion (USD 361 billion) on renewable power development by 2020, according
to the latest strategy for the Thirteenth Five-Year Plan (2016–20). China’s goal of generating 20% of its energy
from non-fossil fuel sources by 2030 will require the installation of an additional 800–1 000 GW of renewableenergy, an amount which is equal to the current size of the entire US electricity grid.
WINDWind offers one of the greatest opportunities for renewable energy growth in China. During 2007–14, China’s
wind energy capacity increased nearly 25 times, growing from 6.0 GW to 148.6 GW, and it is expected tocontinue to grow. Since 2010, China has been the largest wind power producer in the world. In 2016, theelectricity generation output of wind reached 241 TWh, making it the third most popular energy source in theeconomy after coal (3 906 TWh) and hydro (1 150 TWh) (EGEDA, 2017).
In 2016, China added 19.3 GW of wind power generation capacity and generated 241 TWh of electricity,representing 4% of the total economy’s electricity consumption. Both China’s installed capacity and newcapacity in 2017 are the largest in the world by a wide margin, with the next largest market, the United States,
adding 8.2 GW in 2016 and having an installed capacity of 82.2 GW. By the end of 2016, China’s large-scalewind power capacity had reached 142 540 MW, which is 25.8% more than the previous year. China is estimatedto have 250 GW of wind capacity by 2020 as part of the government’s pledge to produce 15% of all electricity
from renewable resources by that time.
However, the wind power industry faces the challenge of wind power curtailment because of thelimitations of wind farms-grid connections and grid capacity. The abandonment of wind power has occurredin China since 2010 and reached a peak in 2012, with 21 billion kWh of wind power electricity. This constituted
just 17% of wind power electricity generated in that year, leading to a direct economic loss of CNY 100 billion.
In 2013, the situation improved because the wind power curtailment rate fell to 11% and decreased further to
8.5% in 2014. In 2016, the average utilisation of wind power in China was 1 742 hours, 14 hours morecompared with that in 2015; the abandoned wind power represented 49.7 billion kWh, with the average windabandoning rate being 17.1% (NEA, 2017).
SOLAR

The solar PV industry in China has long depended on subsidies and is expected to experience a crucial periodof transformation in 2016–20. Under the economy’s energy transformation policy, China’s solar PV industry
is changing towards intelligent manufacturing for stronger competitive advantages. This is because China is
endeavouring to accelerate energy technology innovation to construct a clean, low-carbon and high-efficiency
energy system.
In 2015, China’s installed solar PV capacity surpassed Germany and had the largest capacity in the world
at 43 GW (PV Magazine, 2016). Indeed, China has been the world’s largest market for solar PV since 2013,
when it had 17.5 GW.
In 2016, China added 34.4 GW of solar PV generation capacity, and China’s accumulated installedcapacity reached 77.4 GW, including 67.1 GW of centralised PV power plant capacity and 10.3 GW of
distributed PV. The total generation in 2016 was 66.2 TWh, constituting 1% of the economy’s power
generation.
In December 2016, NEA issued the Thirteenth Five-Year Plan for Solar Energy Development, setting a target
for installed solar power generation capacity of 110 GW by 2020, including 105 GW of solar PV capacity. The
basis of this target is that the economy will continue to expand solar PV generation during the 13th FYP period.
In addition, NDRC solicits opinions on reducing the benchmark on-grid price of electricity generated by windand solar PV power every couple of years. The opinions requested are those of local governments and powercompanies. The intention is that a lower price will help the industry to expand (Xinhua Finance Agency, 2015).
HYDRO

Hydropower is a significant part of China’s renewable energy mix. However, it cannot be scaled up indefinitely.
China is the world leader in terms of hydropower capacity. The installed capacity at the end of 2016 was 332.1
GW, including 26.7 GW of pumped storage, making it the economy’s single largest renewable power source
by far. Although China has set a goal to increase capacity to 350 GW by 2020, the potential for new large-scale

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hydropower capacity is limited. Thus, the proportion of hydropower in China’s renewable energy mix is likely
to decrease in the near future (EGEDA, 2017).
The pumped storage hydroelectricity industry has developed significantly in recent decades due to rapid
development in the modern renewable energy industry. The deployment location of pumped storage stations
are also becoming more diverse, new pumped storage stations are constructed near energy basements or supply
centres rather than demand centres to smooth the output of solar farms and wind farms or store energy during
the off-peak time. By May 2017, China’s installed capacity and under constructed capacity reached 27.73 GW
and 30.95 GW respectively, which are both the largest in the world. According to Hydro Power Development
Plan for 13th Five-Year Plan, China targets to have 40 GW of pumped storage capacity by the end of 2020.
NUCLEAR

Following Japan’s Fukushima Daiichi crisis in early 2011, China reviewed its nuclear plant safety requirements.
On 25 October 2012, the State Council approved new safety rules and a nuclear power development plan,
which prioritises safety and quality in Chinese regulations and sets a target of 58 GW nuclear capacity by 2020
(WNA, 2018). The Chinese Government has said that it will approve a small number of plants along the coastin accordance with new stricter safety rules, and no plants were approved for inland areas during the Twelfth
Five-Year Plan (2011–15) (NNSA, 2013). According to the Energy Development Strategy Action Plan 2014–
20, all new nuclear plants must meet the strictest world safety standards (SCC, 2014).
Because China is striving to reduce air pollution from coal-fired power plants, it is aiming to constructmore nuclear power plants. By the end of 2016, 38 nuclear power reactors were in operation with 19 underconstruction and more to be constructed. In 2016, the electricity generation output of nuclear was 213 TWh,which was approximately 3.6% of the total power generation. The installed capacity was 26 GW, which wasapproximately 1.8% of the total capacity. The year 2015 also saw the beginning of the greatest number ofnuclear power projects in a single year in China since the 2011 crisis, with eight new units being approved forconstruction.
No new nuclear projects were approved for construction in 2016. However, some projects were in theprocess of evaluation and were considered to start construction in the near term. These included the CAP1400
demonstrative project in Rongcheng City, Shangdong Province, and the second phase of AP1000 nuclear
reactors in Lufeng City, Guangdong Province; Sanmen City, Zhejiang Province; and Xu Dapu, Liaoning
Province.
China also significantly focuses on the next generation of nuclear power. In China’s nuclear development
plan, pressurised water reactors (PWRs) are to be the main type of nuclear reactor before 2030. Fourthgeneration reactors (high-temperature reactors, molten-salt reactors, gas-cooled fast reactors, sodium-cooled
fast reactors and lead-cooled fast reactors) which have improved operating safety features, will be available forcommercial construction in approximately 2030. Then, the fourth-generation reactors will gradually replace
the current PWRs. By 2040, new technology is projected to play an important role in China’s energy supply(World Nuclear, 2016).
In December 2012, the Shidaowan nuclear power plant in Shandong Province, as China’s first
demonstration-scale 4th generation nuclear power plant, restarted construction as the original plan wascancelled after the Fukushima Daiichi crisis in 2011. This high-temperature gas-cooled technology nuclear
power plant was projected to be completed and begin generating electricity at the end of 2017.
CLIMATE CHANGE

In June 2015, China submitted a climate action plan called the Intended Nationally Determined Contribution(INDC) to the Secretariat of the United Nations Framework Convention on Climate Change (UNFCCC). In
the action plan, China reaffirmed the bilateral climate deal agreement with the United States in November
2014. It also pledged to reach a total emissions peak by approximately 2030 and try its best to peak earlier.
Further, China committed itself to increase the share of non-fossil fuels in its energy mix to 20% by 2030.
China also announced two goals in addition to the November deal with the United States. These are to
reduce carbon intensity by 60% to 65% based on the 2005 level and restore approximately 4.5 bcm of forested

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land beyond the 2005 level. This is an important change because the economy is increasingly decoupling its
economic growth from greater growth in carbon emissions.
The cooperation between China and the United States on addressing climate change has injected
momentum into UNFCCC negotiations. In 2013, the United States and China also came to a joint bilateralagreement to work through the existing Montréal Protocol and UNFCCC mechanisms to reduce the use of
HFCs, which are potent greenhouse gases emitted through a variety of industrial processes.
In November 2016, China’s Greenhouse Gas (GHG) Control Work Plan and Power Sector
Development Thirteenth Five-Year Plan were issued, while its Ecological and Environmental Protection
Thirteenth Five-Year Plan was released later. Covering a comprehensive set of policies, these documents lay
out benchmark goals for 2020 that will put China on track to overachieve its 2030 Paris goals, strengthen
enforcement of environmental laws and standards and continue its transition to low-carbon energy.
N OTA B L E E N E RG Y D E V E L O P M E N T S
THE THIRTEENTH FIVE-YEAR ENERGY DEVELOPMENT PLAN (2016–20)

The year 2016 marks the beginning of China’s thirteenth five-year development period. In December 2016,
the NDRC and NEA finally unveiled the Thirteenth Five-Year Energy Development Plan (2016–20) (NDRC,
2017b). It includes a breakdown for the energy sector, with more detailed targets to better guide policymaking,government spending and project planning in the sector.
In the plan, China is determined to reduce coal’s share in the economy’s energy mix, lowering its 2020
percentage in primary energy consumption from 62% to 58%. China is also aiming towards more renewables:
the installed capacity of wind energy and solar energy should reach ‘more than 210 GW’ and ‘more than 110
GW’ by 2020, respectively. By 2020, the proportion of non-fossil fuels should rise above 15% from 12% in
2015. Natural gas should constitute at least 10% of the energy consumption.
STRUCTURAL CHANGE AND A GREEN LEAP FORWARD

To reduce GHG emissions and address air quality impacts, China needs to move its energy structure fromfossil fuel dominance to renewables and nuclear. A host of policies and regulations support China’s ambitious
push for renewables and encourage energy efficiency and domestic renewable energy deployment. China’s fiveyear plans have pursued an aggressive renewable energy policy, pushing for an increase in renewable energy
production to 15% of the total energy mix by 2020. In March 2015, China’s State Council announced a plan
to reform the power sector by improving the share of renewable energy in electricity generation, encouraging
competition and developing greater efficiency.
Heavy government investment and subsidies could be the key drivers for success with these goals.
According to the Statistics Bureau, China’s solar and wind energy capacity increased by 80.6% and 14.9%,
respectively, in 2016, while coal consumption dropped by 4.7%. China broke a new record in 2016, installinga record 34.5 GW of solar, including 4.2 GW of distributed photovoltaic power plants (a 200% incrementcompared with that in 2015) and 30.3 GW of centralised PV plants. Approximately 72% of these PV power
plants were constructed outside the north-west area, which is rich in solar energy.
China has implemented supply-side reform in coal mining and coal-fired power generation since 2015and has made significant progress in 2017. According to official data from the NDRC, China has eliminatedover 150 Mt of unnecessary coal mining capacity and 50 GW of outdated coal-fired power generation capacity
during 2017.
NEW ENERGY VEHICLESA proposal in the Thirteenth Five-Year Plan states that the Chinese Government will implement aneighbourhood electric vehicle (NEV) popularisation program. It will also upgrade the industrialisation levelfor electric car manufacturing to ensure the long-term development of China’s NEV industry. The proposal
expects that a market-oriented NEV industrial system will be developed by 2020. Further, an independent,
controllable and complete NEV industrial chain will be built. This NEV industrial chain will produce three
million NEV units each year.

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The proposal has three aims:


A greater than 80% share of the Chinese NEV market by domestically produced brands;

The placement of two Chinese vehicle enterprises among the world’s top 10 for NEV sales, withoverseas sales constituting 10% of the total sales; andAutomobile industry advances through NEV development, while foreign automobile makers remain
inactive in promoting NEV.

At the end of 2016, Shanghai was the top city in the world for ownership of NEVs, according to data
provided by the automobile registration department of Shanghai.
NATIONAL CARBON EMISSION TRADING SYSTEM

On 19 December 2017, the Chinese government launched the carbon emission trading system. This systemcovers about 1 700 coal-fired and gas-fired power generation enterprises, which emit over 26 000 tonnes of
CO2 per year and have emitted over 3 billion tonnes of CO2 (39% of the total economy). Although the firstphase of the system only covers the power generation industry, it is still the biggest carbon emission trading
system in the world (1.5 times that of the European Union Emission Trading System [EU ETS]). Furthermore,
the whole system needs about two years to optimise and test the trading system and establish the necessary
policies and regulations. Currency trading will begin in 2019. The early launch of China’s cap-and-trade system
is a promising start, and this action has a great opportunity to become a very powerful policy that will cut
carbon pollution cost-effectively and help China peak in its total carbon emissions before 2030.
INTERNATIONAL ENERGY COOPERATION UNDER ‘THE BELT AND ROAD INITIATIVE’

Under the ‘the Belt and Road Initiative’, China has conducted a series of energy cooperation initiatives withother economies. In April 2017, the Sino-Myanmar oil and natural gas pipelines, which connect the south-west
area of China with Myanmar, began operations. In April 2017, the southern Kazakhstan natural gas pipeline,
which will deliver over 5 bcm per year to China, completed construction. On 1 January 2018, an extension of
the East Siberia-Pacific Ocean oil pipeline between Russia and China started operations, doubling Russia-toChina export volumes from 15 Mt/a to 30 Mt/a (almost 220 million barrels/a).

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REFERENCES

BP (British Petroleum) (2017), BP Statistical Review of World Energy June 2017,https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review2017/bp-statistical-review-of-world-energy-2017-full-report.pdf.
China (2015), China Boosts Pricing Reforms in Natural Gas Sector, www.china.org.cn/business/201511/21/content_37123349.htm.
CNSTOCK (2015), 十三五电力规划：加快体制改革和绿色转型,
http://news.cnstock.com/news,bwkx-201512-3642518.htm
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
EIA (U.S. Energy Information Administration) (2015), China,
https://www.eia.gov/beta/international/analysis.cfm?iso=CHN.
FT (Financial Times) (2015), China Oil Imports Surpass Those of US, https://www.ft.com/content/342b3a2ef5a7-11e4-bc6d-00144feab7de.
MIIT (Ministry of Industry and Information Technology) (2017), Joint announcement of completion of theelimination of backward and excess capacity targets in various regions in 2015,
http://www.miit.gov.cn/n1146295/n1652858/n1652930/n3757016/c5276586/content.html
NBS (National Bureau of Statistics) (2017), http://www.stats.gov.cn.
NDRC (National Development and Reform Commission) (2017a), The 13th Five-Year Plan for Economic andSocial Development of People’s Republic of China
http://www.ndrc.gov.cn/fzgggz/fzgh/ghwb/gjjh/201612/P020161207635328170224.pdf.
–– (2017b), Thirteenth Five-Year Energy Development Plan (2016–20)
http://www.ndrc.gov.cn/gzdt/201701/W020170117348373245462.pdf.
–– (2017c), The notification of NDRC on reducing the benchmark city station gate price of non-residential natural gas,
http://www.ndrc.gov.cn/zcfb/gfxwj/201708/t20170830_859307.html
NEA (National Energy Administration) (2017), China’s Grid-connected Wind Power Data in 2016
http://www.nea.gov.cn/2017-01/26/c_136014615.htm
NNSA (National Nuclear Safety Administration) (2013), The Sixth National Report Under the Convention on
Nuclear Safety, http://nnsa.mep.gov.cn/gjhz_9050/gjgybg/201509/P020150918552267931130.pdf.
OilPrice (2015), China Reshapes Energy Sector, Shifts Towards Market Economy,
http://oilprice.com/Energy/Energy-General/China-Reshapes-Energy-Sector-Shifts-Towards-MarketEconomy.html.
Primeline (Primeline Energy Holdings Inc.) (2015), China Natural Gas Market,
www.primelineenergy.com/operations/china-gas-market.
PV Magazine (2016), It's Official: China Has the Most Solar PV Installed Globally, www.pvmagazine.com/news/details/beitrag/its-official--china-has-the-most-solar-pv-installedglobally_100022939/#axzz3yujhZPuB.
Reuters (2015), China's Strategic Oil Reserves Double to 190 mln bbl—Stats Bureau,
www.reuters.com/article/china-oil-reserves-idUSL3N1402YL20151211.
SCC (State Council of China) (2014), Energy Development Strategy Action Plan (2014-2020).
http://www.nea.gov.cn/2014-12/03/c_133830458.htm–– (2015), New Standard to Reduce Pollutant Emissions,
http://english.gov.cn/premier/news/2015/12/02/content_281475246642991.htm.

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USCBC (US-China Business Council) (2017), Three Reform Strategies behind Xi’s Energy Revolution,
https://www.uschina.org/three-reform-strategies-behind-xi%E2%80%99s-energy-revolution.
World Bank (2017), http://data.worldbank.org/indicator/NY.GDP.MKTP.PP.CD?locations=CN.
WTO (World Trade Organization) (2017), World Trade Statistical Review 2017,https://www.wto.org/english/res_e/statis_e/wts2017_e/wts2017_e.pdf
WNA (World Nuclear Association) (2017), Supply of Uranium,
http://www.world-nuclear.org/information-library/nuclear-fuel-cycle/uranium-resources/supply-ofuranium.aspx––(2018), Nuclear Power in China
http://www.world-nuclear.org/information-library/country-profiles/countries-a-f/china-nuclearpower.aspx
Xin Qiu and Honglin Li (2012), ‘Energy Regulation and Legislation in China’, Environmental Law Reporter, Vol.
42, September 2012.
http://xueshu.baidu.com/s?wd=paperuri%3A%2862c9a69ac8e03af55e5f931c8b566b6a%29&filter=sc_l
ong_sign&tn=SE_xueshusource_2kduw22v&sc_vurl=http%3A%2F%2Fpapers.ssrn.com%2Fabstract%
3D2145789&ie=utf-8&sc_us=11972000159231084251
Xinhua Finance Agency (2015), China to Speed Up Solar PV Development in 2016–2020,
http://en.xinfinance.com/html/13th_Five-year_Plan/Development_Policy/2015/168004.shtml.

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USEFUL LINKS

Central People’s Government of PRC—www.gov.cn
China Electricity Council (CEC)—www.cec.org.cn
Energy Research Institute of National Development and Reform Commission (ERI)—www.eri.org.cn
Ministry of Environmental Protection (MEP)—www.zhb.gov.cn
Ministry of Industry and Information Technology (MIIT) — www.miit.gov.cn
Ministry of Housing and Urban-Rural Development—www.mohurd.gov.cn
Ministry of Science and Technology—www.most.gov.cn
National Bureau of Statistics (NBS)—www.stats.gov.cn
National Development and Reform Commission (NDRC)—www.ndrc.gov.cn
National Energy Administration (NEA)—www.nea.gov.cn
National Nuclear Safety Administration (NNSA)—nnsa.mep.gov.cn
Standardisation Administration—www.sac.gov.cn
World Nuclear Association (WNA) —http://www.world-nuclear.org

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HONG KONG, CHINA

H O N G K O N G, C H I N A
I N T ROD U C T I ON

Hong Kong, China is a special administrative region of the People’s Republic of China. It is a world-classfinancial, trading and business centre comprising 7.3 million people and is located at the south-eastern tip ofChina. Hong Kong, China has no natural resources and completely relies on imports to meet its energy
requirements. The energy sector comprises investor-owned electricity and gas utility services.
In 2015, the per capita gross domestic product (GDP) of Hong Kong, China was USD 52 408 (2010
USD purchasing power parity [PPP]), the highest among the APEC economies. The GDP increased by 16%
in real terms to USD 383 billion after 2010 (2010 USD PPP). The service sector remained the dominant driving
force of the overall economic growth, constituting 89% of the GDP in 2015 (EGEDA, 2017). Hong Kong,
China is driven by its financial, higher value-added and knowledge-based services. To stay competitive andattain sustainable growth, Hong Kong, China needs to restructure and reposition itself not only in light of thechallenges posed by globalisation but also due to its closer integration with mainland China. The Mainland andHong Kong Closer Economic Partnership Arrangement (CEPA) is a manifestation of the advantages of ‘one
country, two systems’. As part of the liberalisation of trade in goods under CEPA, all products imported from
Hong Kong, China to mainland China enjoy tariff-free treatment.
With the support of mainland China under CEPA and the Framework Agreement on
Hong Kong/Guangdong Cooperation, Hong Kong, China is poised to reinforce and enhance its status as aninternational centre for financial services, trade and shipping, in addition to being an advanced global
manufacturing and modern services base. The central government has announced that it will actively liaise with
Guangdong to identify favourable treatment and implement opportunities for the people and enterprises ofHong Kong, China in the planning and development of Nansha, Qianhai and Hengqui. Furthermore, it will
increase the number of economic and trade offices in Asia to help business and investors tap Asian markets.
Moreover, the government has invited the submission of proposals to complement the National 13th FiveYear Plan (Policy Address, 2015).
Table 1: Key data and economic profile, 2015
Key data

Energy reserves

Area (km2)

1 104

Oil (million barrels)–

Population (million)

7.3

Gas (billion cubic metres)–

GDP (2010 USD billion PPP)

383

Coal (million tonnes)–

GDP (2010 USD PPP per capita)

52 408Uranium (kilotonnes U)–

Source: EGEDA (2017).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Hong Kong, China has no domestic energy reserves or petroleum refineries; it imports all of its primary energy
needs. A substantial share of imported energy is converted into secondary energy, such as electricity and gas,
for final consumption. The total primary energy supply in Hong Kong, China was 14 million tonnes of oil
equivalent (Mtoe) in 2015, 0.315 Mtoe lower than that in the previous year. Coal maintained the highest sharein the total primary energy supply (48%), followed by oil (24%), gas (21%) and other sources (7%) (EGEDA,
2017).

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In 2015, the total installed electricity generating capacity in Hong Kong, China was 12 645 MW (EGEDA,
2017). All locally generated power is thermal-fired. Electricity is supplied by CLP Power Hong Kong Limited(CLP Power) and the Hongkong Electric Company, Limited (HKE). CLP Power supplies electricity from its
Black Point (2 500 MW), Castle Peak (4 108 MW) and Penny’s Bay (300 MW) power stations. Natural gas andcoal are the main fuels used for electricity generation at the Black Point and Castle Peak power stations. CLP
Power has arrangements with China National Offshore Oil Corporation and PetroChina International
Company to procure gas supplies from the mainland. CLP Power has commenced constructing a 550 MW
gas-fired generation unit at Black Point Power Station, thereby aiming to commission the unit before 2020. It
is proposing to construct an offshore LNG terminal in Hong Kong waters to enable direct access to a rangeof gas sources from around the world and strengthen the reliability of its fuel supplies. HKE’s electricity issupplied by Lamma Power Station, which has a total installed capacity of 3 757 MW. Natural gas used at HKE’s
power station is mainly imported through a submarine pipeline from the Dapeng LNG terminal in Guangdong,
mainland China. HKE has also operated wind turbines (capacity 800 kW) since 2006 and a photovoltaic (PV)system (1 MW) since 2010 (CLP, 2015a; HKEI, 2015a, 2015b, 2015c).
While natural gas and liquefied petroleum gas (LPG) are the main types of gaseous fuels used in Hong
Kong, China, town gas serves as another fuel product. Town gas, which is locally manufactured using naphtha
and natural gas as feedstock, is being distributed by the Hong Kong and China Gas Company Limited(Towngas, 2016).
FINAL ENERGY CONSUMPTION

In 2015, the final energy consumption in Hong Kong, China was 6 760 kilotonnes of oil equivalent (ktoe), a
decrease of 1.6% from the previous year. The residential and commercial sectors constituted the largest shareof energy used (64%), followed by the transport sector (31%) and the industry sector (5%). By energy source,
electricity and ‘others’ constituted 56% of end-use consumption, followed by petroleum products (35%)(EGEDA, 2017).
Town gas and LPG are the main types of fuel gas used in the domestic, commercial and industrial sectors.
LPG is also used as fuel for taxis and light buses, while natural gas is used for electricity generation and town
gas production.
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe) Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

65

Industry sector

351

Net imports and others

30 331

Transport sector

2 100

Thermal

Total primary energy supply

14 059Other sectors

4 309

Hydro

2

Coal

6 694

Non-energy0

Nuclear

–

Oil

3 433

Final energy consumption*

6 760

Others

48

Gas

2 953

Coal

0

Renewables

71

Oil

2 334

Others

908

Gas

601

Renewables

44

Electricity and others

Total power generation

37 97137 921

3 781

Source: EGEDA (2017) (data collected in September 2017).
*Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This isdifferent from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid
waste used in power plants is assumed to be comprising renewables.
‘Total power generation’ does not include electricity generated by hydro and nuclear energy facilities located in themainland.

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HONG KONG, CHINAENERGY INTENSITY ANALYSISIn terms of primary energy or final energy consumption, the energy intensity of Hong Kong, China is thelowest among APEC economies. The primary energy intensity in 2015 was only 37 tonnes of oil equivalent
per million USD (toe/million USD) compared with the median value of 138 toe/million USD for APEC
economies, while the final energy consumption was only 18 toe/million USD compared with the median valueof 83 toe/million USD (EGEDA, 2017).
Hong Kong, China endeavours to achieve sustainable development and fully support APEC’s Honolulu
Declaration in 2011, seeking to reduce 45% of its energy intensity by 2035. To step-up energy efficiency andconservation efforts, various policies have been implemented. These include the Mandatory Energy Efficiency
Labelling Scheme, Energy Efficiency Registration Scheme for Buildings, Building Energy Efficiency Ordinanceand the Scheme on Fresh Water Cooling Towers (GHK, 2015a).
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

38

37

4.5

Total final consumption

18.4

17.7

3.9

Final energy consumption excl. non-energy

18.4

17.7

–3.9

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

Despite geographical constraints in developing renewable energy, the government has been implementing
various plans to develop its potential. Actions such as developing wind energy, floating PV farms and turning
various types of waste into renewable energy (RE) have already been taken to address the issue. In 2015, theshare of modern renewable energy to the total final energy consumption was approximately 0.68%. The
situation is expected to improve with the materialisation of various RE projects.
Table 4: Renewable energy share analysis, 2014 vs 2015

6 867

6 760

Change (%)
2014 vs 2015
–1.6

6 807

6 711

–1.4

Traditional biomass*

5

3

–29

Modern renewables*

55

45

–18

Share of modern renewables to final energy
consumption (%)

0.82

0.68

–17

2014
Final energy consumption (ktoe)
Non-renewables (Fossils and others)

2015

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal, and so on), including biogas and wood pellets, areconsidered to be modern renewables, although data on wood pellets are limited.

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P OL I C Y OV E RV I E W
E N E RG Y P OL I C Y F R A M E W O R K

The government of Hong Kong, China has four key energy policy objectives: to ensure that the energy needsof the community are met safely, efficiently and at reasonable prices, while minimising the environmental
impact on the production and use of energy (ENB, 2017a). The government also promotes efficient use andconservation of energy. In combating climate change, reducing greenhouse gas (GHG) emissions anddeveloping a low-carbon economy, Hong Kong, China’s emissions reduction strategy emphasises the wider
use of cleaner and low-carbon energies and fuels in power generation.
In keeping with the free market economic policy of Hong Kong, China, the government intervenes only
when necessary to safeguard the interests of consumers, ensure public safety and protect the environment. The
government works with the oil companies to maintain strategic reserves of gas, oil and naphtha. It monitors
the performances of the power companies through the Scheme of Control Agreements (SCAs). The current
SCAs were signed in 2008 and will expire in 2018. New SCAs were signed in April 2017 to promote quality
services, cleaner energy sources, energy efficiency and conservation. In addition, the new SCAs support further
development of RE to supplement conventional power generation as well as public awareness and public
participation (ENB 2017b, 2017c).
Specifically, Hong Kong, China proposes to optimise the fuel mix for power generation. In 2014, thegovernment conducted a public consultation on the future fuel mix for electricity generation in Hong Kong,
China to solicit the public’s views on the subject. Two fuel mix options were proposed for public consultation.
They were (i) to import more electricity through purchase from the mainland power grid and (ii) to use morenatural gas for local generation. Having considered the public’s views, the government plans to increase thepercentage of natural gas generation to approximately 50% by 2020 and maintain the current interim measureof importing 80% of nuclear output from the Daya Bay Nuclear Power Station so that nuclear imports would
constitute approximately 25% of the total fuel mix. Subject to public views on tariff implications, thegovernment is preparing to develop more RE and enhance efforts to promote energy saving. The remaining
demand will be met by coal-fired generation. This will help Hong Kong, China achieve the environmental
targets for 2020, including its target to reduce carbon intensity by 50–60% in 2020 compared with the 2005
level. Hong Kong, China will also endeavour to enhance energy efficiency, promote green buildings, advocate
electricity savings, facilitate low-carbon transport, reduce waste and develop facilities to turn waste into energy(ENB, 2015a).
A major target for the economy’s energy policy, as stated in the Energy Saving Plan for Hong Kong’s
Built Environment 2015~2025+ unveiled in 2015, is to reduce its energy intensity by 40% by 2025 based on
the 2005 level. The actions are as follows:Promoting energy saving and green building development by enhancing the green performance ofgovernment buildings, public housing and public sector developments;

Conducting periodic reviews to expand and/or tighten relevant energy-related standards, including thestatutory requirements under the Buildings Energy Efficiency Ordinance, Building (Energy Efficiency)
Regulation and Energy Efficiency (Labelling of Products) Ordinance;Updating schools and public education programs and strengthening government energy saving efforts byappointing green managers and energy wardens and encouraging public sector institutions to save energy;and

Supporting community campaigns through government funding schemes and collaborating with key
energy consumers in the commercial sector to develop sector-specific campaigns to promote energy saving.
More importantly, the Secretary for the Environment is engaging environment leaders to accelerate green
building adoption in the private sector.

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HONG KONG, CHINAENERGY MARKETS

A memorandum of understanding (MOU) was signed by the Hong Kong, China Government and the National
Energy Administration of the People’s Republic of China on 28 August 2008. To ensure the prosperity andstability of Hong Kong, China, the central government of China will continue to support energy cooperation
between the mainland and Hong Kong, China over the long-term. This will include efforts to provide a stablesupply of nuclear electricity and natural gas to the economy. The intergovernmental MOU contemplates thedelivery of natural gas to Hong Kong, China from three sources:

Existing and new gas fields planned for development in the South China Sea;

A second west-to-east gas pipeline, transporting gas from Central Asia; and

An LNG terminal to be located in Shenzhen, mainland China.

The MOU also contemplates the ongoing supply of nuclear-generated electricity to Hong Kong, China.
An extension of the Guangdong Daya Bay Nuclear Power Station joint venture and supply contracts wasapproved by the Hong Kong, China Government in September 2009. These contracts will enable thecontinued supply of non-carbon-emitting electricity to Hong Kong, China for an additional term of 20 years
from 2014. CLP Power has successfully negotiated an increase in the portion of electricity supply from the
Guangdong Daya Bay Nuclear Power Station to Hong Kong, China, increasing the plant’s generation from
70% to approximately 80% from late 2014 to 2018 (CLP, 2015b, 2015c).
ENERGY EFFICIENCY

Buildings consume approximately 90% of the electricity used in Hong Kong, China. Therefore, one of thegovernment’s first priorities is to conserve the energy used by buildings. Efforts are being made to improve
public awareness regarding energy efficiency to drive behavioural changes.
ENERGY DATA

To help monitor the energy situation, Hong Kong, China has developed an energy end-use database. The
database provides useful insight into the energy consumption situation, including the energy consumption
patterns, trends and usage characteristics of each sector and segment. A basic dataset is publicly available on
the Internet. The government is able to analyse the current system based on the data and develop policy andstrategy revisions for future implementation. The private sector can use the data to benchmark its own energy
efficiency when seeking improvements in its energy consumption systems (EMSD, 2017a).
BUILDINGS

To strengthen its efforts towards building energy conservation, the government has enhanced the regulatory
system for building energy efficiency. The Buildings Energy Efficiency Ordinance was fully implemented on
21 September 2012. The three key requirements of the ordinance are as follows (EMSD, 2012a):The developers or building owners of newly constructed prescribed buildings should ensure that the four
key types of building service installations (air conditioning, lighting, electrical and lift and escalator
installations) comply with the design standards of the Building Energy Code (BEC);When carrying out ‘major retrofitting works’, responsible persons of prescribed buildings (for example,
owners, tenants or occupants) should ensure that the four key types of building service installations
comply with the design standards of the BEC; andThe owners of commercial buildings, including the commercial portions of composite buildings, should
conduct an energy audit for the four key types of central building service installations in accordance with
the Energy Audit Code (EAC) every 10 years. The first energy audit should be conducted within four
years of the commencement of the ordinance in accordance with the timetable set out in Schedule 5 forthat ordinance.

The BEC is reviewed once every three years to meet public desire, international trends and the latest
technological developments. The first comprehensive review was completed in 2015, and the new standards
required a further 10% improvement in energy efficiency. It is estimated that up to 2025, energy savings from91

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HONG KONG, CHINA

all new buildings in Hong Kong, China will be approximately 5 billion kilowatt-hours of electricity, equivalent
to a reduction in carbon dioxide (CO2) emissions of approximately 3.5 million tonnes (Mt).
The government continues to utilise government buildings to demonstrate state-of-the-art energyefficient designs and improve energy conservation technologies. These are based on an environmental
performance framework that covers energy efficiency, GHG reduction, RE application, waste reduction, water
management and indoor air quality. All newly built government buildings over 10 000 square metres should
aim to obtain not lower than the second-highest grade under the Hong Kong Building Environmental
Assessment Method (HK-BEAM).
In April 2009, the government promoted a comprehensive target-based green performance frameworkfor new and existing government buildings and set targets for various aspects of environmental performance.
It has achieved the target of a 5% savings on the total electricity used in government buildings from 2009–10
to 2013–14 after discounting activity changes, using electricity consumption in 2007–08 as the baseline.
Building on this success, the government has set a new target of 5% savings in the electricity consumption of
government buildings in the next five years from 2015–16 to 2019–20 under comparable operating conditions.
This target uses electricity consumption from 2013–14 as the baseline.
In April 2009, the government introduced the Buildings Energy Efficiency Funding Schemes totalling
HKD 450 million to subsidise environmental performance reviews and upgrades for communal areas inresidential, commercial and industrial buildings. These schemes also cover energy/carbon audits andupgradation of the energy efficiency performance of building service installations. The subsidy can cover up
to 50% of the expenditures. These funding schemes were closed in April 2012 (EMSD, 2012a).
WATER-COOLED AIR CONDITIONING SYSTEMS

Water-cooled air-conditioning systems (WACS) using fresh water cooling towers are generally more energy
efficient than air-cooled systems. Examples of adopting the energy-efficient WACS in Hong Kong, China
include the WACS using fresh water cooling towers for individual buildings, WACS using seawater cooling forindividual buildings and the large-scale district cooling system (DCS) for numerous buildings (EMSD, 2015a).
The government has implemented a DCS in the Kai Tak Development to supply chilled water for
centralised air conditioning to buildings in the new development. The DCS is the first project of its kind
implemented by the government. It is an energy-efficient air-conditioning system as it consumes 35% and 20%
less electricity compared with traditional air-cooled air-conditioning systems and individual WACS using fresh
water cooling towers, respectively. The project is scheduled to be implemented in three phases: Phases I and
II were completed in 2013 and 2014, respectively, and the construction of Phase III commenced in 2013 andis expected to be completed by 2022 (EMSD, 2015c).
ENERGY CONSUMPTION INDICATORS

Since 2001, the government has commissioned the development of energy utilisation indexes andbenchmarking tools for the residential (six groups), commercial (32 groups) and transport (30 groups) sectors.
The tools assist stakeholders to compare the energy consumption performances of sectors and provide
applicable advice regarding energy conservation (EMSD, 2017b).
ENERGY EFFICIENCY LABELLING

Hong Kong, China has a voluntary Energy Efficiency Labelling Scheme that covers 22 types of household andoffice appliances, including 13 types of electrical appliances (refrigerators, washing machines, non-integrated
type CFLs, dehumidifiers, electric cloth dryers, room coolers, electric storage water heaters, televisions, electric
rice cookers, electronic ballasts, LED lamps, induction cookers and microwave ovens). The scheme also
includes seven types of office equipment (photocopiers, fax machines, multifunction devices, printers, LCD
monitors, computers and hot/cold bottled water dispensers) and two types of gas appliances (domestic
instantaneous gas water heaters and gas cookers). The scheme was extended to cover passenger cars runningon petrol (EMSD, 2015b).
To further assist the public in choosing energy-efficient appliances and raise public awareness regarding
energy saving, the government has introduced a Mandatory Energy Efficiency Labelling Scheme (MEELS)
through the Energy Efficiency (Labelling of Products) Ordinance, Cap. 598. The MEELS covers five types of92

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HONG KONG, CHINA

products: room air conditioners, refrigerating appliances, CFLs, washing machines and dehumidifiers. Under
the MEELS, energy labels must be displayed on the products supplied to Hong Kong, China to informconsumers regarding their energy efficiency performance (EMSD, 2012b).
TRANSPORT

Transport constitutes approximately 18% of the total GHG emissions in the economy and is the second mostsignificant contributor of emissions. To reduce carbon emissions from the transport sector, Hong Kong, China
has undertaken the following efforts (EPD, 2015).
EXTENSION OF THE PUBLIC TRANSPORT SYSTEM

An extensive and energy-efficient public transport system in Hong Kong, China is instrumental in helping
maintain low levels of GHG emissions. Approximately 90% of commuter trips are made each day via the
public transport system. The government is committed to further expanding and upgrading its public transport
infrastructure, with an emphasis on the railways.
PROMOTION OF CLEANER VEHICLESThe government actively promotes the wider use of electric vehicles. The first registration tax (FRT) for electricvehicles has been waived until the end of March 2017. The government liaised with electric vehicle (EV)manufacturers and dealers to encourage them to introduce EVs to Hong Kong, China; as a result, the economy
is one of the leading APEC economies in terms of EV use. The government has been working with the private
sector to expand the charging infrastructure for EVs in Hong Kong, China. There are approximately 1 500
different types of public EV chargers, including over 340 medium chargers and around 220 quick chargers.
The government’s ultimate policy objective is to have zero emission buses running throughout the
territory. As such, the government has allocated about HKD 213 million to fully subsidise the franchised bus
companies to purchase 36 single-deck electric buses and 6 double-deck hybrid buses for trial usage. If the trial
results are satisfactory, the government will encourage the franchised bus companies to use these green buses
on a larger scale, considering affordability for the bus companies and passengers.
CREATION OF THE PILOT GREEN TRANSPORT FUND

To encourage the public transport sector and non-profit organisations to test green and innovative transporttechnologies, the government set up a HKD 300 million Pilot Green Transport Fund in March 2011 (GHK,2015b). The government has been encouraging vehicle suppliers and technology companies to introduce moretransport means and related technologies. Furthermore, it encourages the transport sector to carry out trials
with subsidies from the fund. At the end of February 2016, 87 trials have been approved under the fund,including 67 electric commercial vehicles (taxis, light buses, buses and goods vehicles), 63 hybrid commercial
vehicles (goods vehicles and light buses), one solar air-conditioning system and four electric inverter airconditioning systems. Additionally, a ferry was retrofitted with a diesel-electric propulsion system and aseawater scrubber.
PROMOTION OF BIODIESEL AS A MOTOR VEHICLE FUEL

Since 2007, the government has adopted a duty-free policy for biodiesel to facilitate the use of biodiesel inmotor vehicles. In 2010, it introduced regulatory controls for motor vehicle biodiesel to help safeguard its
quality and encourage drivers to use it.
RENEWABLE ENERGY

Despite the geographical and natural constraints in developing wind energy, both power companies (CLP
Power and HKE) have started to explore the feasibility of offshore wind farm projects.
CLP Power is currently conducting a feasibility study for an offshore wind farm. An offshore
meteorological wind mast was installed to collect site environmental data. CLP Power completed theinstallation of an RE power system of approximately 200 kW on Town Island in late 2012. The system now
comprises 672 solar panels and 2 wind turbines supplying RE to the island.
The RE assets of HKE also performed well, with Lamma Winds generating an average of 800 to 1 000
megawatt-hours (MWh) of electricity since being commissioned in 2006. A thin-film photovoltaic (TFPV)

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solar power system of 1 MW was installed at Lamma Power Station, generating 1 100 MWh annually, offsetting
1 715 tonnes of CO2 emissions together with the wind turbines every year on average (HKEI 2015b, 2015c).
To increase its RE portfolio, HKE plans to install up to 33 offshore wind turbines, each being 3.0 to 3.6
MW with a total generation capacity of around 100 MW, producing 175 gigawatt-hours (GWh) of electricity
per year for the consumption of 50 000 four-person households. In 2012, HKE set up a wind monitoring
station at its offshore wind farm site to collect meteorological and oceanographic data for detailed design
purposes. Data collected indicate that the site is feasible for development of an offshore wind farm. Additional
data are being collected for optimising the offshore wind farm design (HKEI, 2015d).
Landfill gas, a waste gas produced at landfill sites, has been used as a waste-to-energy source for onsite
electricity generation and leachate treatment and for use by the town gas production plant (EPD, 2017a).
In 2007, landfill gas generated at the North East New Territories (NENT) Landfill was treated andtransferred to the town gas production plant to replace some of the naptha used as heating fuel. In 2016, theSouth East New Territories (SENT) Landfill Gas Treatment Plant was completed. Landfill gas is treated with
impurities, removed and converted to synthetic natural gas before being injected into the Towngas supply
network. It can offset 56 000 tonnes of carbon emissions per year, equivalent to planting 2.4 million trees(Towngas, 2016).
CLP Power is planning to develop Hong Kong, China’s largest landfill gas power generation project thatwould produce 10 MW of renewable power close to one of its power plants (CLP, 2016b).
The government has taken the lead in using RE by installing PV systems at various government premises.
More notable installations are a 1 100 kW system at the Siu Ho Wan Sewage Treatment Works, capable ofgenerating 1.1 million kWh annually, a 468 kW system at a swimming pool complex and a 350 kW system on
the roof of the Electrical and Mechanical Services Department Headquarters (DSD, 2016) (EMSD, 2017c).
The government also installed large-scale solar water heating devices on government buildings, including
those with swimming pools, to save power in heating water.
The government is studying the practicality of installing floating photovoltaic (FPV) systems on
reservoirs. Two pilot projects were commissioned in 2017, each having a capacity of 100 kW and capable of
120 GWh of electricity annually to power the equivalent of 36 households, with a reduction of 84 tonnes of
CO2 emissions. Data gathered will be used as reference for the future implementation of large-scale FPV farms
on reservoirs in Hong Kong, China (WSD, 2017). In its effort to convert waste to energy and to reduce GHG
emissions, the government has been planning and constructing several waste management facilities.
(a) Phase 1 of the Organic Resources Recovery Centre (ORRC) will be commissioned in early 2018. It
will treat 200 tonnes of organic waste per day for the production of biogas and compost. The biogas
produced will be used to generate electricity with about 14 million kWh of surplus electricity supplied
to the power grid per year, which is adequate for use by 3 000 households. This will contribute to a
reduction of 25 000 tonnes per year of GHG emissions via reduction in the use of fossil fuels forelectricity generation. Study on the second phase of the ORRC had already commenced in 2011
(EPD 2017b).
(b) The government is planning to construct an integrated waste management facility (IWMF). IWMF
Phase 1 can incinerate3 000 tonnes of mixed municipal solid waste per day and is capable ofexporting about 480 million kWh of electricity (about 1% of the total electricity consumption in
Hong Kong, China). This project can satisfy the electricity use of more than 100 000 households
and help reduce about 440 000 tonnes of GHG per year (EPD 2017c).
(c) Phase 1 of the Sludge Treatment Facility (STF) was commissioned in April 2015 and Phase 2 inApril 2016. The STF incinerates 1 200 tonnes of sewage sludge per day (2 000 tonnes by 2030). The
heat of the steam is converted to electricity by two 14 MW steam turbine generators to fully meetthe energy needs of the entire STF. When running at full capacity, approximately 2 MW of surplus
electricity is expected to be exported to the public power grid, enough to supply 4 000 households(EPD, 2017d).

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NUCLEAR ENERGY

Despite having no nuclear plant located within the territory, Hong Kong, China has been importing electricity
of nuclear origin from mainland China.
Currently, CLP Power is contracted to purchase around 70% of the electricity generated by the two
984 MW pressurised water reactors at the Guangdong Daya Bay Nuclear Power Station in mainland China tohelp meet the long-term demand for electricity in its service area. This arrangement meets 27% of the electricity
demand in Hong Kong, China. In September 2009, the government approved the extension of CLP Power’s
contract for the supply of nuclear-generated electricity from Guangdong Daya Bay Nuclear Power Station foranother 20 years, starting 7 May 2014. The extension of the contract ensures a continued supply of cleaner
electricity to Hong Kong, China, which will help alleviate air pollution and GHG emissions locally. To ensurethat cleaner and more cost-competitive energy is provided to Hong Kong, China, an agreement has beenreached wherein Daya Bay will increase its electricity supply from 70% of its output to approximately 80% by
the late stages of 2014–18 (CLP, 2016a, 2016b).
CLIMATE CHANGE

Hong Kong, China is committed to working closely with the international community to combat climatechange. The government is pursuing measures established in Hong Kong, China’s Climate Change Strategy
and Action Agenda (EPD, 2010) to reduce the territory’s carbon intensity 50–60% by 2020 compared with the2005 level. The government also published the ‘Hong Kong Climate Change Report 2015’ in November 2015,
which outlines the work and joint efforts of the government and key private sector stakeholders in responding
to climate change. It also provides an account of the economy’s climate change actions so that the public canhave a more complete picture of Hong Kong, China’s contributions to concerted global action.
The major contributors of GHGs in Hong Kong, China are the power generation and land transport
sectors, constituting approximately two-thirds and one-fifth of the territory’s GHG emissions, respectively. In
addition, energy consumption in buildings contributes approximately 90% of the total electricity consumption.
Therefore, the government is focussing on decarbonising the future fuel mix for power generation, enhancing
building energy efficiency and greening road transport to reduce carbon emissions.
The GHG emission reduction measures are classified in the following sections.
REVAMPING THE FUEL MIX FOR ELECTRICITY GENERATION

The government aims to increase the use of non-fossil, clean and low-carbon fuels for future electricity
generation. In 2015, the government proclaimed the fuel mix for 2020: to increase the proportion of natural
gas for power generation from around 20% in 2014 to around 50% in 2020, aiming at reducing the territory’s
carbon intensity by 50–60% by 2020, using 2005 as the base level.
MAXIMISING ENERGY EFFICIENCY

In particular, measures to improve energy efficiency in buildings include reducing the energy consumption of
air conditioning and other major electrical equipment. Specific measures include the following:

Expanding the scope and tightening the requirements of the BEC so that major electrical equipment in
all new commercial buildings will be up to 50% more energy efficient by 2020 compared with buildings
in 2005;



Expanding the use of district cooling or water-cooled air conditioning so that up to 20% of all commercial
buildings will have up to 50% better refrigeration performance by 2020 compared with buildings using
regular air conditioners;

Reducing energy consumption in new buildings by various means such as tightening overall thermaltransfer value standards and promoting the wider adoption of green roofing so that all new commercial
buildings will reduce their energy consumption by up to 50% by 2020 compared with new buildings in
2005;



Improving energy efficiency in commercial buildings through good housekeeping, information
technology products and intelligent building environmental management systems so that up to 25% of95

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HONG KONG, CHINA

existing commercial buildings will be 15% more energy efficient by 2020 compared with those in 2005;
and

Expanding the scope and tightening the energy efficiency of electrical appliance standards for domestic
use so that all major domestic appliances sold in the market will be 25% more energy efficient by 2020
compared with those sold in 2005.

GREENING ROAD TRANSPORT

These initiatives include measures to promote the use of electric vehicles and implement energy efficiency
standards for vehicles. Specific measures include the following:

Expanding access to public transportation, establishing pedestrian areas and covered walkways, and so on,
to reduce transport needs;

Promoting wider use of alternative fuelled vehicles such as hybrids and EVs;

Expanding railway networks and controlling the number of vehicles;Waiving the first registration tax on EVs until 31 March 2017;



Allowing enterprises to have 100% profit tax deductions for capital expenditures in the first year of EV
procurement;Implementing importers’ average fleet efficiency standards so that new vehicles will be 20% more energy
efficient than the 2005 market average; andPromoting the use of clean fuels (biofuels) for motor vehicles.

TURNING WASTE INTO ENERGY

These initiatives comprise measures to explore the potential of RE. Specific measures include the following:

Developing and operating one IWMF, one organic waste treatment facility and one STF; and

Utilising landfill gas and gas generated from wastewater treatment.

LONG-TERM CLIMATE STRATEGYWith the positive outcome of the twenty-first session of the Conference of the Parties to the United Nations
Framework Convention on Climate Change (UNFCCC), the government recognised the need to step-up
climate actions and draw up long-term policies. The Chief Executive announced in the 2016 Policy Address
the establishment of an inter-departmental committee (namely, the Steering Committee on Climate Change)
under the leadership of the Chief Secretary for Administration. The Steering Committee comprises members
from 10 policy bureaus and 2 departments. It seeks, among other things, to steer the overall direction of thegovernment in combating climate change, including the setting of post-2020 carbon reduction targets as well
as long-term climate strategies with regard to the UNFCCC and Paris Agreement.
N OTA B L E E N E RG Y D E V E L O P M E N T S
P U B L I C C O N S U LTA T I O N O N T H E F U T U R E D E V E L O P M E N T OF
THE ELECTRICITY MARK ET

The current SCAs between the government and the two power companies were signed in 2008 and will expire
in 2018. New SCAs were signed in April 2017. To plan for the way forward beyond 2020, the government
conducted a public consultation in 2015 to solicit public views on the future development of the electricity
market. More specifically, these include public views on the (a) introduction of competition, (b) future
regulatory framework and possible areas for improvement and (c) the development of RE and demand-side
management (DSM). The government has collated views from the public and will work out specific proposals
on future contractual arrangements before commencing negotiations with the power companies. Solicited
public views are summarised as follows (ENB 2015b):96

APEC ENERGY OVERVIEW 2017

HONG KONG, CHINAIntroduction of competition: The public held different views with regard to introducing competition. The
majority of the respondents considered that the current power supply in Hong Kong, China is reliable,
safe and affordable and that there is no need for introducing competition for expanding choices available
to the public. Some respondents considered that while choice had its merits, the requisite conditions for
introducing competition were not present at this stage.

Devising the future regulatory framework and delineating possible areas for improvement: Regarding theregulatory arrangement, almost all respondents considered that the current contractual arrangement by
SCAs had mostly worked well and allowed the economy to achieve the energy policy objectives. It was
generally agreed that improvements should be made to the current SCAs with respect to areas such as thelevel of permitted rates of return and mechanisms to promote energy saving and RE.

Development of RE: The community’s views on the development of RE were generally positive. Aroundhalf of the respondents supported the further development of RE despite its higher tariff implications.
Some respondents suggested that specific measures should be introduced to promote RE, such as
improving the grid access arrangements for distributed RE generators and encouraging their connections
to the power grids.

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HONG KONG, CHINAREFERENCES

CLP (CLP Power Hong Kong Limited) (2015a), Infrastructure & Fuel Mix, www.clp.com.hk/en/aboutclp/power-generation/infrastructure-and-fuel-mix.
(2015b), Extension of nuclear electricity supply,
https://www.clp.com.hk/en/Current%20Releases/20090922_Eng.pdf(2015c), Increasing Daya Bay offtake,https://www.clpgroup.com/nuclearenergy/eng/aboutus/aboutus1_2_1.aspx–– (2016a), Annual Report2016,
https://www.clpgroup.com/en/Investors-Informationsite/Documents/Financial%20Report%20PDF/e_2016Annual%20Report.pdf–– (2016b), Sustainability Report 2016, https://www.clpgroup.com/en/Sustainabilitysite/Report%20Archive%20%20Year%20Document/SR_Full_2016_en.pdf
DSD (Drainage Services Department, Government of the Hong Kong Special Administrative Region of thePeople’s Republic of China) (2016),
http://www.dsd.gov.hk/EN/What_s_New/What_s_New/news553.html.
EMSD (Electrical and Mechanical Services Department, Government of the Hong Kong Special
Administrative Region of the People’s Republic of China) (2012a), Buildings Energy Efficiency Ordinance,
www.beeo.emsd.gov.hk/en/mibec_beeo.html.
–– (2012b), Mandatory Energy Efficiency Labelling Scheme,
http://www.energylabel.emsd.gov.hk/en/mainpage.html.
–– (2015a), Water-Cooled Air Conditioning System,
https://www.emsd.gov.hk/en/energy_efficiency/water_cooled_air_conditioning_system/index.html.
–– (2015b), Voluntary Energy Efficiency Labelling Scheme,
https://www.emsd.gov.hk/en/energy_efficiency/voluntary_energy_efficiency_labelling_scheme/index.html.
–– (2015c), District Cooling System at Kai Tak Development,www.emsd.gov.hk/en/energy_efficiency/district_cooling_system_at_kai_tak_development/index.html–– (2017a), Hong Kong Energy End-Use Data,
https://www.emsd.gov.hk/filemanager/en/content_762/HKEEUD2017.pdf–– (2017b), Energy Consumption Indicators and Benchmarks,
https://www.emsd.gov.hk/en/energy_efficiency/energy_end_use_data_and_consumption_indicators/
energy_consumption_indicators_benchmarks/index.html–– (2017c), Government PV Installations,
http://re.emsd.gov.hk/english/solar/solar_ph/files/gov_pv_Apr2017.pdf
ENB (Environment Bureau, Government of the Hong Kong Special Administrative Region of the People’s
Republic of China) (2015a), Future Fuel Mix for Electricity Generation Consultation Document,www.enb.gov.hk/sites/default/files/en/node2605/Consultation%20Document.pdf.
–– (2015b), Public Consultation on the Future Development of the Electricity Market,
www.enb.gov.hk/en/resources_publications/policy_consultation/public_consultation_future_develop
ment_electricity_market.html.
http://www.enb.gov.hk/sites/default/files/en/node3428/EMR_condoc_e.pdf.
http://www.legco.gov.hk/yr15-16/english/panels/edev/papers/edev20151123cb4-217-3-e.pdf.
–– (2017a), Energy, http://www.enb.gov.hk/en/energy/index.html–– (2017b), SCA with HKEI,
http://www.enb.gov.hk/sites/default/files/en/node66/new_HKE_SCA_eng.pdf

98APEC ENERGY OVERVIEW 2017

HONG KONG, CHINA–– (2017c), SCA with CLP, http://www.enb.gov.hk/sites/default/files/en/node66/new_CLP_SCA_eng.pdf
EPD (Environment Protection Department, Government of the Hong Kong Special Administrative Regionof the People’s Republic of China) (2010), Hong Kong’s Climate Change Strategy and Action Agenda
Consultation Paper,
www.epd.gov.hk/epd/english/climate_change/files/Climate_Change_Booklet_E.pdf.
–– (2015), GHG Emission, https://www.climateready.gov.hk/files/pdf/HKGHG_Sectors_201612.pdf.
–– (2017a), Utilising Landfill Gas,
http://www.epd.gov.hk/epd/english/environmentinhk/waste/prob_solutions/msw_lgu.html–– (2017b) Organic Resources Recovery Centre,
http://www.epd.gov.hk/epd/english/environmentinhk/waste/prob_solutions/WFdev_OWTF.html–– (2017c), Integrated Waste Management Facilities,
http://www.epd.gov.hk/epd/english/environmentinhk/waste/prob_solutions/WFdev_IWMF.html–– (2017d), Sludge Treatment Facility,
http://www.epd.gov.hk/epd/english/environmentinhk/waste/prob_solutions/Sewage_Sludge.html
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
GHK (Government Hong Kong) (2015a), Energy Efficiency & Conservation,
www.gov.hk/en/residents/environment/energy/.
–– (2015b), Climate Change, www.gov.hk/en/residents/environment/global/climate.htm.
HKEI (HK Electric Investments) (2015a), Electricity Generation, www.hkelectric.com/en/ouroperations/electricity-generation.
–– (2015b), Lamma Wind Power Station, https://www.hkelectric.com/en/our-operations/lamma-wind-powerstation.
–– (2015c), Solar Power Station, https://www.hkelectric.com/en/our-operations/solar-power-system.
–– (2015d), Offshore Wind Farm, https://www.hkelectric.com/OffshoreWindFarm/introduction.
Policy Address (2015), www.policyaddress.gov.hk/2015/eng/.
Towngas (Hong Kong and China Gas Company Ltd) (2016), Utilising Landfill Gas,
http://www.towngas.com/getmedia/9bc8b39f-2517-4842-862a1fb2a82de91e/TGSD_FullReport_2016_en.pdf.aspx?ext=.pdf.
WSD (Water Supplies Department, Government of the Hong Kong Special Administrative Region of thePeople’s Republic of China) (2017), Floating PV on Reservoir,
http://www.wsd.gov.hk/en/home/climate-change/mitigating/floating-solar-power-system/index.html
USEFUL LINKSElectrical and Mechanical Services Department—www.emsd.gov.hk
Environment Bureau—www.enb.gov.hk
Environmental Protection Department—www.epd.gov.hk
The Hong Kong Government—www.gov.hk/en99

APEC ENERGY OVERVIEW 2017

INDONESIAINDONESIAI N T ROD U C T I ON

Indonesia is the world’s largest archipelagic state located south-east of mainland South-East Asia, between the
Pacific Ocean and the Indian Ocean. Indonesia’s territory encompasses 17 504 large and small islands andlarge bodies of water at the equator over an area of 7.9 million square kilometres (km 2). This constitutes
Indonesia’s exclusive economic zone. The economy’s total land area (25% of its territory) is about 1.9 million
km2. The population was around 258 million in 2015.
Indonesia had a gross domestic product (GDP) of around USD 2 622 billion and a per capita GDP of
USD 10 158 in 2015 (2010 USD purchasing power parity [PPP]). Indonesia is the largest economy in South
East Asia because of its robust economic growth since overcoming the Asian financial crisis of the late 1990s.
Indonesia’s sovereign credit ratings are classified into investment grade status by global leading credit rating
agencies such as Standard & Poor’s, Fitch Ratings and Moody’s Investors Service. The Indonesian
Government has been continuously making progress in deregulating its economy and removing barriers forinvestment, indicated by significant improvement of its rankings in the Ease of Doing Business index for 2018,
ranking seventy-second place, a significant increase of 19 places from ninety-first place in the previous year
(World Bank, 2017).
Indonesia has substantial and diverse energy resources from oil, natural gas, coal and renewable sources.
In 2016, Indonesia’s proven fossil energy reserves consisted of 3.3 billion barrels of oil, 101 trillion cubic
metres of natural gas and 29 billion tonnes of coal. Indonesia is one of the largest coal producers in the world.
Coal production reached 456 million tonnes in 2016, where 73% of the production was exported (ESDM,
2017d). Renewable energy sources include 29-gigawatts (GW) energy equivalent of geothermal, 75-GW energy
equivalent of hydro power, 208-GW energy equivalent of solar, 33-GW energy equivalent of biofuels and 61GW energy equivalent of wind power.
Domestic oil, gas and coal reserves have played an important role in Indonesia’s economy as sources ofenergy, industrial raw materials and foreign exchange. In 2014, oil and gas exports contributed 11% and coalexports contributed 5% of Indonesia’s total exports. Overall, tax and non-tax revenue from oil, gas andminerals, including coal accounted for 19% of the Indonesian Government’s budget in 2014 (ESDM, 2015a).
Table 1: Key data and economic profile, 2015
Key dataa

Energy reservesb, c

Area (million km2)

1.9

Oil (billion barrels)

3.3

Population (million)258

Gas (trillion cubic metres)101

GDP (2010 USD billion PPP)

2 622

Coal (billion tonnes)29

GDP (2010 USD PPP per capita)

10 158Uranium (kilotonnes U)

6.3

Sources: a EGEDA (2017); b ESDM (2015b); c NEA (2014).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

In 2015, Indonesia’s total primary energy supply (TPES) was 231 757 kilotonnes of oil equivalent (ktoe) ofcommercial energy, consisting of oil (36%), coal (22%), natural gas (16%) and other energy (mainlyhydropower, geothermal and biomass) (27%). Indonesia is a net exporter of energy; overall energy exports ofcrude oil, condensates, natural gas, liquefied natural gas (LNG), petroleum products and coal totalled 212
604 ktoe in 2015. Total energy exports in 2015 slightly decreased by 3.4% from 2014 (219 585 ktoe), a decrease
driven primarily by a decrease in the price of exported coal.

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INDONESIAOIL

In 2015, Indonesia produced 88 754 ktoe of crude oil and condensates. Of this, 17 584 ktoe (20%) was exported,
an increase of 2% compared to 2014. Because oil production has declined significantly over the past decade (in1997, Indonesia produced 72 474 ktoe of crude oil and condensates), the economy imported 20 893 ktoe of
crude oil and 28 534 ktoe of petroleum products in 2015 to meet its domestic oil requirements (EGEDA, 2017;
ESDM, 2015b).
Most crude oil is produced onshore from two of Indonesia’s largest oil fields: the Minas and Duri oilfields in the province of Riau on the eastern coast of central Sumatra. Because these fields are consideredmature, the Duri oil field in particular has been subject to one of the world’s largest enhanced oil recovery
efforts.
NATURAL GAS

Indonesia produced 67 294 ktoe of natural gas in 2015, a slight decrease of 0.5% from the 67 627 ktoe produced
in 2014 (EGEDA, 2017). Of the total natural gas production, 34% was converted to LNG for export. The
economy produced 23 045 ktoe of LNG in 2015, an increase of 4.6% from 21 976 ktoe in 2014. In 2015,
Indonesia also exported 9 billion cubic metres of natural gas through pipelines to Singapore and Malaysia.
Overall, 46% of Indonesia’s natural gas production was exported in 2015. The balance is made available fordomestic requirements (ESDM, 2015b).
Indonesia’s large natural gas reserves are located near Arun in Aceh, around Badak in East Kalimantan,
South Sumatra, the Natuna Sea, the Makassar Strait, the Masela Block in Maluku and Papua, with smaller gas
reserves offshore in West and East Java. LNG exports from Tangguh, Papua began in 2009 with gas supplied
from the onshore and offshore Wiriagar and Berau gas blocks, which are estimated to have reserves of
23 trillion cubic feet (SKKMIGAS, 2014).
COAL

In 2015, Indonesia produced 271 401 ktoe of coal, an increase of 1% from 269 361 ktoe in 2014. Most ofIndonesia’s coal production in 2015 (215 120 ktoe, or 79%) was exported. For domestic consumption (41 215
ktoe in 2015), the source is from power generation (56%) and industrial uses 30 898 ktoe (44%) (EGEDA,
2017; ESDM, 2015b).
Approximately 57% of Indonesia’s total recoverable coal reserve is lignite, 27% is sub-bituminous coal,
14% is bituminous coal and less than 2% is anthracite. Most of the economy’s coal reserves are in South
Sumatra and East Kalimantan, with relatively small deposits in West Java and Sulawesi. As a result, while
Indonesian coal’s heating value can range 5 000–7 000 kilocalories per kilogram, it is generally distinguishedby its low ash and sulphur content (typically less than 1%).
ELECTRICITY

Indonesia had 59 659 megawatts (MW) of electricity generation capacity in 2016. This was held by the stateowned electricity company (PLN) and independent power producers (IPPs). In 2015, 249 terawatt-hours ofelectricity was generated, of which 23% was supplied by IPPs and 1.5% was imported from Malaysia. In 2016,
several types of power plants produced electricity; namely, coal-steam power plants (51%), gas power plants(combined gas-steam power plants, gas turbine power plants and gas engine power plants) (27%), renewableenergy power plants (geothermal, hydro, biomass, solar and wind) (10%), and oil power plants (diesel power
plants and oil-powered thermal plants) (12%) (ESDM, 2017d).
FINAL ENERGY CONSUMPTION

Total final consumption was 171 724 ktoe in 2015, a slight increase of 1.4% from 169 269 ktoe in 2014. The
share of total final consumption by sector in 2015 was 26% for industry, 31% for transport, 43% for othersectors and 13% for non-energy consumption. By fuel source, oil consumption had the largest proportion in
final energy consumption (excluding non-energy consumption) at 41%, whereas renewable energy was thesecond largest at 33% final energy consumption (EGEDA, 2017).

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Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

445 243

Industry sector

39 098Net imports and others−212 064

Transport sector

47 380

Thermal210 240

Total primary energy supply

231 757

Other sectors

65 585Hydro

13 741

Coal

51 047

Non-energy

19 659

Nuclear0

Oil

82 534

Final energy consumption*

152 064

Others10 506

Gas

36 533

Coal

9 838

Renewables

61 642

Oil

61 7651Gas

13 163

Renewables

49 853

Electricity and others

17 445

OthersPower generation (GWh)
Total power generation

234 487

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
ENERGY INTENSITY ANALYSIS

In 2015, Indonesia’s primary energy intensity was 88 tonnes of oil equivalent per million USD (tonnes of oil
equivalent/million USD), a decline of 3.4% from previous year. This indicates Indonesia’s primary energy
intensity has improved in recent years; however, there remains scope for the economy to improve its energy
efficiency. In terms of total final consumption, energy intensity amounted to 65 tonnes of oil
equivalent/million USD, a decrease of 4.6% from 2014. This was mostly driven by decreasing energy
consumption in industry and transportation and other sectors.
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

EnergyChange (%)

2014

2015

2014 vs 2015

Total primary energy supply

91

88

–3.2

Total final consumption

68

65

−3.3

Final energy consumption excl. non-energy

61

58

–4.3

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

In 2015, renewable energy’s share in Indonesia’s final energy consumption was 51 657 ktoe, a slight decline of
0.2% from previous year. The share of modern renewables was 9 026 ktoe (17.5%) while traditional biomass
was 42 631 ktoe (82.5%) in 2015. This indicates Indonesia’s renewable energy development has improved inrecent years although there remains scope for the economy to accelerate the update of renewable energy in the
final energy consumption. On 2 March 2017, the Indonesian government issued Presidential Regulation No.
22/2017, regarding the General Plan of Energy that includes a policy target for achieving 23% renewableenergy sources in the energy mix by 2025. In 2017, the electricity generations from renewable energy was
accounted at 12.5% of the total electricity generation mix in 2017.

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Table 4: Renewable energy share analysis, 2014 vs 2015
2014
Final energy consumption (ktoe)

2015

Change (%)
2014 vs 2015

151 584

152 0640.3

Non-renewables (Fossils and others)

99 735100 407

0.7

Traditional biomass*

42 66842 631−0.1

Modern renewables*

9 181

9 026

−1.7

Share of modern renewables to final energy
6.1%
5.9%
−2.0%
consumption (%)
Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (e.g. hydro and geothermal energy), including biogas and wood pellets,
are considered modern renewables, but data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKTHE ENERGY LAW

On 10 August 2007, Indonesia enacted the Energy Law (Law No. 30/2007), which contains principles
regarding the utilisation of energy resources and final energy use, the security of supply, energy conservation,
the protection of the environment with regard to energy use, the pricing of energy and international
cooperation. It defines the outline of the National Energy Policy (Kebijakan Energi Nasional, or KEN); theroles and responsibilities of the central government and regional governments in planning, policy making andregulation; energy development priorities; energy research and development; and the role of businesses.
Under the Energy Law, the National Energy Policy addresses the need to have sufficient energy to meetthe economy’s needs, energy development priorities and the utilisation of indigenous energy resources andenergy reserves. The Energy Law mandates the creation of a National Energy Council (Dewan Energi
Nasional, DEN). The tasks of the DEN are as follows:

Draft the National Energy Policy (KEN);



Endorse the National Energy Master Plan (Rencana Umum Energi Nasional, RUEN);

Declare measures to resolve energy crises and energy emergencies; andProvide oversight on the implementation of energy policies that are cross-sectoral.

The President chairs the assembly of DEN members. As an institution, the DEN is headed by theminister responsible for energy affairs and has 15 members: seven ministers and high-ranking government
officials responsible for the supply, transportation, distribution and use of energy; and eight stakeholder
members from industry, academia, expert groups, environmental groups and consumer groups. The selection
and appointment of members of the DEN was finalised in 2014.
After obtaining approval from the parliament (the DPR) on 17 October 2014, the government issued the
new National Energy Policy under Government Regulation No. 79/2014. This replaced the existing National
Energy Policy, which was established by Presidential Regulation No. 5/2006. The new policy is intended tocreate energy security and resilience through an energy management strategy that will be implemented during
2014–50.

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INDONESIAThe RUEN implements the KEN. By law, the RUEN is drafted by the government, namely, the Ministryof Energy and Mineral Resources (MEMR), in a process that involves related ministries and other government
institutions, state-owned companies in the energy sector and regional governments. The process also includes
academia and other energy stakeholders and pays due regard to input from the public. To provide guidance on
how to draft the RUEN, the government issued Presidential Regulation No. 1/2014 on 2 January 2014. Under
this regulation, the RUEN should be prepared based on the KEN, engagement with local government andconsideration of public opinion and input. On 2 March 2017, the government issued Presidential Regulation
No. 22/2017 about RUEN that will be used by the central and provincial government as a guideline fordeveloping long-term electricity development plan and other relevant energy policies up to 2050.
ENERGY MARKETSOver the past decade, Indonesia has reformed its energy sector through a series of new laws: the Oil and Gas
Law (Law No. 22/2001); the Geothermal Energy Law (Law No. 27/2003, which was replaced with Law No.
21/2014); the Mineral and Coal Mining Law (Law No. 4/2009); and the Electricity Law (Law No. 30/2009).
These laws were established to promote an increased role for business in the energy supply chain. They
cover issues such as fair competition on an equal playing field as an alternative to a monopolistic industry,
direct contracts between energy producers and buyers and a transparent regulatory framework.
THE OIL AND GAS LAWIndonesia’s oil and gas industry was reformed in 2001 under the Oil and Gas Law (Law No. 21/2001). The
regulatory bodies BP MIGAS and BPH MIGAS were created to address oil upstream and downstream
activities. Exploration and production activities were conducted on the basis of a fiscal contractual system,
which relied mainly on production sharing contracts (PSCs) between the government and private investors.
Such investors could include foreign and domestic companies as well as the government-owned oil company
Pertamina.
However, on 13 November 2012, the Constitutional Court declared that the existence of BP MIGAS
conflicted with the Constitution of 1945 and ordered its dissolution. At the time of writing, the government
was drafting a new oil and gas law that will determine a new industry structure. Until the enactment of this law,
an interim working unit for upstream oil and gas business activities (SKSPMIGAS) has been established under
the MEMR to assume all BP MIGAS roles and responsibilities. Furthermore, on 14 January 2013, thegovernment issued Presidential Regulation No. 9/2013 as the umbrella regulation for the establishment of theworking unit for upstream oil and gas business activities (SKKMIGAS), whose responsibility is to manage theupstream oil and gas business in Indonesia.
BPH MIGAS has supervisory and regulatory functions in the downstream oil and gas sector. It aims toensure the availability and distribution of fuel throughout Indonesia and the promotion of gas utilisation in thedomestic market through fair and transparent market competition.
The enactment of the Oil and Gas Law required that the state-owned oil company, Pertamina, should
relinquish its governmental roles to the new regulatory bodies, BP MIGAS (which has now passed on its tasks
to SKKMIGAS) and BPH MIGAS and mandated the termination of Pertamina’s monopoly in upstream oil
and gas activities.
THE MINING LAW

On 16 December 2008, parliament passed a new law on minerals and coal mining to replace Law No. 11/1967,
which had been in place for 41 years. The government enacted the new law on 12 January 2009 as Law
No. 4/2009 on minerals and coal mining.
In essence, the new mining law ended the concession of work areas by contracts of work (COW) and bywork agreements for coal mining businesses known as Perjanjian Karya Perusahaan Pertambangan Batubara(PKP2B). Concessions are now based on permits issued from the central government and regional
governments.
Prior to the new law, the government arguably had less regulatory control over its concessions. For
example, any changes in the concession terms needed to be agreed upon by both the government and the104

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investor. By instituting permits, the government expects to be better positioned to promote investment andregulate mining.
The new law creates greater opportunities for smaller investments in mining and gives regional
governments a greater role in regulating the industry and its revenue. The mining law called for regulations on
the following:Concession areas and concession periods (for exploration permits) and production limits (forproduction permits) with regard to mining for metals, non-metals and specific non-metals;A requirement that prospective investors submit post-mining and reclamation plans before applying
for a permit;

An obligation for permit holders to build smelters;

An obligation for foreign companies to divest shares to the government or to state-owned
businesses and private companies registered in Indonesia;

Payment of taxes and fees and the allocation of profits; and

Reclamation and post-mining costs.

A set of government regulations with regard to the mining law was completed in 2010. These are now
operational.
THE ELECTRICITY LAW

In 2004, the Constitutional Court rejected an advanced reform of the electricity sector, which would haveestablished the possibility of direct competition in power generation through Law No. 20/2002 (currently
annulled).
On 23 September 2009, the government enacted Law No. 30/2009 regarding electricity. This new law
replaced Law No. 15/1985, which the Constitutional Court had reinstated in December 2004 as a provisionallaw upon annulment of Law No. 20/2002.
A notable difference between Law No. 30/2009 and Law No. 15/1985 is the absence of a holder ofelectricity business authority (Pemegang Kuasa Usaha Ketenagalistrikan, PKUK). Under Law No. 15/1985,
the government had appointed the state-owned electricity company, PLN, as the sole PKUK and consequently
had made it responsible for providing electricity to all parts of Indonesia.
Under the new electricity law, the industry consists of electricity business entities, which are title holdersof electricity supply business licences, or Izin Usaha Penyediaan Tenaga Listrik (IUPTL). The IUPTL integrates
electricity supply, power generation, transmission, distribution and retailing of electricity. Indonesia’s electricity
systems retain vertically integrated configurations. However, these consist of several licenced systems, such as
PLN’s numerous power systems, provincial government-owned systems (to be established, where necessary)and private sector power systems, each operating within their respective business areas. Licence holders ofspecific electricity supply types (such as the IPPs, which are licence holders in power generation for the supplyof electricity to the public) participate in the vertically integrated systems.
By law, the central government and regional governments regulate the electricity industry within theirrespective jurisdiction and through electricity regulatory authorities. The electricity law allows electricity tariffs
to be differentiated by region to allow for different costs of supply. Under the previous law, Indonesia had auniform electricity tariff regime and applied cross-subsidies among regions. At the time of writing, there wasno ruling as to whether PLN will implement tariff differentiation over its extensive power systems acrossIndonesia.
As mandated by Law No. 30/2009, the MEMR issued three government regulations (GRs), namely, GR
No. 14/2012 on electricity supply businesses activity, GR No. 42/2012 on the buying and selling of electricity
across Indonesia’s borders and GR No. 62/2012 on electricity support businesses.

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Geothermal development activities are defined as mining activities under the Geothermal Law No. 27/2003.
Furthermore, according to the forestry law, no mining activities are allowed to occur in protected forest areas(protection and conservation forests). Therefore, geothermal energy cannot be developed if it is located inthese areas. This situation has been a major barrier to developing geothermal electricity in Indonesia.
To remove the restriction to develop geothermal electricity in protected forest areas, the government
issued the New Geothermal Law No. 21/2014 on 17 September 2014. Under the new law, geothermal
development activities are not considered as mining activities because the government has changed the permit
scheme from that of a ‘geothermal mining permit’ to a ‘geothermal permit’. This new law states that geothermalenergy can be developed in production, protection and conservation forests after obtaining a permit from the
Ministry of Forestry under the category of the environmental service use permit.
The new regulation also states that the government sets the tariff on geothermal electricity. This approach
offers incentives to developers and affirms that central government holds the authorisation power to conduct
tenders for geothermal working areas (GWA) and to control the projects. However, local government isauthorised to utilise geothermal energy for direct use (other than electricity generation).
Geothermal exploration and exploitation are based on the awarding of licences. The process involves thecentral government offering GWA for competitive bidding to prospective business investors. Public, private
and cooperative entities may submit bids on such GWA and successful bidders are awarded licenses. The widthof the concession areas is determined according to the capacity of the individual geothermal system. Successful
bidders have the right to conduct exploration for five years with two extensions of up to one year each. They
also have the right to 30 years for exploitation from the date on which a feasibility study has been approvedby the government. The government can approve extensions for the exploitation of geothermal resources foran additional 20 years per extension approval. Working areas are subject to taxes, land rentals and royalties
determined by the government. Laws and regulations that govern the electricity industry apply to the utilisationof geothermal energy for electricity generation.
FISCAL AND INVESTMENT REGIME

In late 2008, Indonesia announced an overhaul of its taxation system, effective in 2009, with improvements to
tax collection and lower tax rates. The general corporate income tax rate for the 2009 tax year was reduced toa flat rate of 28% from the prior maximum progressive rate of 30%. Tax rates were to be further reduced to aflat rate of 25% in 2010 (ASEAN, 2008).
OIL AND GAS

The PSC regime (outlined in the earlier section on ‘The Oil and Gas Law’) was introduced in Indonesia in the
mid-1960s and reportedly became the fiscal system of choice for many economies over many years. Worldwide,slightly over half of those governments whose economies produce hydrocarbons now use the PSCs (Johnston,1994) and several types have since emerged internationally.
Technically, the PSCs do not have the type of royalty that applies to royalty/tax systems of concessions
or licences in the oil and gas industry. However, industry analysts argue that there are equivalent elements in
the PSC and royalty/tax systems and that the major difference is in the title transfer of oil or gas (Johnston, etal., 2008). In a PSC, title to the hydrocarbons passes to the contractor at the export or delivery point.
In 1988, Indonesia’s third-generation PSC introduced a new contract feature called ‘first tranche
petroleum’ (FTP). The contractor’s share of FTP is taxed and the remaining production is available for cost
recovery. Some industry analysts view FTP as a royalty (Johnston, 1994). Indonesia has other types of joint
contract schemes for oil and gas, such as technical assistance contracts (TACs) and enhanced oil recovery(EOR) contracts. A TAC is a variant cooperation contract or a PSC and is typically used for establishedproducing areas; thus, it usually covers exploitation only. Operating costs are recovered from production andthe contractor does not typically share in production. A TAC can cover both exploitation and exploration if it
involves an area where the Indonesian government has encouraged exploration. In accordance with the newoil and gas law, existing TACs will not be extended. In addition, participants in the PSCs, TACs and EOR

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contracts may also enter into separate agreements known as joint operating agreements and joint operating
bodies (JOB).
Since 2008, a fifth generation of PSCs have been introduced. The key differences between the PSCs of
the later generation and earlier generations are as follows:

Rather than a fixed production historical after-tax share, there is some flexibility in the productionsharing percentage offered;

PSC now provides for a domestic market obligation for natural gas;BP MIGAS is entitled to FTP of 10% of the petroleum production, which is not shared with thecontractor;



The profit-sharing percentages that appear in the contract are determined on the assumption thatthe contractor is subject to a dividend tax on after-tax profits under Article 26 (4) of the Indonesian
Income Tax Law, which is not reduced by any tax treaty;

Certain pre-signing costs (for example, seismic purchases) may be cost recoverable;BP MIGAS must approve any changes to the direct or indirect control of the entity; andThe transfer of the PSC participating interest to non-affiliates is only allowable with BP MIGAS’s
approval and where the contractor retains majority interest and operatorship, or three years after
the signing of the PSC (PwC, 2012). Note that BP MIGAS has since been handed over to
SKKMIGAS.

Indonesia revised the terms of the domestic market obligation in 2009. Under Government Regulation
No. 55/2009, the contractor must allocate 25% of its oil or gas share to the domestic market. In relation to
the development of new gas reserves, the government advises the contractor, on request, of the domestic gas
supply requirement about a year prior to production. The contractor and prospective domestic buyers negotiate
directly on gas price and terms of supply. However, if there is no domestic consumption for gas or if anagreement between the contractor and prospective buyers is not reached, the contractor may sell the entire
share to the international market.
THE GROSS SPLIT SCHEME

On 13 January 2017, the government issued Ministerial Regulation No. 8 of 2017 on production sharing
contracts. A gross split was enacted on 22 January 2017, which is a breakthrough scheme for the programmein the upstream oil and gas more efficiently and effectively so as to attract the investors (ESDM, 2017b). The
regulation includes the following:

The ownership of natural resources remains in the hands of the government until the point ofdelivery;Management control operations are at SKKMIGAS;

Capital and risks are borne by the contractor;

Gross split for oil is 57% government and 43% PSC;

Gross split for gas is 52% government and 48% PSC; and

For gross revenue share split, especially for oil and gas development in the deep sea, which is locatedin the eastern part of Indonesia where its infrastructure is underdeveloped, a different split will be
determined by the government.

On 29 August 2018, the government revised the Ministerial Regulation No. 8/2017 in response to the
feedback from the oil and gas industry association to provide fiscal incentive for the existing upstream oil andgas operators for Plan of Development (POD) Phase II.
Further to the issuance of Ministerial Regulation No. 8/2017 and its subsequent revision of Ministerial
Regulation No. 52/2017, the government introduced Government Regulation No. 53/2017 about Tax Rules
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for Gross Split PSCs. Government Regulation No. 53/2017 provides fiscal framework for gross split PSCs
that will be detailed into implementing regulations that, at the time of this writing, was still being prepared by
the MEMR through the revision of Ministerial Regulation No. 8/2017. Key features of Government
Regulation No. 53/2017 about Tax Rules for Gross Split PSCs are as follows:

An exemption from import duty on goods used in relation to oil and gas operations;

A 100% reduction in land and buildings tax;

Non-collection of value-added tax on the import and local procurement of goods and services usedin oil and gas operations;

An exemption from Article 22 on the import of goods entitled to an import duty; andOperating costs as a cost reduction component of the taxable income as a tax loss carry forward
entitlement is extended to 10-year period, greater than 5-year period under the general tax law;

It is evident that the introduction of regulations on gross split PSCs is accepted by the upstream oil andgas industry. On 31 January 2018, the government announced five winning bidders for upstream oil and gas
field development that will adhere to the gross split contract scheme as follows:Andaman I—Mubadala Petroleum (SE Asia) Ltd;Andaman II—Joint consortium of Premier Oil Far East Ltd, Kriss Energy (Andaman II) BV,
Mubadala Petroleum (Andaman II JSA) Ltd;

Merak-Lampung—PT. Tansri Madjid Energi;Pekawai—PT. Saka Energi Sepinggan; and

West Yamdena—PT. Saka Energi Sepinggan.
UPSTREAM

In 2014, the Directorate General of Oil and Gas, the MEMR signed seven new PSC agreements. Apart fromthese, the PSC under the control of the upstream oil and gas implementing agency—BP MIGAS (before
becoming SKKMIGAS)—numbered approximately 316 by the end of 2014. Of these 316 PSC, 81 were foroil and gas at the exploitation stage and 235 related to the exploration stage. Of the latter, 180 were forconventional oil and gas, 55 were for shale gas, 8 were terminated and 41 were in the termination process(SKKMIGAS, 2014).
To increase production of oil and gas, SKKMIGAS has developed the economy’s oil and gas in new
fields through a number of major projects, including the following (SKKMIGAS, 2014):
Banyu Urip—ExxonMobil Cepu Ltd;Indonesia Deepwater Development—Chevron Indonesia Company;Abadi—INPEX Masela Ltd;

Jangkrik dan Jangkrik North East—Eni Muara Bakau B.V.;

Bukit Tua—PC Ketapang II Ltd;

Ande-Ande Lumut— (Northwest Natuna) Pte Ltd;

North Duri Development 13 (NDD-13)—PT Chevron Pacific Indonesia;Corridor—ConocoPhillips Grissik Ltd;

Ruby—Pearl Oil (Sebuku) Ltd;



Kepodang—PC Muriah Ltd;

Donggi Senoro—JOB Pertamina-Medco Tomori; and108

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Tangguh Train 3—BP Berau Ltd.
KEROSENE TO LIQUEFIED PETROLEUM GAS CONVERSION PROGRAMMEIn December 2009, Phase I of the government’s kerosene-to-liquefied petroleum gas (LPG) conversion
programme was completed. The programme distributed 23.8 million three-kilogram LPG cylinders to thedensely populated provinces of Jakarta, Banten, West Java, Yogyakarta and South Sumatra. The programmeeliminated the need for Pertamina to supply 5.2 billion litres of heavily subsidised kerosene for household use
in these provinces.
In an extension of the programme, 4.7 million three-kilogram LPG canisters were distributed by 2010.
From 2011 to 2013, some 6.8 million three-kilogram LPG cylinders were distributed. In 2014, the programme
expects to distribute 1.629 million cylinders with the same characteristics.
CITY GAS NETWORK DEVELOPMENT PROGRAMMEThe MEMR has rolled out a city gas network development programme that aims to connect 3 million
households by 2025 and to reach 5 million households by 2030. The city gas network is developed in regionsthat have indigenous sources and consumption of natural gas. The programme will reduce LPG consumption
and substitute it with natural gas through the city gas network. The number of households with gas connection
has increased from 200 000 in 2014 to 402 583 connections in 2017.
COAL-BED METHANE

Oil and gas laws and regulations also govern coal-bed methane. The Directorate General of Oil and Gas
oversees business activities with regard to coal-bed methane development. The MEMR issues regulations aswell as establishes and offers coal-bed methane work areas. The Directorate General of Oil and Gas technicallyestablishes and offers coal-bed methane work areas with due consideration given to the opinion of BP MIGAS(which has now passed on its duties to SKKMIGAS).
Ministerial Regulation No. 36/2008 regards coal-bed methane gas regulation and development, covering
exclusively rights and business related to coal-bed methane; the method of determining and offering coal-bed
methane work areas; the use of data, information, equipment and facilities; research, assessment anddevelopment of coal-bed methane; resolution of disputes; rulings on coal-bed methane as an associated natural
resource; and the utilisation of coal-bed methane for domestic needs.
In addition, simplification of licensing was among the efforts undertaken by the Indonesian upstream oil
and gas industry to attract investors. By March 2018, the Directorate General of Oil and Gas has revoked 56
regulations and permits that consist of 23 Ministerial regulations and 18 Ministerial permits, 12 regulations at
the SKK Migas, and 3 permits at the BPH Migas. To accelerate the licensing process, the MEMR incooperation with the Investment Coordinating Board (BKPM) has launched quick service delivery andlicensing related to infrastructure in the energy and mineral resources in three hours (ESDM, 2017c).
MINERALS AND COAL MINING

Indonesia’s minerals and coal mining law (Law No. 4/2009) replaced the COW and PKP2B systems with two
types of permits: mining business permits (Izin Usaha Pertambangan [IUPs]) and citizens mining permits (Izin
Pertambangan Rakyat [IPRs]). The new law also introduced a contract called the mining business contract(Perjanjian Usaha Pertambangan [PUP]). The IUPs apply to large-scale mining. The PUP is a contract between
the government and a private mining company whereby the government is represented by an implementing
body, which is yet to be established.
Under the new law, the mining fiscal regime includes corporate tax under the prevailing taxation law, asurtax of 10% and a mining royalty that is determined according to the level of mining progress, the level ofproduction and the prevailing price for the mineral. The law allows a transition period for current COW and
PKP2B holders, some of which are large mining concessions for minerals and coal that will expire between
2021 and 2041. The law’s explanation with regard to transition states that existing contracts will be upheld;
however, the specific scheme for the transition of existing concessions has not yet been formulated.
According to the Geological Agency of the Ministry of Energy and Mineral, proven coal reserves inIndonesia reached 26.2 billion tons in 2017. The coal reserve is distributed in three regions of Kalimantan (14.9
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billion tons), Sumatera (11.2 billion tons) and Sulawesi (0.12 billion tons). At a production rate of 461 million
tons per annum, existing coal reserves could last for another 56 years.
Domestic coal consumption was recorded at 97 million tons in 2017, equivalent to 21% from the total
coal production. The remaining portion of the coal production was exported to 28 countries with the biggest
portions to China (51 million tons), India (46 million tons), and Japan (22 million tons). The Indonesian
government is maintaining coal export policies while coal supplies for domestic consumptions are secured
through the Domestic Market Obligation policy.
PUBLIC PRIVATE PARTNERSHIPIn late 2011, project documents were signed which enable the Central Java ultra-supercritical coal power plant,
consisting of two 1 000 MW units, to be the first project realised under the Public Private Partnership (PPP)
programme by Presidential Regulation No. 67/2005 regarding government partnership with private entities toprovide infrastructure. The terms of the PPP include government investments and guarantees on PLN powerpurchases through a private guarantor established by Presidential Regulation No. 78/2010, Infrastructure
Guarantees in Government Partnership Projects with Business Entities Executed through Private
Infrastructure Guarantors.
Government guarantees for the PPP Central Java power plant project are an advanced step in
infrastructure development in Indonesia because the approach taken is considered more transparent andaccountable. The PPP scheme to be used for the Central Java power plant project is the build-own-operatetransfer (BOOT), which has a concession period of 25 years. Commercial operation is expected to commenceat the end of 2019.
GEOTHERMAL

To promote geothermal development, the government has provided some fiscal incentives for income tax,
value added tax, import duty and the withholding of income tax for imports under the taxation regulations(MoF, 2014). The details are as follows:

A tax holiday with exemption from corporate income tax (from five to ten tax years). After theperiod of corporate income tax exemption has ended, the developers are given a 50% reduction of
corporate income tax for two tax years.

An investment allowance for geothermal energy. The allowance includes reduced net income tax of
30% of the total investment (5% a year for six years), accelerated depreciation and an income tax
rate of 10% or lower based on a tax treaty with regard to dividends paid to non-resident taxpayers
and compensation for losses in certain circumstances. However, the developers may only have
either a tax holiday or an investment allowance.



Exemption from value added tax for the importation of machinery and equipment, not including
spare parts.



Exemption from import duty for machinery, goods and materials for construction and development
as long as the machinery, goods and materials have not been produced in the domestic area, havebeen produced in the domestic area but their specifications do not meet the criteria or have been
produced in the domestic area but in insufficient quantities.



Exemption from Withholding Income Tax Art. 22 for the importation of machinery andequipment, not including spare parts.

To implement Law No. 27/2003 on geothermal energy, the government issued Government Regulation
No. 28/2016 regarding the amount and procedures for geothermal production bonuses (ESDM, 2016b).
The regulation states the following:Production bonus is a financial obligation for geothermal developers (geothermal license holders,authorities of geothermal resource utilisation, holders of joint operation contracts of geothermal
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the sale of geothermal steam and/or power from geothermal power plants) to the local
governments.

The geothermal developers are required to provide bonuses for geothermal production after thecompletion of the first unit of commercial production to the general treasury account of the local
government as determined by the MEMR.



Production bonuses imposed amount to 1% of the gross revenue from the sale of geothermal steam,or 0.5% of the gross revenue from the sale of electricity.



Further provisions concerning the procedures for reconciliation and production bonus percentage
producer region and assessment parameters and weights are stipulated in the regulations of the
MEMR.
ENERGY EFFICIENCYGOVERNMENT REGULATION ON ENERGY CONSERVATIONAs called for by the Energy Law (Law No. 30/2007) on 16 November 2009, the government issued
Government Regulation No. 70/2009 regarding energy conservation. The regulation mandates the following:

The formulation of a National Energy Conservation Master Plan (Rencana Induk Konservasi
Energi Nasional), which will be updated every five years or annually, as required;

The introduction of an energy manager, energy audits and an energy conservation programme forfinal energy users of 6 ktoe or greater;

The implementation of energy efficiency standards and energy labelling;

Government incentives in the form of tax exemptions, fiscal incentives for the importation ofenergy-saving equipment and low-interest lending rates to encourage investments in energy
conservation; andGovernment disincentives in the form of written notices advising compliance, publicannouncements of noncompliance, monetary fines and reduced energy supply for noncompliance.

To implement Government Regulation No. 70/2009 regarding energy conservation throughout
Indonesia, the government issued Ministerial Regulation No. 14/2012 on energy management.
The regulation states the following:Energy producer’s own utilisation and energy users who consume energy sources and/or energy of
6 ktoe per year or greater shall carry out energy management and have an obligation to establish anenergy management team.

Energy source users and energy users who use energy sources and/or energy of less than 6 ktoe per
year shall carry out energy management and/or implement energy savings.

Energy conservation programmes shall consist of short-term programmes (improvements inoperating procedures, maintenance and installation of simple device controls), medium- to longterm programmes (increasing efficiency of equipment and fuel switching) and continuous
improvement of employee or operator awareness and knowledge of energy conservation techniques.

An energy audit shall be conducted periodically on at least the main energy-consuming appliancesand equipment at least once every three years.

An annual report on energy management implementation shall be provided by energy source users
and energy users to ministers, governors and regents or mayors within their respective jurisdiction.

Incentives shall be given to energy source users and energy users who have succeeded in reducing
their specific energy consumption by at least 2% per year during a three-year period. These
incentives include eligibility for energy audit partnerships funded by the government and/or
recommendations for priority access to energy supplies by ministers, governors and regents or111

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mayors within their respective jurisdiction. Disincentives shall be imposed on energy source users
and energy users who have not achieved energy conservation through energy management. Thesedisincentives include written notices advising compliance, public announcements of noncompliance, monetary fines (calculated at 5% of the cost of energy used during the one-year
reporting period) and/or reduced energy supply (maximum 5% of contract capacity for a period of
one month, with a possible extension) for non-compliance.
As part of the government commitment to increase energy efficiency and conservation, the MEMR has
developed an energy conservation project as one of its nationally appropriate mitigation actions (NAMAs),
namely, the Smart Street Lighting Initiative (SSLI). The SSLI programme aims to implement energy efficiency
in street lighting by replacing conventional lighting technology with energy efficient technology, namely, lightemitting diodes in urban areas. The SSLI will be implemented in 22 cities in Indonesia to promotetransformational changes in this particular sector. This programme will then be implemented throughout theeconomy. The SSLI has been registered with a NAMA of the United Nations Framework Convention on
Climate Change (UNFCCC) since May 2014 to seek international support for implementation. In addition to
being proposed to the NAMA facility, the project has been attracting support from several development
partners, namely, the Asian Development Bank, the United States Agency for International Development andthe French Development Agency.
Moreover, with regard to energy efficiency, Indonesia has also issued standards and regulations for energy
efficiency in buildings. These include the following. The National Standard (SNI) No. 03-6390-2011: Energy
Conservation for Air Conditioning Systems in Buildings; SNI 03-6197-2011: Energy Conservation for Lighting
Systems in Buildings; SNI 03-6389-2011: Energy Conservation for Building Envelopes; and SNI 03-61962011: Procedures for Energy Audits in Buildings. The implementation of the standards is carried out by
provincial and municipality level of governments, such as the City of Jakarta as part of the Governor’s
Regulations on Green Buildings in Jakarta. Each building, whether existing or new, must conform to the green
building standard, which includes energy efficiency, to obtain or renew its building permit. Some buildings,
new and existing, are also participating in the Greenship Programme of the Green Building Council Indonesia.
The Greenship Programme has the following four criteria:


Sustainable building materials;



Water and waste water management;Energy efficiency; and

Waste management.

Currently, there are 41 new buildings and three existing buildings registered under this programme.
BARRIER REMOVAL

Indonesia is participating in a United Nations Development Programme-Global Environment Facility(UNDP-GEF) project, which involves six developing Asian economies. This project, Barrier Removal to the
Cost-Effective Development and Implementation of Energy Efficiency Standards and Labelling (BRESL),
comprises five major programmes promoting energy standards and labelling: policy making, capacity building,manufacturing support, regional cooperation and pilot projects. The BRESL project was completed in 2014
but the government has continued its implementation (UNDP, 2014).
With regard to the promotion of the establishment of a legal and regulatory basis for the removal fromthe market of technologies that are less energy efficient and produce more emissions and the subsequent
adoption of high-efficiency technologies, some of the achievements in 2016 were as follows:

The government has revised Ministerial Regulation No. 6/2011 on CFLs with Regulation No.
18/2014 and followed this with a technical guideline, which has been signed and released by the
Directorate General of New Renewable Energy and Energy Conservation (DGNREEC);

Regulation No. 7/2015 on air conditioners has been issued by the Minister of Energy and Mineral
Resources and followed by a technical guideline, which has been signed and released by the
DGNREEC;
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Drafts of a ministry regulation on refrigerator labels were submitted to the DGNREEC and will be
the basis for the creation of technical guidelines for labels;

Drafts of energy performance tests on rice cookers and electric fans were finalised and submitted
to the DGNREEC and will be enacted as the Indonesian Standard for Energy Performance;

A testing protocol for electronic ballast was submitted to DGNREEC to be evaluated and included
as a technical guideline under a ministerial regulation; andA regional feasibility study on CFL was conducted based on Australian practices and updated forthe standard harmonisation of CFL energy performance.
POTONG (CUT) 10% MOVEMENT

Indonesia launched a Potong (cut) 10% Movement in May 2016. The Potong 10% Movement aims to change
people’s behaviour in using energy more wisely. The main target of this national movement is to reduce energy
consumption by 10%. This campaign is intended to promote the rise of a movement such as the Public Lifestyle
Change Joint Action (government, business/industry and individual) to encourage energy savings. Nationally,
it is easier and less expensive to save 10% than to raise the energy equivalent by the same amount (ESDM,
2016a).
The campaign will continue to illuminate ideas through the labelling of energy efficiency, formation ofmanagerial and energy auditors, the use of energy-saving lamps and optimising the role of energy service
companies and the Nation Energy Activator (PETA). The public campaign will hold simultaneous meetingsin 20 major cities, namely, Medan, Pekanbaru, Batam, Padang, Palembang, Lampung, Jakarta, Bogor, Depok,
Tangerang, Bekasi, Cilegon, Bandung, Yogyakarta, Semarang, Sidoarjo, Surabaya, Denpasar, Makassar andBalikpapan.
Public campaigns have been carried out comprehensively and sustainably through the following four
scheme campaigns:


Direct campaigns in public spaces, such as schools, universities, monuments, shopping centres andcity parks;

A viral campaign through social media;

Sustained campaigns involving 33 young communities and 35 community service officers (CSO);and

The campaign with the Report 10% mechanism.

The overall campaign will also be accompanied by information dissemination through various media, suchas public service announcements on national TV, branding on the train and commuter-lines, cover seat
information on planes, banners on online media and appearances on talk shows on national TV. The activity
will continuously post various advertisements on television and distribute print media on trains and planes andin bus terminals.
RENEWABLE ENERGY

On 17 October 2014, the government issued the new National Energy Policy under Government Regulation
No. 79/2014 to replace the existing national energy policy, which was established by Presidential Regulation
No. 5/2006. The aim of this policy is to:achieve energy elasticity for GDP of less than one by 2025;



achieve a reduction of final energy intensity to 1% per year up to 2025; andrealise an optimum primary energy consumption mix where the share of new and renewable energy
will be at least 23% by 2025 and at least 31% by 2050.

As part of the government’s commitment to mitigate climate change, the MEMR has developed arenewable energy project in the form of a NAMA, known specifically as the Debottlenecking Project Financing
for Small-scale Renewable Energy (DEEP). The DEEP programme aims to promote on-grid renewable
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energy, particularly bioenergy-based power plants, by increasing the institutional capacity of financial
institutions and project developers. Its activities will include technical assistance as well as financial facilities
for renewable energy developers. In addition to this project, Indonesia is currently developing another NAMA
project, which focuses on small-scale renewable energy (mini/micro-hydro power plant).
BIOFUELSIn 2008, Indonesia passed Ministerial Regulation No. 32/2008, regarding the supply, use and commerce of
biofuel as another fuel. This regulation made biofuel consumption mandatory from 2009.
The regulation controls the following:

the utilisation priority of biofuels;biofuel categories;

standards and specifications of quality;

price setting;

biofuel commerce, as another fuel;

directives and oversight; and

sanctions.

To reduce fuel imports by accelerating the improvement and expansion of biofuels, the government
revised Ministerial Regulation No. 32/2008 through Ministerial Regulation No. 12/2015 on 18 March 2015.
This regulation sets mandatory targets for the percentage share of biofuels with regard to the share of total
fossil consumption (biofuel blend), as shown in Table 5.
Table 5: Minimum obligations for biofuel use (% blend)
SectorApril 2015

Jan 2016

Jan 2020

Jan 2025

PSO transport

15

20

30

30

Non-PSO transport

15

20

30

30

Industrial and commercial

15

20

30

30

Electricity generation

25

30

30

30

PSO transport

1

2

10

20

Non-PSO transport

2

5

10

20

Industrial and commercial

2

5

10

20

Industry

10

20

20

20

Marine

10

20

20

20

Aviation

–

2

3

5

Electricity generation

15

20

20

20

Biodiesel

Ethanol

Straight vegetable oil fuelNote: PSO = public service obligation fuel means subsidised fuel.
Source: (ESDM, 2015c).

Until the end of 2014, the realisation of biofuel (biodiesel and bioethanol) utilisation was 4.1 million
kilolitre (kL), an increase of 47% from 2.8 million kL in 2013.
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INDONESIAGEOTHERMALIn 2017, Indonesia’s total geothermal capacity was 1 808 MW, which is 6.25% of the total geothermal potentialof 28 910 MW (PLN, 2018). Indonesia has identified 11 705 MW of geothermal power potential from existing
geothermal plants, through capacity expansion of productive geothermal resources and from new geothermal
projects at 67 sites. Specifically, the latter are anticipated to produce 5 195 MW in Sumatra at 22 sites, 4096 MW in Java at 26 sites, 1 036 MW in Sulawesi at five sites, 813 MW in the Nusa Tenggara and Bali at eightsites and 565 MW in the Maluku islands at five sites (EBTKE, 2015).
This geothermal power potential will be developed under the 10 000 MW Accelerated Development ofElectricity Generation—Phase II programme as well as a 35 000 MW programme. Some of these projects haveachieved commercial operation date and other projects will operate between 2018 and 2027. Under PLN’s
Electricity Power Supply Business Plan 2018–27 (Rencana Usaha Penyediaan Tenaga Listrik, or RUPTL), a further
increase in geothermal capacity by 4 583 MW is expected between 2018 and 2027. Of the total capacity, 2 170
MW will be developed by IPPs, 425 MW by PLN, and 1 988 MW is currently under business case and has notbeen allocated to either PLN or IPPs (PLN, 2018).
HYDROPOWER

In 2014, Indonesia’s total hydropower capacity was 5 229 MW (including 170 MW of micro- and mini-hydro).
This was 7% of the total hydropower potential of 75 GW (DJK, 2015a). Under the 10 000 MW Accelerated
Development of Electricity Generation—Phase II programme over 2015–22, Indonesia is committed todeveloping additional hydropower with a total capacity of approximately 1 803 MW. Of this total capacity, 424
MW will be developed by IPPs and 1 379 MW by PLN.
PLN’s RUPTL 2018–27 also includes the potential for an additional 8 283 MW of hydropower capacity
during 2018–27 (including mini-hydro and pump-storage plants). Of this capacity, 3 558 MW would be
developed by IPPs and 2 688MW by PLN, and the remainder of the project’s 3 001 MW has not yet been
decided; however, private participation is still an option for the project. The additional hydropower capacity
includes the 88 MW Peusangan hydro-power and 174 MW Asahan III hydro-power in Sumatera that areconsidered as strategic power projects to reduce the levelised cost of electricity (LCOE) in the Sumatera power
grid. Three pump-storage power plants in Java—specifically the Upper Cisokan (1 040 MW) in West Java, theMatenggeng (900 MW) at the border of West and Central Java, and the Grindulu (1 000 MW) in East Java.
These pump-storage plants are considered important for the technical performance and stability of theIndonesian electricity grid, particularly the Java-Bali electricity grid.
These hydropower plants would increase Indonesia’s total large hydropower capacity to 14 480 MW, or
19% of Indonesia’s total hydropower potential. It is worth noting that Indonesia’s large hydropower potential
is located in the eastern part of Indonesia, far from the large consumption centres.
WIND POWER

Indonesia has been identified to have wind power potentials especially in Java, South Sulawesi, West Nusa
Tenggara, East Nusa Tenggara and Maluku. Some of wind power projects are currently being developed. The
70 MW Sidrap wind power that commenced its operation in February 2018 has marked as a milestone in thedevelopment of large scale wind power in Indonesia.
The electricity prices of wind power plants that are operated by Independent Power Producers (IPPs) aredetermined in accordance to the MEMR regulation No. 50/2017 regarding The Utilisation of Renewable
Energy Resources for Electricity Generations.
SAVING ENERGY AND WATER

Presidential Instruction No. 13/2011 Regarding Saving Energy and Water instructs Ministers of the Unity
Indonesia II Cabinet, the Supreme Justice of the Republic of Indonesia, the Commander of the Armed Forcesof Indonesia, the Head of State Police Republic of Indonesia, heads of non-ministerial government agencies,
heads of state secretariat institutions, governors and regents or mayors to take measures and innovate in orderto save energy and water within their institutional domains and/or in the domains of state-owned businesses
and regional government-owned businesses within their jurisdiction.

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Presidential Instruction No. 13 assigns an electricity saving target of 20% from the average electricity use
over the six months prior to the presidential instruction; fuel saving targets of 10% through regulations to limit
the use of subsidised fuels; and water saving targets of 10% from the average water use over the six months
prior to the presidential instruction.
The presidential instruction calls for the creation of a national team on saving energy and water. The
Coordinating Minister of Economic Affairs is the chair and the Minister of Energy and Mineral Resources is
the Executive Chief and both are members of the national team; 11 cabinet ministers are also members of theteam. The national team is supported by the executive team, which is headed by the secretary of the national
team.
NUCLEAR ENERGY

In 2007, the government of Indonesia established the Nuclear Power Development Preparatory Team, whose
task is to take the necessary preparatory measures and create the plans to build Indonesia’s initial nuclear energy
power plants; however, to date, the team has not conducted any significant activities or performed any related
tasks. The legal basis of Indonesia’s nuclear energy development includes Law 17/2007 on long-term
development, Years 2005–15 and Government Regulation No. 43/2006 on the licensing of nuclear reactors.
Indonesia has developed an indigenous nuclear fuel cycle, although certain stages are still at the laboratory
stage. The economy has a well-established nuclear research programme, which spans nearly five decades. The
National Nuclear Energy Agency (BATAN) currently operates three nuclear research reactors, specifically the
GA Siwabessy 30-MW pool-type materials testing reactor in Serpong; the Kartini-PPNY 100-kilowatts (kW)Triga Mark-II reactor in Yogyakarta and the Bandung 1000-kW Triga Mark-II reactor in Bandung. A fourth
10-MW pool-type research reactor is planned for development in the near future.
Indonesia currently has two prospective uranium mines. The first is the Eko-Remaja prospect of the
Remaja-Hitam Ore Body, a uranium vein in fine-grained metamorphous rock, estimated to contain
5 000–10 000 tonnes of uranium with a grade ranging 0.1–0.3. The second is the Rirang Tanah Merah Ore
Body, a uranium vein, which may contain fewer than 5 000 tonnes of uranium of a grade ranging 0.3–1.0. The
uranium mines are located in West Kalimantan.
Despite the above developments, the Fukushima Daiichi nuclear accident in 2011 generated negative
perceptions, discouraging prospects for building nuclear energy power plants in Indonesia. At the same time,
people have resisted development on candidate sites, thereby making development uncertain. Hence, thegovernment has stated that nuclear energy will be the last option used to achieve Indonesia’s energy
consumption, which means renewable energy sources are prioritised.
CLIMATE CHANGE

Indonesia strongly supports the objectives of the UNFCCC to prevent atmospheric concentrations ofanthropogenic gases exceeding a level that would endanger the existence of life on Earth. To indicate its
decisiveness and serious concern about global warming, Indonesia signed the convention on 5 June 1992. On
1 August 1994, the President of the Republic of Indonesia formalised this ratification by enacting Law No.
6/1994 regarding approval of the UNFCCC. Indonesia is legally included as a party to the convention, which
implies that Indonesia is bound by the rights and obligations that it stipulates.
As a non-Annex 1 party in the Kyoto Protocol, Indonesia has no obligation to reduce greenhouse gas(GHG) emissions. However, the Indonesian Government is committed to participate in and cooperate withthe global effort to combat climate change. This position was expressed by the President of the Republic ofIndonesia at the G20 Finance Ministers meeting and Central Bank Governors Summit held in September 2009
in Pittsburgh, the United States. In addition, the government of Indonesia has pledged to reduce GHG
emissions from forestry and the energy sector by 26% through domestic efforts and by up to 41% throughcooperation with other economies.
In response to this commitment and the challenges of climate change, the Indonesian Government hasestablished a roadmap for integrating climate change issues into development planning. The climate change
roadmap will integrate mitigation and adaptation into policy instruments, regulations, programmes, projects,
funding schemes and capacity building in all development sectors. Two initial phases are the integration of116

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climate change into the Mid-Term Development Plan 2010–14 (Rencana Pembangunan Jangka Menengah
2010–14, RPJM) and the launching of the Indonesia Climate Change Trust Fund (ICCTF) on 14 September
2009.
The ICCTF is a financing mechanism for climate change mitigation and adaptation within Indonesia’s
policy framework. The ICCTF has two key objectives:

Achieving Indonesia’s goal of a low-carbon economy and greater resilience to climate change
through the facilitation and acceleration of investment in renewable energy and energy efficiency;
sustainable forest management and forest conservation; and the reduction of vulnerability in key
sectors such as coastal zones, agriculture and water resources.



Enabling the government of Indonesia to increase the effectiveness and impact of its leadershipand management in addressing climate change by bridging the financial gap in order to address
climate change mitigation and adaptation and increasing the effectiveness and impact of externalfinance for climate change work in Indonesia.

Through the ICCTF, the government of Indonesia can utilise not only government budgets but alsobilateral and multilateral financial agreements, public-private partnerships, mandatory and voluntaryinternational carbon markets and the Global Environmental Fund and other funds in order to implement a
policy framework for climate change.
The ICCTF consists of two funds: the Innovation Fund and the Transformation Fund. The Innovation
Fund is a grants-based fund to finance demonstration and innovation projects, pilot projects and research anddevelopment. The Transformation Fund is used to finance low-emissions programmes, projects and initiatives
developed by private parties. The Transformation Fund is not a grants fund but a revolving fund; thus, projects
are expected to generate returns on the fund’s investments.
In December 2015, at the Conference of the Parties (COP) 21 of the UNFCCC in Paris, the governmentof Indonesia submitted its Intended Nationally Determined Contribution (INDC) in which the economy
pledged unconditionally 29% GHG emission reduction by 2030 compared to business-as-usual (BAU) level
and an increase of up to 41% with international support. The BAU level has been projected to be approximately
2869 GtCO2e in 2030 based on its level in 2010 (1334 GtCO2e), which has been updated from the National
Energy Policy owing to increasing coal-fired power plant utilisation.
In November 2016, the government of Indonesia submitted the first INDC document to the UNFCCC.
The document included a target to increase the energy sector contribution from 6% to 38%. The main
contribution, around 59% remaining, would come from the forestry sector, including peat fire, whereas around
3% would be contributed from waste, agriculture, industrial processes and product use (UNFCCC, 2016).
In order to achieve the target of 29% reductions of CO2 emissions in 2030, the government has adopted
the following strategies for carbon emissions reduction for the electricity supplies, including:Prioritise electricity supplies from renewable energy sources while ensure cost competitive of electricity
Fuel switching from oil to gas and biodiesel
Adopt advanced clean coal technologies such as ultra-supercritical and consider Carbon Capture andStorage (CCS) when the technology has reached mature stage of development.
N OTA B L E E N E RG Y D E V E L O P M E N T S
ELECTRICITYACCELERATED ELECTRICITY GENERATION PHASE I, PHASE II AND 35 GW PROGRAMMEThe accelerated power development programme, 10 000 MW Phase I, had completed 9 120 MW of new
generation capacity by the end of December 2015. With regard to project constraints, the MEMR had set a
new final completion date of 2016 for the 10 GW Phase I of the programme.
In 2010, the government mandated PLN to implement Phase II of the programme. In this second phase,
PLN will add 11 GW of capacity based on 68% coal, 19% geothermal, 10% combined cycle gas and 3%
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hydropower. The two-phase accelerated power development programme is expected to rapidly increase
generating capacity, encourage renewable energy utilisation and simultaneously eliminate oil-based power
plants, except in regions where there are no other competitive alternative energy sources.
The composition of the generation capacity mix for Phase II of the 10-GW Accelerated Power
Programme is required to be updated to accommodate the current situation’s conditions. In 2014, the MEMR
established a new final energy mix for the 10-GW Phase II with a total capacity of 17 458 MW, 60% of which
will be developed from coal, 28% from geothermal, 10% from hydropower and 2% from gas. The scheduled
completion date for the 10-GW Phase II is 2022.
To provide a sufficient electricity supply for supporting economic growth as well as increasing the
economy’s electrification ratio, the government launched the 35-GW Electricity Programme for Indonesia in
May 2015. The procurement process is expected to be completed in 2019 while commercial operation dates
will vary between projects (PLN, 2018). Taking into consideration that the total capacity of 7.4 GW of power
plants are in the construction stage, the total additional capacity of the power plants that will be developed is
43 GW (7.4 GW plus 36 GW). In the 35-GW programme, 57% of the capacity comes from coal-fired power
plants, 36% from combined cycle gas, 6.1% from hydropower and 1.2% from geothermal. Based on the latest
project status update in November 2017, 1 GW of power plants are already operating, 16.6 GW are underconstruction, 12.8 GW has entered into power purchase agreements, 3.2 GW is being tendered by PLN, and
2.2 GW is being planned by PLN (PLN, 2018).
To realise such an ambitious programme, a policy breakthrough has been prepared by the government.
The Presidential Regulation No. 4 Year 2016 was issued and later revised to Presidential Regulation No. 14
year 2017 to accelerate electricity infrastructure development in Indonesia. This is a key regulation that
underline the 35-GW Electricity Programme. This involves implementing initiatives such as land acquisition
secured by the government according to the land law for projects of public interest; establishing a ceiling pricefor electricity purchase; shortening the procurement process in order to select developers and contractors
through direct appointment and direct selection as well as conducting due diligence to assess the developer’s
and contractor’s performance; streamlining the permit process (the number of electricity permits has been
reduced from 52 to 29); and establishing a one-stop service for permits under the Investment Coordinating
Board Agency (BKPM) (DJK, 2015b).
The subsequent electricity development programmes that are supported by regulations to accelerate
electricity infrastructure development has substantially improved electricity services in Indonesia. There are nolonger electricity supply deficits where the electricity reserve margins are varied electricity grids. For example,
the Batam electricity system has 75.21% of reserve margin while the Java-Bali electricity grid has 35.7% reserve
margin in 2017.
ELECTRIFICATION RATIOThe Government of Indonesia has rapidly increased the Indonesia’s electrification rate from 84.4% in 2014 to
95.4% in 2017. The rate of electrification will increase to 97.5% in 2018 and is forecasted to reach 99% in
2019. The government has a target to achieve 100% electricity access by 2024n. The electrification program
includes the expansion of transmission and distribution network in the Eastern Indonesia to reach remotevillages. At the same time, solar home systems program has been underway to reach out 2,510 villages thathave not have access to electricity, while the grid expansion is being rolled out to reach their regions until theend of 2019.
UPDATE OF THE PLN ELECTRICITY SUPPLY BUSINESS PLAN 2018-2027

The MEMR has issued the ministry decision number 1567 K/21/MEM/2018 on 13 March 2018 thatconsists the following changes to the previous electricity supply business plan:

23% share of renewable energy in the electricity generation mix in 2025 while the share of coal, gas, andoil will be 54.4%, 22%, and 0.4% respectively;
The plan for additional power generating capacity at total capacity of 56 024 MW;
The expansion of transmission line capacity of 63 855 kilometer circuits (kms) while distribution
network expansion is 526 390 kilometer circuits (kms); and118

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INDONESIAThe development of 151 424 mega-volt-ampere (MVA) of high voltage substations and 50 216 MVAof distribution substations.
REGULATIONSPOWER PURCHASES FROM RENEWABLE ENERGY POWER PLANTS BY PLN

On 8 August 2017, Ministerial Regulation No. 50/2017 regarding the Utilisation of Renewable Energy
Resources for Electricity Generations was issued. The regulation introduced a ceiling price mechanism andelectricity purchase mechanisms from renewable energy sources and it was enacted to replace the previous
Ministerial Regulation No. 12/2017 and previous feed-in tariff regulations (Ministerial Regulation No. 22/2012
for geothermal energy, Ministerial Regulation No. 19/2015 for hydro energy, Ministerial Regulation No.
21/2016 for biomass and biogas energy and Ministerial Regulation No. 19/2016 for solar energy).
Under this new regulation, the purchase of electricity from renewable energy such as solar and wind
power is carried out through direct selection based on quota capacity. Furthermore, the purchase of electricity
from other renewable energy such as geothermal, biomass, biogas, municipal solid waste as well as hydro power
will be conducted through the mechanism of the reference price and direct selections. This regulation also
stipulates that PLN is obligated to operate renewable energy power plants with a capacity within 10 MW
continuously (ESDM, 2017a).
Purchasing electricity from solar and wind power for areas where the generation cost is above the averagenational generation cost, the purchase price of electricity is maximum 85% of the generation cost on therespective local grid. Meanwhile, if generation cost in the local grid equal to or below the average national
generation cost, the electricity purchase price is equal to the generation cost in the local grid.
Purchasing electricity from biomass and biogas energy with a maximum capacity of 10 MW using thereference price and with a maximum capacity more than 10 MW using the mechanism of direct selection forareas where the generation cost is above the average national generation cost, the purchase price of electricity
is maximum 85% of the generation cost on the respective local grid. Meanwhile, if the generation cost in thelocal grid equals or is below the average national generation cost, the electricity purchase price is equal to thegeneration cost in the local grid.
Electricity from municipal solid waste power plant can be obtained by the technology of methane gas
collection along with anaerobic digestion or similar methods from sanitary landfills or through theheat/thermal technology using thermochemical. The developers can be provided facilities in the form of
incentives that will be set in a separate regulation. For areas where the generation cost is above the averagenational generation cost, the purchase price of electricity is equal to the generation cost on the respective local
grid. Meanwhile, if the generation cost in the local grid equals or is below the average national generation cost,the electricity purchase price is determined upon agreement of the parties.
Electricity from geothermal energy can only be purchased by PLN to electric power developers that have
GWA in accordance with proven reserves after exploration. For areas where the generation cost is above theaverage national generation cost, the purchase price of electricity is equal to the generation cost on therespective local grid. Meanwhile, if the generation cost in the local grid equals or is below the average national
generation cost, the electricity purchase price is determined upon agreement of the parties.
Electricity from hydro energy power plants is purchased on the basis of the reference price or direct
selections. A plant with a maximum capacity of 10 MW must be able to operate with a minimum capacity
factor of 65%. With a capacity larger than 10 MW, the capacity factor depends on the needs of the system. For
areas where the generation cost is above the average national generation cost, the purchase price of electricity
is maximum 85% of the generation cost on the local grid of the respective areas. Meanwhile, if the generation
cost in the local grid equals or is below the average national generation cost, the electricity purchase price isequal to the generation cost in the local grid.
The generation cost in the electricity system that is used as the purchase price of electricity in the powerpurchase agreement is the generation cost in the electricity system of the previous year. Electricity is purchasedusing the scheme of Build Own Operate and Transfer (BOOT). Construction of the grid for power evacuation

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from the power plant to the point of connection will be carried out between the electric power developer and
PLN on the business-to-business basis.
PARTICIPATION OF REGIONAL GOVERNMENT IN UPSTREAM OIL AND GAS BUSINESSOn 26 November 2016, the government issued Ministerial Regulation No. 37/2016 regarding provisions
offering participating interest of 10% (PI 10%) in the area of oil and gas works. This regulation was intended
to implement the provisions of Article 34 of Government Regulation No. 35/2004 on upstream oil and gas,
which has been amended several times. The most recent amendment was by Government Regulation No.
55/2009 to increase the participation of regional government through the obligation for the contractor (PSC)
to offer the PI 10% to the regional-owned enterprise (BUMD). BUMD was established by the regional
government whose oil and gas fields are located in its administrative area (ESDM, 2016c).
The regulation mandates include the following:

Since the approval of the first plan of development (POD1), the contractor (PSC) has an obligation
to offer PI 10% to BUMD;

Onshore fields from 0 to 4 nautical miles involving BUMD districts/cities/provinces coordinatedby the governor;

The fields from 4 to 12 nautical miles for BUMD provinces;

Onshore or offshore fields located in administrative areas of more than one province are based on
the agreement among the related governors. If no agreement exists, then the MEMR determines
the number of PI offered to each province;In the period of 10 days from date of receipt of the approval of POD1, Chief of SKKMIGAS is
obliged to submit a letter addressed to the governor to review the preparation of BUMD that will
accept the PI 10% offer;During Period 1 year, the governor will deliver, with a copy to the Minister, a letter of appointment
to BUMD, which will accept the PI 10% offer indicated by the Chief of SKKMIGAS;

In case the governor does not submit a letter of BUMD appointment, it will be assumed that the
party is not interested and the PI 10% offer will be declared closed;

In case the PI 10% offer for BUMD is declared closed, a contractor is required to offer it to StateOwn Enterprises;The contractor (PSC) pre-finances the obligation amount of BUMD;

SOE has an obligation to finance itself complying with normal business practices; andShareholding enterprises and 10% PI cannot be traded or transferred or pledged.

REGULATION SIMPLIFICATION AND ENERGY SECTOR DEREGULATIONIn the early 2018, MEMR has subsequently simplified several regulations, including revoking ninety Ministerial
regulations and ninety-six permits from the subsectors of oil, coal, electricity, renewable energy, SKK Migas,
and BPH Migas. These policies are aiming at improving investment climates in the energy sector andparticularly in the upstream oil and gas development. Detailed information on the list of regulations andpermits that have been revoked can be found on the MEMR website.

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INDONESIAREFERENCESASEAN (Association of South-East Asian Nations) Affairs (2008), Indonesia’s Tax Overhaul Seen a Boost,
11 September, www.aseanaffairs.com/page/indonesia_s_tax_overhaul_seen_a_boost.
Daniel Johnston (1994), International Petroleum Fiscal Systems and Production Sharing Contracts.
David Johnston, Daniel Johnston, and Tony Rodgers (2008), International Petroleum Taxation for the Independent
Petroleum Association of America, Daniel Johnston & Co., Inc., Hancock, New Hampshire.
DJK (Direktorat Jenderal Ketenagalistrikan–Directorate General of Electricity) (2015a), Statistik
Ketenagalistrikan 2015,
http://www.djk.esdm.go.id/pdf/Buku%20Statistik%20Ketenagalistrikan/Statistik%20Ketenagalistrika
n%202015.pdf.
–– (2015b), Indonesian Power Sector Policy & Strategy, presented at Indonesia Japan Energy Forum, Tokyo, 16June 2015.
EBTKE (Directorate General of New, Renewable Energy and Energy Conservation) (2015), Statistik
EBTKE 2015, December 2015.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
ESDM (Ministry of Energy and Mineral Resources) (2015a), Laporan Akuntabilitas Kinerja Instansi Pemerintah(LAKIP) KESDM Tahun 2014, February 2015https://www.esdm.go.id/assets/media/content/contentlaporan-akuntabilitas-kinerja-instansi-pemerintah-kementerian-esdm-tahun-2015.pdf–– (2015b), Handbook of Energy and Economic Statistics of Indonesia 2015,
http://prokum.esdm.go.id/Publikasi/Handbook%20of%20Energy%20&%20Economic%20Statistics%20of%20Indonesia%20/Buku%20Handbook%202015.pdf.
–– (2015c), Ministerial Regulation No. 12/2015 regarding the third revision of Ministerial Regulation No. 32/2008,
http://jdih.esdm.go.id/peraturan/Permen%20ESDM%2012%20Thn%202015.pdf.
–– (2016a), Ministry of Energy and Mineral Resources: Cut 10 Percent program is cheaper than building new power
plants, https://www.esdm.go.id/id/media-center/arsip-berita/hemat-energi-potong-10-persen-lebihmurah-daripada-bangun-pembangkit-listrik–– (2016b), Government Regulation No. 28/2016 regarding amount and procedure for geothermal production bonus,
http://jdih.esdm.go.id/peraturan/PP%20No.%2028%20Tahun%202016.pdf.
–– (2016c), Ministerial Regulation No. 37/2016 regarding Provisions offer 10% Participating Interest in Working Area of
Oil and Gas,
http://jdih.esdm.go.id/peraturan/Permen%20ESDM%20No.%2037%20Tahun%202016.pdf.
–– (2017a), Ministerial Regulation No. 50/2017 regarding the utilization of renewable energy sources for electricity supply,
http://jdih.esdm.go.id/peraturan/Permen%20ESDM%20Nomor%2012%20Tahun%202017.pdf.
–– (2017b), Ministerial Regulation No. 8/2017 regarding production sharing contract gross split,
http://migas.esdm.go.id/post/read/permen-esdm-nomor-08-tahun-2017-tentang-kontrak-bagi-hasilgross-split.
–– (2017c), Gross split thus upstream oil and gas breakthrough for more attractive and efficient,
http://www.migas.esdm.go.id/post/read/gross-split-jadi-terobosan-hulu-migas-agar--lebih-menarikdan--efisien.
__ (2017d), Handbook of Energy and Economics Statistics of Indonesia 2017.
MoF (Ministry of Finance) (2014), Innovative Fiscal Policies to Create Energy Resilience: Focusing on Geothermal
Energy, presented at Indonesia International Geothermal Convention and Exhibition 2014, 4 June 2014.

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INDONESIANEA (Nuclear Energy Agency) (2014), Uranium 2014: Resources, Production and Demand, https://www.oecdnea.org/ndd/pubs/2014/7209-uranium-2014.pdf
PLN (State Electricity Company) (2015), Rencana Usaha Penyediaan Tenaga Listrik 2016-25 – Electricity
Supply Business Plan 2016–25 (RUPTL 2016-25).
PLN (State Electricity Company) (2018), Rencana Usaha Penyediaan Tenaga Listrik 2018-2027 – Electricity
Supply Business Plan 2018-27 (RUPTL 2018-2027).
PwC (PricewaterhouseCoopers Indonesia) (2012), Oil and Gas in Indonesia—Investment and Taxation Guide, May
2012, 5th Edition, Updated for GR 79/2010 and its implementing regulations,www.pwc.com/id/en/publications/assets/oil-and-gas-guide_2012.pdf.
SKKMIGAS (The Upstream Oil and Gas Implementing Agency) (2014), Laporan Tahunan 2014–Annual
Report 2014, http://www.skkmigas.go.id/wp-content/uploads/2013/06/Laporan-Tahunan-2014.pdf.
UNDP (United Nations Development Programme) (2014), Barriers Removal to the Cost-Effective Development ofEnergy Efficiency Standards and Labelling BRESL Indonesia,
www.id.undp.org/content/indonesia/en/home/operations/projects/environment_and_energy/barriers-removal-to-the-cost-effective-development-of--energy-ef.html.
UNFCCC (United Nation Framework Convention on Climate Change) (2016), NDC Registry, First
Nationally Determined Contribution Republic of Indonesia,
http://www4.unfccc.int/ndcregistry/PublishedDocuments/Indonesia%20First/First%20NDC%20Ind
onesia_submitted%20to%20UNFCCC%20Set_November%20%202016.pdf.
World Bank (2017), Doing Business 2018: Reforming to Create Jobs, Economy Profile – Indonesia,
http://www.doingbusiness.org/~/media/wbg/doingbusiness/documents/profiles/country/idn.pdf

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INDONESIAUSEFUL LINKS

BPH MIGAS—www.bphmigas.go.id
Ministry of Energy and Mineral Resources (KESDM)—www.esdm.go.id
PT PLN (Persero)—www.pln.co.id
SKKMIGAS, Satuan Kerja Khusus Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi—www.skspmigasesdm.go.id
Statistics Indonesia (Badan Pusat Statistik, BPS)—www.bps.go.id
UNDP Indonesia—www.id.undp.org

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APEC ENERGY OVERVIEW 2017JAPANJ A PA N
I N T ROD U C T I ON

Located in East Asia, Japan comprises several thousand islands, the largest of which are Honshu, Hokkaido,
Kyushu and Shikoku. Most of its land area, approximately 377 800 square kilometres (km2), is mountainous
and thickly forested. Japan is the third-largest economy in the world and among the APEC economies after
the United States and China. Its real GDP in 2015 was approximately USD 4 707 billion (2010 USD purchasing
power parity [PPP]). In 2015, Japan’s population of 127 million people had a per capita income of USD 37 021.
The GDP grew by 1.2% in 2015 compared with that in 2014. Since indigenous energy resources are modest,
Japan imports nearly all of its fossil fuels to sustain economic activity. The proven energy reserves1 include
approximately 44 million barrels of oil, 21 billion cubic metres (bcm) of natural gas and 350 million tonnes(Mt) of coal.
Table 1: Key data and economic profile, 2015
Key dataa

Energy reserves

Area (thousand km2)

377.8

Oil (million barrels)b

44

Population (million)

127

Gas (billion cubic metres)b21

GDP (2010 USD billion PPP)

4 706

Coal (million tonnes)c350

GDP (2010 USD PPP per capita)

37 021Uranium (kilotonnes U)–

Sources: a EGEDA (2017); b Conglin Xu and Laura Bell (2017); c BP (2017).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

In 2015, Japan’s total primary energy supply was approximately 430 million tonnes of oil equivalent (Mtoe), a
decrease of 0.7% from the previous year. By fuel type, oil contributed the largest share (44%), followed by coal
(27%) and natural gas (25%). In 2015, the net imports of energy sources constituted 97% of the total primaryenergy supply.
In 2015, Japan was the fourth-largest oil consumer in the world and the third among the APEC
economies (4.3 million barrels per day [Mbbl/D]), following the United States, China and India (BP, 2017).
Almost all of the oil was imported. The bulk of the imports (83% in fiscal year (FY)2 2015) was from economies
in the Middle East such as Saudi Arabia, the United Arab Emirates and Qatar (METI, 2017a). In 2015, theprimary oil supply was 187 Mtoe, a decrease of 2.9% from the previous year.
Japan is endowed with only limited coal reserves, 350 Mt, while its coal consumption in FY2015
comprised 120 Mt of steam coal and 73 Mt of coking coal (METI, 2017a). It is one of the world’s largest
importers of coking coal for steel production and steam coal for power generation, in addition to cement
production. Japan’s main steam coal suppliers are Australia (77% in FY2015); Indonesia (11%); and Russia(10%), while those for coking coal are Australia (50%); Indonesia (29%); and Canada (9%) (METI, 2017a).
Natural gas resources are also scarce in Japan. Domestic reserves stand at 21 bcm, which is less than onefifth of the annual consumption in 2015, and are located in Niigata, Chiba and Fukushima prefectures. In
FY2015, the domestic demand was met almost entirely by imports in the form of liquefied natural gas (LNG
mainly from Australia (23%); Malaysia (29%); Qatar (16%) and Russia (9%) (METI, 2017a). LNG imports toJapan comprised 31% of the total global LNG trade in 2016 (BP, 2017). Natural gas is mainly used for

1 Oil and natural gas are as of January 2017. Coal is as of the end of 2016.
2 The fiscal year starts in April in Japan.

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JAPANelectricity generation, followed by reticulation as city gas and as an industrial fuel. The primary natural gas
supply was 105 Mtoe in 2015, an increase of 0.7% from the previous year.
Japan has 290 gigawatts (GW) (EGEDA, 2017) of installed generating capacity and generated 1 051 593
gigawatt-hours (GWh) of electricity in 2015. Fossil fuels—coal, gas and oil—constituted 83% of generated
electricity. The share of renewables, including hydro, solar, wind and geothermal, was 17%. Nuclear power
generation increased to 4.5 terawatt-hours (TWh) (0.4% of the total generation) in 2015 from 0 TWh in 2014
due to the restart of the Sendai nuclear power plants (two units).
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

24 405

Industry sector

133 459

Net imports and others

418 386

Transport sector

74 079Thermal873 311

Total primary energy supply

430 078

Other sectors

88 336Hydro

89 012Coal

117 238

Non-energy

3 366

Nuclear

4 459

Oil

186 876

Final energy consumption*

295 874

Others84 811

Gas

105 156

Coal

32 557

Renewables

19 646

Oil

148 331

Others

1 162

Gas

30 089Renewables

2 159

Electricity and others

82 739Total power generation

1 051 593

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type, do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

In 2015, the final energy consumption in Japan was 295.9 Mtoe, a decrease of 0.5% from the previous year.
The industrial sector consumed 45% of the total final consumption, followed by the other sectors, including
buildings (30%), and the transportation sector (25%). Final energy consumption decreased by 0.2% from theprevious year in the industry and transport sectors and by 1.4% in the other sectors. By energy source,
petroleum products constituted 50% of the total final consumption, followed by electricity and others (28%),
coal (11%) and gas (10%).
ENERGY INTENSITY ANALYSIS

In 2015, Japan’s energy intensity declined in terms of primary energy and total final consumption comparedwith that in the previous year. Primary energy intensity decreased to 91 tonnes of oil equivalent per million
USD (toe/million USD), –1.9% from the previous year. Final energy intensity also dropped to
64 toe/million USD, equivalent to –1.8% from 2014. This was mostly driven by the decreasing energy
consumption in the other sector, which includes buildings, and the industry sector.

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Table 3: Energy intensity analysis, 2014 vs 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)

Total primary energy supply

93

91

2014 vs 2015
–1.9

Total final consumption

65

64

–1.8

Final energy consumption excl. non-energy

64

63

–1.7

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

In 2015, the share of modern renewable energy in final energy consumption was 5.4%, an increase of 0.5
percentage point from the previous year. Incremental modern renewables, especially renewable electricity after
the introduction of the feed-in tariffs (FiT) system in 2012, combined with declining consumption, contributed
to the share growth.
Table 4: Renewable energy share analysis, 2014 vs 2015297 484

295 874

Change (%)
2014 vs 2015
–0.5

282 839

280 019–1.0

Traditional biomass*

24

22

–8.5

Modern renewables*

14 621

15 833

8.3

4.9

5.4

8.9

2014
Final energy consumption (ktoe)
Non-renewables (Fossils and others)

Share of modern renewables to final energy
consumption (%)

2015

Source: EGEDA (2017).
*Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal and so on) including biogas and wood pellets are
considered modern renewables, although data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKThe Ministry of Economy, Trade and Industry (METI) of Japan is responsible for designing the energy policyof the economy. Within METI, the Agency for Natural Resources and Energy is in charge of the rational
development of mineral resources, securing stable supplies of energy, promoting efficient energy use andregulating electricity and other energy industries. Regarding nuclear safety, the Nuclear Regulation Authority(NRA), which is an independent commission affiliated with the Ministry of the Environment (MOE), has been
responsible for nuclear safety since September 2012.
Before the Great East Japan Earthquake in March 2011 and the subsequent Fukushima Daiichi nuclear
power plant accident, the aim of Japan’s energy policy was to achieve the ‘3E’ goals—energy security, economic
efficiency and environment (for example, against global warming)—in an integrated manner. After these events,
Japan aims to achieve the ‘3E+S’ goals—the original 3E concept plus safety as the foremost condition.
The Basic Act on Energy Policy 2002 presents the core principles of Japan’s energy policy—assuranceof a stable supply, adaptation to the environment and use of market mechanisms. The Strategic Energy Plan
was established in 2003. The plan is required to be reviewed at least every three years and revised as necessary.
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Since then, the Strategic Energy Plan was revised three times. The current fourth plan was approved by
the Cabinet in April 2014, considering the energy situation after the Great East Japan Earthquake in March2011 and the subsequent Fukushima Daiichi nuclear power plant accident (METI, 2014). This plan provides a
direction to Japan’s energy policies for the medium/long-term (about the next 20 years) based on the ‘3E+S’
policy. It reaffirms the importance of renewables as promising low-carbon and domestic sources, coal as astable and cost-effective base-load power source and natural gas as the main flexible middle-load power source.
The latest plan also reaffirms the importance of nuclear energy as a low-carbon and quasi-domestic powersource. However, it states that dependency on nuclear generation will be lowered to the greatest extent possible
by energy saving and introducing renewable energy, as well as by improving the efficiency of thermal power
generation.
In addition to the fourth plan, the government concluded the Long-term Energy Supply and Demand
Outlook of Japan in July 2015 (METI, 2015a). The outlook indicates an electricity mix, primary energy demandand supply, and energy-related CO2 emissions in FY2030, which realise the ‘3E+S’ policy in the Strategic
Energy Plan. The outlook has three steps: 1) increase energy self-sufficiency (including nuclear as a quasidomestic energy) to approximately 25% from approximately 6% in 2012; 2) reduce electricity costs from thecurrent level; and 3) reduce greenhouse gas (GHG) emissions comparable to the targets of Europe and the US.
The government’s outlook aims for a well-balanced power mix wherein nuclear constitutes 20–22% of thetotal generated electricity, renewables constitute 22–24%, LNG constitutes 27%, coal constitutes 26% and oilconstitutes 3%. Nuclear dependence is lower than that before the earthquake (when it was around 30%).
Within renewables, the two largest sources are hydro, constituting 8.8–9.2%, and solar (7%).
In August 2017, the government began discussions for the fifth Strategic Energy Plan at the Strategic
Policy Committee of the Advisory Committee for Natural Resources and Energy. According to Mr Hiroshige
Seko, the METI minister, the fifth plan is expected to retain the core directions in the fourth plan, whileconsidering the developments in the last few years3. As of January 2018, the fifth plan is under consideration.
ENERGY MARKETSOILJapan aims to decrease its oil dependency, partly because of its experiences during the oil crises in 1973 and1979. However, oil still dominates the total primary energy supply of the economy. The share of oil wasapproximately 40% in 2010, and it increased to 47% in 2012 due to the loss of nuclear generation andincremental oil-fired generation after the earthquake. Although the share of oil declined to approximately 44%
in 2014, securing its stable supply is one of Japan’s major energy policy issues.
The oil supply structure of the economy is vulnerable to the disruption of maritime transport because it
imports almost all of its domestic consumption by tankers. In preparation for possible supply disruptions,Japan has created emergency oil stockpiles and independently developed resources as well as promotedcooperation with oil-producing economies to manage emergencies.
The Japan Oil, Gas and Metals National Corporation (JOGMEC) is responsible for the state-owned
stockpile. It provides financial and technical assistance to Japanese oil industries for oil and natural gas
exploration and development domestically and abroad. The oil stocks of Japan are well in excess of theInternational Energy Agency’s 90-day net import requirements. As of October 2017, Japan held the equivalentof 226 days of net imports, including state-owned stocks, private sector stocks and joint oil storage programs,with oil-producing economies (PAJ, 2017).
To utilise crude oil effectively, the government has been regulating domestic refining capacity in a phasedmanner through the law that regulates the promotion of the use of non-fossil energy sources and the effective
use of fossil energy materials by energy suppliers. First regulation aimed to raise the heavy oil cracking unit
capacity in the economy to approximately 13% of the total distillation capacity from FY2010 to FY2013.
Second regulation aimed to raise the residues processing capacity4 to approximately 50% of the total distillation
capacity from FY2014 to FY2016. Oil refining companies achieved the regulation mainly by reducing
3 The METI minister mentioned at the first meeting of the Strategic Policy Committee (METI, 2017b).

4 Such as RFCC (Resid Fluid Catalytic Cracking), FCC (Fluid Catalytic Cracking), hydrocracking, and SDA (Solvent

Deasphalting).

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JAPAN

distillation capacity (METI, 2017c). The number of oil refineries in Japan decreased from 40 in 1996 to 22 in
October 2017, and the refining capacity decreased from 5.3 Mbbl/D to 3.5 Mbbl/D (PAJ, 2017). Third
revision to the law, which was enforced in October 2017, was to encourage the refining companies to set atarget for the utilisation rate of residues processing capacity from FY2017 to FY2021. This regulation aims topromote the production of higher-value oil products, such as gasoline and naphtha rather than asphalt, fromresidues.
Competition continues in the domestic oil product market. For example, the number of service stationsin the economy decreased from 59 615 in 1996 to 34 706 in 2013 due to market liberalisation (NPA, 2014).
The Specific Petroleum Law (provisional measures law regulating the importation of specific kinds of refined
petroleum products) was abolished in March 2012. In this context, the Japanese Government aims to establish
a fair and transparent market in terms of quality and prices, where oil product retailers are able to play animportant role in the interaction with final consumers.
NATURAL GASOver the past two decades, demand for natural gas has increased rapidly at an annual rate of 3.7% between
1990 and 2015 (EGEDA, 2017). Natural gas is supplied almost entirely by imports in the form of LNG. Since
Japan prioritises a stable and secure supply of LNG, Japanese LNG buyers have generally paid a higher pricethan those in Europe or the US under long-term ‘take or pay’ contracts with rigid terms on volume and price.
Recently, Japanese gas and electric utilities have sought to reduce their costs because of the deregulation of thegas and electricity markets. The utilities have been striving to secure an LNG supply on flexible terms thatenable them to quickly respond to changes in the market situation and supply gas at lower prices. The
government holds the LNG Producer–Consumer Conference every year to support the development offlexible LNG markets (METI, 2017d). Japan has also been seeking alternative gas supplies; for example, theeconomy promoted technological developments in the production and processing of methane hydrate, which
is abundant in the ocean areas surrounding Japan and is considered to be a future energy resource.
The Fourth Strategic Energy Plan states that the period from 2014 to 2018–20 will be devoted toreforming the electricity and gas systems to build a more liberalised and competitive energy market.
Accordingly, amendments to the Gas Business Act were enacted in June 2015 to fully liberalise the retail market
by approximately 2017 and legally unbundle the gas pipes owned by three city gas utilities—Tokyo Gas, Osaka
Gas and Toho Gas—by April 2022 (METI, 2015b).
COAL

In 2015, coal constituted 27% of the total primary energy supply. Coal will continue to play an important rolein Japan’s energy sector, mainly for power generation and iron, steel, cement, and pulp and paper production.
Japan is the third-largest coal importer in the world after China and India. Japan’s imports constituted
approximately 14% of the total global coal imports in 2015 (IEA, 2017).
ELECTRICITY

After oil, electricity was the second-largest contributor to the total final energy consumption in 2015. The
increased use of electrical appliances in homes, widespread use of personal computers and related information
technology in offices, in addition to a shift in the industry structure to more services-based sectors, have steadily
increased electricity consumption in recent years.
Since 1995, Japan has been partially liberalised to ensure fair competition and transparency: for example,
introduction of independent power producers in 1995; introduction of power producers and suppliers (PPS)
and partial retail competition (over 2 000 kW) in 2000; and expansion of retail competition in 2004 (over500 kW) and 2005 (over 50 kW) (METI, 2002). As of FY2013, approximately 60% of the market was alreadyliberalised in terms of electricity consumption. However, after the earthquake and the subsequent Fukushima
Daiichi nuclear power accident, Japan’s electricity sector faced mounting pressure to further deregulate themarket for a more competitive and transparent electricity supply. The Electricity Business Act was amended
in 2013, 2014 and 2015 to reform the market (METI, 2015b). This reform mainly focuses on three stages: 1)
establishing the Organisation for Cross-regional Coordination of Transmission Operators (OCCTO) in April
2015; 2) ensuring full retail competition from April 2016; and 3) legal unbundling of thetransmission/distribution sector from 2020 and transition to overall liberalisation of retail prices after the128

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JAPAN

unbundling. To avoid a monopoly situation after retail liberalisation in 2016, retail tariffs of designated utilities
will be regulated as a transitional measure and gradually deregulated at the same time or after the legal
unbundling.
Japan’s electricity market faces technical and institutional challenges due to the growing penetration ofvariable renewable power, especially solar photovoltaic (PV), after the introduction of the FiT system in 2012.
To ensure secure and reliable electricity supply while realising active market, the government will open thefollowing markets, in addition to the current wholesale market and reserve tender system: a non-fossil fuelmarket in FY2018 for FiT electricity; a base-load market in 2019; and real-time and capacity markets in FY2020(METI, 2017e). To encourage a cost-effective electricity supply, the government will implement new operation
rules for inter-regional transmission lines in FY2018 on a ‘first-come, first-served’ basis to an implicit auction
system.
HYDROGENIn the Strategic Energy Plan in 2014 (METI, 2014) and the Basic Strategy for Hydrogen in 2017 (METI, 2017f),
Japan has reaffirmed the potential of hydrogen, which can be produced from diverse energy sources, toconstruct a secure and lower-carbon energy system. To realise a ‘hydrogen society’, METI compiled theStrategic Road Map for Hydrogen and Fuel Cells in 2014 and revised it in 2016 (METI, 2016a). This road mapsummarises the steps needed to be taken to make use of hydrogen, from production to transport and storage,
with clear time frames. The revised road map set short-term targets as follows:

Installation cost target for polymer electrolyte fuel cells (800 000 JPY/kW by 2019) and solid oxide fuelcells (1 million JPY/kW by 2021);



Vehicle stock target for fuel cell vehicles (4 million by 2020, 20 million by 2025 and 80 million by 2030);
and

Target for the number of hydrogen stations (160 stations by FY2020 and 320 stations by FY2025).

According to the revised road map, in the mid- to long-term, Japan aims to utilise hydrogen for power
generation in the late 2020s and establish a ‘CO2-free’ hydrogen supply system by around 2040.
FISCAL REGIME AND INVESTMENTS

The Japanese Government recognises the need for encouraging domestic petroleum companies to obtain
upstream oil and gas equities overseas. JOGMEC offers technical support to domestic petroleum companies
in areas such as geological structure studies and mining technologies. In addition, both JOGMEC and theJapan Bank for International Cooperation (JBIC) offer financial support to companies.
In the short-term, the government intends to concentrate on financial support for existing upstream
projects to assist with start-up and continuation. In the mid-term, the government will continue toappropriately support domestic petroleum companies by borrowing money from the market with government
guarantees and building a flexible and effective finance system through JOGMEC, aiming at reducing
geopolitical and technical risks for future projects.
ENERGY EFFICIENCY

The 1979 Energy Conservation Law, established after the oil crises, is the basis of all energy conservation
policies in Japan. It requires improving the energy efficiency of the industrial, building (commercial andhousehold), and transport sectors (METI, 2017g). Based on the law, the government has been implementing
energy efficiency policies through regulation and economic incentives, and the economy achieved a 40%
improvement in terms of energy intensity (final consumption basis) from 1980 to 2014. Regulations include 1)
regular reports on energy efficiency and efforts for energy intensity improvements of 1%/year for factories
and business establishments with energy consumption of 1 500 kl/year; 2) the Top-Runner Programme, which
was introduced in 1998 to establish energy efficiency standards to curb consumption in the residential,commercial and transport sectors; and 3) regular reports on energy efficiency implementation for specifiedscale cargo owners and carriers. The law also requires factories and business establishments with energy
consumption of 3 000 kl/year to appoint qualified energy managers. Economic incentives include subsidies,

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JAPAN

accelerated depreciation and tax reductions for installing efficient equipment or facilities, in addition to R&D
subsidies for high-efficient technologies such as high-performance heat pumps and insulation materials.
Following the earthquake in 2011 and electricity shortage situation, the 1979 Energy Conservation Law
was partially amended in May 2013 to strengthen energy efficiency activities and promote activities forlevelising electricity load. Key amendments included the development of new indicators and guidelines toevaluate ‘peak-shift’ activities and the expansion of the Top-Runner Programme. The Top-Runner Programme
initially covered 11 items, including cars and air conditioners, and expanded to 31 items in 2013. In the 2013
amendments, in addition to energy-consuming items, items that do not consume energy but rather contributeto high efficiency or energy conservation, such as building insulation materials, were added to this program.
In 2014, the revised Strategic Energy Plan established the following initiatives (METI, 2014):
Enhancing Japan’s energy efficiency (already at the highest level in the world) by introducing the mostadvanced technologies for replacing equipment in the industrial sector;Enhancing support and regulatory measures (including the Top-Runner Programme) to increase theadoption of highly efficient equipment in each sector. Expanding the coverage of the program, which
now includes industrial refrigerators, printers, heat pumps, LED lamps and building insulation materials;



Replacing 100% of the lighting with high-efficiency lamps (including LED and organic electroluminescence [EL] lighting) on a flow basis by 2020 and stock basis by 2030;

Achieving net zero energy with regard to newly constructed public buildings by 2020 and all newly
constructed buildings on average by 2030;



Raising next-generation vehicles’ share of new vehicle sales to between 50% and 70% by 2030 while
promoting comprehensive measures, including improving traffic flow such as introducing intelligent
transportation systems (ITS); and

Facilitating the introduction of the energy management system, such as building energy management
system (BEMS), and encouraging the acquisition of the certification of the ISO 50001 standard.
RENEWABLE ENERGY

As mentioned, Japan has a system of FiT. In August 2011, the Act on Purchase of Renewable Energy-Sourced
Electricity by Electric Utilities was passed by the Diet (the Japanese Parliament). This act took effect on 1 July
2012. It requires electric utilities to purchase electricity generated from renewable energy sources (solar PV,
wind power, small- and medium-sized hydropower, geothermal and biomass) based on fixed-period contracts
with fixed prices. Table 5 shows the prices for the FiT in FY2017.
Beginning in April 2017, the government enforced a partial revision to the act to facilitate the installationof authorised capacity, revise the FiT pricing system and obligate the general transmission companies topurchase FiT electricity instead of retail companies under current rules. Regarding the pricing system, therevision will allow the government to determine the purchase prices for the next several years. This new system
is expected to promote renewable energy with longer lead times, such as geothermal, wind, medium hydro andbiomass, by improving the predictability of the projects. To promote renewable energy in a cost-effective
manner, the revision also allows the government to use auctions for determining the FiT prices. The
government began to use the auction system for utility-scale solar PV (METI, 2016b). For other technologies,
METI determined purchase prices for the next three years (METI, 2017h).

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Table 5: Prices for feed-in tariffs from FY2017 to FY2019 unless otherwise specified
Renewable Energy
Solar

Prices (JPY/ kWh)
Over 2 000 kW

Years

Determined though auctions

20

21 + taxa

20- FY2017

28.0/30.0b

10- FY2018

26.0/28.0

10- FY2019

24.0/26.0

10- FY2017 and FY2018

25.0/27.0b

10- FY2019

24.0/26.0

10Over 20 kW

22 + tax

20- from October 2017 to March 2018

21 + tax

20- FY2018

20 + tax

20- FY2019

19 + tax

20- FY2017

18 + tax

20- FY2018

17 + tax

20- FY2019

16 + tax

20

Less than 20 kW (FY2017)

55 + tax

20

36 + tax

20

From 5 000 kW to 30 000 kW (fromOctober 2017 to FY2019)

20 + tax

20

Facilities that utilise existing headrace(from FY2017 to FY2019)12 + tax

20

From 1 000 kW to 5 000 kW (from
FY2017 to FY2019)27 + tax

20

Facilities that utilise existing headrace(from FY2017 to FY2019)15 + tax

20

From 200 kW to 1 000 kW

29 + tax

20

Facilities that utilise existing headrace

21 + tax

20

Less than 200 kW

34 + tax

20

Facilities that utilise existing headrace

25 + tax

20

From 10 kW to 2 000 kW (for FY2017)
Less than 10 kW

Less than 10 kW (Double generation)

Onshore windOver 20 kW (replacement)

Offshore wind
Hydro

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Renewable Energy
Geothermal

Prices (JPY/ kWh)

Years

Over 15 000 kW- New facility

26 + tax

15- Replacement

20 + tax

15- Replacement but reusing utilisingunderground equipment

12 + tax

15- New facility

40 + tax

15- Replacement

30 + tax

15- Replacement but reusing utilisingunderground equipment

19 + tax

15

Methane fermentation gasification

39 + tax

20

Unused woods (less than 2 000 kW)

40 + tax

20

Unused woods (over 2 000 kW)

32 + tax

20

General woods (from October 2017 toFY 2019)

21 + tax

20

Waste (excluding woods)

17 + tax

20

Recycled woods

13 + tax

20

Less than 15 000 kW

Biomass

Source: METI (2017h)
Note: a. consumption tax (8%); b. Solar PV, approved for grid connection in Hokkaido, Tohoku, Hokuriku, Chugoku,
Shikoku, Kyusyu and Okinawa areas is obliged to be installed with a suppression control system. Higher purchase prices
are applied to this case.

Costs incurred by the utilities in purchasing renewable energy-sourced electricity shall be transferred toall electricity customers, who will pay a surcharge for renewable energy at a rate proportional to their electricity
usage. The surcharge for renewable energy has been calculated from May 2017 to March 2018 as follows(METI, 2017h):

Surcharge for renewable energy = Monthly electricity consumption (kWh) × 2.64 JPY/kWhFiT rates and contract periods are to be determined according to factors such as the type of renewable
power, form of installation and scale of renewable energy sources. Contract rates and periods shall be reviewed
by METI and are based on the recommendations of an independent committee in the ministry.
Table 6 indicates the installed generation capacity for each renewable source of energy after the
introduction of FiT (METI, 2013; METI, 2017h). Almost five years after the introduction of FiT, 105 136 MWof renewable capacity were authorised compared with the accumulated renewable capacity at the end of June
2012, that is, before the introduction of FiT of 20 600 MW. This indicates that if all the authorised capacity is
installed, the generation capacity based on renewable energy is more than six times since the introduction of
FiT. Non-residential solar PV has flourished in Japan. Its installed capacity and authorised capacity under thesystem amounts to 28 753 MW and 79 047 MW, respectively, constituting 80% of the total newly installedcapacity and 75% of the authorised capacity. Biomass follows in terms of authorised capacity. The start-up
renewable capacity is 35 392 MW, approximately one-third of the authorised capacity.

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Table 6: Installed generation capacity by renewable energy after the introduction of FiT (MW)
Authorised capacity
under FiT

Installed capacity
By the end of June 2012
Solar (Residence)

Newly installed under FiT(July 2012–March 2017)

July 2012–March 2017

4 700

4 745

5 492

900

28 753`79 047

Wind

2 600

2 852

6 972

Medium hydro

9 600

239

1 118

Biomass

2 300

851

12 416

500

15

88

20 60035 392

105 136

Solar (Non-residence.
More than 10 kW)

Geothermal
Total
Source: METI (2013, 2017h).

NUCLEAR ENERGY

There were 54 commercial nuclear reactors in Japan in 2010, the last year before the Fukushima Daiichi nuclear
power plant accident. As of December 2017, the number of commercial reactors decreased to 40 due to thedecommission of the Fukushima Daiichi nuclear power station5 and eight other reactors:6 Tsuruga Unit 1,
Mihama Unit 1 and Unit 2, Shimane Unit 1, Genkai Unit 1, Ikata Unit 1 and Oi Unit 1 and Unit 2. Owners of
the eight reactors decided on the retirements due to the aging of the facilities and the large amount of additionalcosts to meet the new safety regulations enforced in June 2013.
As mentioned above, 2014 was the first year without nuclear generation since its introduction. After the
Oi Unit 3 and Unit 4 ceased operations for periodic inspections in September 2013, no nuclear reactors wererestarted until August 2015. The Sendai nuclear power plant became the first reactor to restart under the new
regulatory scheme. In October 2016, the NRA gave the final safety approval to Ikata Unit 3, Mihama Unit 3,
Sendai Unit 1 and Unit 2 and Takahama Units 1 to 4. The Nuclear Regulation Authority (NRA) approved a
20-year license extension for Takahama Units 1 and 2; this was the first lifetime extension under the current
regulatory scheme. However, several nuclear reactors in Japan face challenges due to the decisions made by
local district courts. For example, in March 2016, the Otsu district court suspended the operation of Takahama
Unit 3 and Unit 4, which were restarted in January and February 2016, respectively. In 2017, the suspension
was overturned by the Osaka high court and these reactors were restarted.
Regarding the nuclear fuel cycle, Japan promotes the reprocessing process and the effective utilisation of
the plutonium retrieved. Although Japan continues to maintain its nuclear fuel cycle policy, the government
decided to decommission Monju, the prototype fast breeder reactor, in December 2016 due to repeatedtroubles. For future R&D of nuclear fuel cycle, the government is discussing alternative approaches, including
cooperation with France in the ASTRID project (CAS, 2016). Despite its prolonged efforts, Japan has not yet
decided the site for final disposal. To further economy-wide and regional comprehension about the final
disposal site, the government published an economy-wide map of scientific features for geological disposal ofhigh-level radioactive waste in July 2017 (METI, 2017i).

5 A total of six reactors. The reactor owner (Tokyo Electric Power Company) decided to decommission units 1-4 in April

2012 and units 5 and 6 in January 2014.
6 Except for Oi Unit 1 and Unit 2, reactor owners announced their decisions in March 2015. Decommission of the Oi Unit
1 and Unit 2 was decided by the plant owner in December 2017.

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CLIMATE CHANGE

According to the Kyoto Protocol, Japan was obliged to reduce GHG emissions by 6% on average between
2008 and 2012 from the 1990 level, and the economy has exceeded this commitment by reducing emissions
by 8.4%. In fact, average GHG emissions in Japan during the commitment period increased by 1.4%, from
1 261 million tonnes of CO2 equivalent to 1 278 million tonnes of CO2 equivalent, partly due to additional
fossil fuel consumption after the earthquake and the subsequent nuclear plant shutdowns. However, the carbon
sink by forest ecosystems (equivalent to a 3.9% reduction) and the Kyoto Mechanism Credit (equivalent to a
5.9% reduction) contributed to achieving the commitment level (MOE, 2014).
To generate further emission reductions, Japan introduced the Tax for Climate Change Mitigation in
October 2012 (MOE, 2012). This tax is levied on crude oil/oil products, gas and coal. The tax was raised inphases in April 2014 and 2016 (Table 7); the tax value is JPY 289 per tonne CO2 for each kind of product sinceApril 2016. Revenue from this tax is used for implementing various measures to promote energy efficiency
and renewable energy, in addition to the use of clean fossil fuels.
Table 7: Tax for the promotion of global warming countermeasures
October 2012

April 2014

April 2016

Crude Oil/Oil Product (JPY/kL)

250

500

760

Gas (JPY/tonne)

260

520

780

Coal (JPY/tonne)

220

440

670

Source: MOE (2012).

Japan also has prefectural-level emission policies, such as emission trading schemes in Tokyo, Kyoto andSaitama. Sectoral coverage and the level of regulation vary by prefecture; Tokyo focuses on the industry andcommercial sectors, while Kyoto includes transport as well. For example, the level of regulation in Tokyo is asfollows: 8% and 17% reductions in commercial buildings and 6% and 15% reductions in factories in FY2010–
14 and FY2015–19, respectively, from the average emissions in three consecutive years in FY2002–07.
The private sector has been working towards a low-carbon society. KEIDANREN (Japan Business
Federation), which is a comprehensive economic organisation, published a voluntary action plan
(KEIDANREN, 2017). The action plan comprises two phases: Phase I was published in 2013, with a focus
on 2020 targets, and Phase II was published in 2015, with a focus on 2030 targets. Voluntary targets, such as
CO2 reduction, were individually formulated by 62 industries/companies in the industrial, commercial,transport and transformation sectors.
In July 2015, Japan submitted its Intended Nationally Determined Contribution (INDC) to the United
Nations Framework Convention on Climate Change (UNFCCC, 2015). The economy determined its emission
reduction level based on the government’s Long-term Energy Supply and Demand Outlook. Japan’s INDC
towards its post-2020 GHG is a reduction of 26% by FY2030 compared with FY2013 (25.4% reduction
compared with FY2005), equivalent to 1 042 Mt of CO2 in 2030.
In the same month of Japan’s INDC submission, a voluntary action plan was decided by 10 former
general electric power companies, Japan Atomic Power Company (J-POWER) and 23 PPS. This action plantargets an emission intensity of 0.37 kgCO2/kWh in 2030, which is consistent with Japan’s Long-term Energy
Supply and Demand Outlook and INDC. To support the voluntary action plan, the government amended
several laws, in particular, the Energy Conservation Law (conversion efficiency standards on new fossil fuelplants: 42% for coal-fired and 50.5% for LNG-fired on a higher heating value basis) and the Act on
Sophisticated Methods of Energy Supply Structure (non-fossil’s share standards for retail companies: 44% in2030) (METI, 2017a).

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THE NEXT STRATEGIC ENERGY PLAN

In August 2017, the government began discussions for the Fifth Strategic Energy Plan at the Strategic Policy
Committee of the Advisory Committee for Natural Resources and Energy (METI, 2017b). According to the
METI Minister Mr Hiroshige Seko, the fifth plan is expected to retain the core directions in the fourth plan,
while considering the developments in the last few years. As of January 2018, the fifth plan is underconsideration.
ELECTRICITY MARKET REFORM

To ensure secure and reliable electricity supply while realising active markets, the government will open thefollowing new markets in addition to the current wholesale market: non-fossil fuel market in FY2018 for FiT
electricity, base-load market in 2019 and real-time and capacity markets in FY2020 (METI, 2017e). To
encourage cost-effective electricity supply, the government will implement new operation rules for interregional transmission lines in FY2018 on a ‘first-come, first-served’ basis to an implicit auction system.
FINAL DISPOSAL SITE FOR HIGH-LEVEL RADIOACTIVE WASTE

As mentioned in the Nuclear Energy section, the government published an economy-wide map of scientificfeatures for geological disposal of high-level radioactive waste in July 2017 to deepen the general public’s
comprehension about the final disposal site (METI, 2017i).
THE 6 TH LNG PRODUCER–CONSUMER CONFERENCE

Japan has been holding an annual LNG Producer–Consumer Conference since 2012 as a platform to exchange
ideas and enhance cooperation among producers, consumers and all the key stakeholders (METI, 2017d). The
6th Conference held in October 2017 focused on the following key themes: 1) producer–consumer cooperation
towards LNG markets in Asia; 2) new LNG opportunities driven by innovation; 3) LNG as a transport fuel;and 4) flexible LNG markets and spot pricing. Mr Hiroshige Seko, the METI minister, announced that Japan
will contribute to expanding the LNG market in Asia through financing and human resource development.
The 7th Conference will be held in Nagoya in 2018.

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REFERENCES

BP (British Petroleum) (2017), BP Statistical Review of World Energy,
https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review2017/bp-statistical-review-of-world-energy-2017-full-report.pdf.
CAS (Cabinet Secretariat) (2016), Ministerial Meeting on Nuclear,
http://www.cas.go.jp/jp/seisaku/genshiryoku_kakuryo_kaigi/.
Conglin Xu and Laura Bell (2017), ‘Worldwide Oil, Natural Gas Reserves Inch Higher in 2017’, Oil & Gas
Journal, Vol 115. No. 12, Dec 2017.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
IEA (International Energy Agency) (2017), Coal Information 2017.
KEIDANREN (2017), The Commitment to a Low Carbon Society, http://www.keidanren.or.jp/policy/vape.html.
METI (Ministry of Economy, Trade and Industry) (2002), Report of the Electricity Industry Committee of theAdvisory Committee for Natural Resources and Energy,
http://www.enecho.meti.go.jp/category/electricity_and_gas/electric/summary/pdf/tousin.pdf.
–– (2013), Installed Generation Capacity by Renewable Energies as of the End of June 2013,www.meti.go.jp/press/2013/11/20131118003/20131118003.html.
–– (2014), Strategic Energy Plan (in Japanese), www.meti.go.jp/press/2014/04/20140411001/201404110011.pdf.
–– (2015a), Long-term Energy Supply and Demand Outlook,www.meti.go.jp/press/2015/07/20150716004/20150716004_2.pdf.
–– (2015b), Electricity System Reform,

http://www.enecho.meti.go.jp/category/electricity_and_gas/electric/system_reform.html.
–– (2016a), Revised Strategic Road Map for Hydrogen and Fuel Cells,
http://www.meti.go.jp/press/2015/03/20160322009/20160322009-c.pdf.
–– (2016b), Key Points of the Amendments to the FiT Law,
http://www.enecho.meti.go.jp/category/saving_and_new/saiene/kaitori/dl/kaisei/01_point.pdf.
–– (2017a), Energy White Paper 2017, http://www.enecho.meti.go.jp/about/whitepaper/2017html/.
–– (2017b), Basic Policy Committee,
http://www.enecho.meti.go.jp/en/committee/council/basic_policy_subcommittee/.
–– (2017c), About the Third Regulation in the law on the promotion of the use of non-fossil energy sources and effective use offossil energy materials by energy suppliers,
http://www.meti.go.jp/committee/sougouenergy/shigen_nenryo/pdf/021_06_00.pdf.
–– (2017d), LNG Producer Consumer Conference, http://www.lng-conference.org/english/index.html.
–– (2017e), Measures to Realize the Energy Mix in 2030 – Nuclear, Fossil Fuels and Heat,
http://www.enecho.meti.go.jp/committee/council/basic_policy_subcommittee/023/pdf/023_005.pdf.
–– (2017f), Basic Strategy for Hydrogen, http://www.meti.go.jp/press/2017/12/20171226002/201712260021.pdf.
–– (2017g), Overview of the Energy Conservation Law,
http://www.enecho.meti.go.jp/category/saving_and_new/saving/summary/pdf/2017_gaiyo.pdf.
–– (2017h), Feed-in Tariff,
http://www.enecho.meti.go.jp/category/saving_and_new/saiene/kaitori/index.html.
–– (2017i), Economy-Wide Map of Scientific Features for Geological Disposal of High-Level Radioactive Waste,
http://www.enecho.meti.go.jp/category/electricity_and_gas/nuclear/rw/kagakutekitokuseimap/.
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MOE (Ministry of the Environment) (2012), Details on the Carbon Tax (Tax for Climate Change Mitigation),
www.env.go.jp/en/policy/tax/env-tax/20121001a_dct.pdf.
–– (2014), Report on GHG Emissions During Kyoto Protocol Commitment Period,www.env.go.jp/press/press.php?serial=18353.
NPA (National Petroleum Dealers Association) (2014), The Number of Service Stations by Prefecture (in Japanese),www.sekiyu.or.jp/topics/data_a.html.
PAJ (Petroleum Association of Japan) (2017), Oil Statistics, www.paj.gr.jp/english/statis/index.html.
UNFCCC (United Nations Framework Convention on Climate Change) (2015),
Submission of Japan’s Intended Nationally Determined Contribution (INDC),
www4.unfccc.int/submissions/INDC/Published%20Documents/Japan/1/20150717_Japan's%20IND
C.pdf.
U SEF UL LI N K S
Agency for Natural Resources and Energy—www.enecho.meti.go.jp/en/
Institute of Energy Economics, Japan—eneken.ieej.or.jp
Ministry of Economy, Trade and Industry—www.meti.go.jp/english/index.html
Ministry of the Environment—www.env.go.jp/en/index.html

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REPUBLIC OF KOREAR E P U B L I C O F KO R E A
I N T ROD U C T I ON

The Republic of Korea (Korea) is located in north-east Asia between China and Japan. It has an area of
100 284 square kilometres (km2) and a population of 51 million people as of 2015. Korea’s population density
is very high, with an average of more than 520 people per km2. Approximately 20% of the population lives in
Seoul, Korea’s capital and its largest city. The economy’s geography consists of hills and mountains with wide
coastal plains in the west and the south. The climate is relatively moderate with four distinct seasons. Air
conditioning is commonly necessary during the tropical hot summers and heating is required during the bitterly
cold winters.
Over the past few decades, Korea has become one of Asia’s fastest growing and most dynamic
economies. The gross domestic product (GDP) has increased at 5.1% every year from 1990 to 2015, reaching
USD 1.8 trillion (2010 USD purchasing power parity [PPP]) in 2015. GDP per capita (2010 USD PPP) income
in 2015 was USD 34 206, about three times higher than in 1990. Korea’s major industries include
semiconductors, shipbuilding, cars, petrochemicals, digital electronics, steel, machinery and parts and materials.
Korea has few indigenous energy resources. It has no oil resources except for a small amount ofcondensate, only 315 million tonnes of recoverable coal reserves and 5.7 billion cubic metres of natural gas.
Thus, to sustain its high level of economic growth, Korea imports large quantities of energy products. It
imported about 87% of its primary energy supply in 2015. In the same year, it was the world’s fifth-largest
importer of crude oil, second-largest importer of liquefied natural gas (LNG) and fourth-largest importer ofcoal.
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesc, dArea (km2)

100 284

Population (million)

51

Oil (million barrels)–Gas (billion cubic metres)

5.7

GDP (2010 USD billion PPP)

1 745

Coal (million tonnes)

315

GDP (2010 USD PPP per capita)

34 206

Uranium (kilotonnes U)–

Sources: a UN (2017); b EGEDA (2017); c EIA (2017); d KEEI (2016).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Korea’s total primary energy supply almost tripled between 1990 and 2015 from 93 million tonnes of oil
equivalent (Mtoe) in 1990 to 273 Mtoe in 2015. In particular, from 1990 to 2000, energy supply increased at
an annual average rate of 7.3%, far exceeding the economic growth rate of 6.5% for the same period. Likewise,
per capita primary energy supply grew from 2.2 tonnes of oil equivalent in 1990 to 5.3 tonnes of oil equivalent
in 2015. This increase was similar to that in Japan and most European economies.
In 2015, Korea’s total primary energy supply was 273 Mtoe, a 1.6% increase from the supply in theprevious year. In terms of energy source, oil represented the largest share (38%), followed by coal (30%) andgas (14%). The remaining 18% of the primary energy supply came from nuclear and renewable energy sources.
Energy imports accounted for about a quarter of Korea’s total import value in 2015.
The oil supply in 2015 was 103 Mtoe, a 6.6% increase over the previous year. In 2015, the economy
imported 82% of its crude oil from the Middle East. With regard to coal, the supply in 2015 totalled 81 Mtoe,
a 1.1% decrease from the previous year. Korea has modest reserves of low-quality, high-ash anthracite coal,
which are insufficient to meet its domestic consumption. Thus, almost all of Korea’s coal consumption is met

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by imports. Korea is the world’s fourth-largest importer of both steam coal and coking coal. The main coal
imports come from Australia; Indonesia; Russia; Canada; China and the United States.
Since the introduction of LNG in 1986, natural gas use in Korea has grown rapidly. The gas supply
reached 39 Mtoe in 2015. Its share of the primary energy supply was 14% in the same year. Most of Korea’s
LNG imports come from Qatar; Oman; Indonesia; Malaysia; Australia and Brunei Darussalam. Korea began
producing natural gas domestically in November 2004 after a small quantity of natural gas was discovered in
the Donghae-1 offshore field in the south-east.
Korea’s electricity generation in 2015 was 548 terawatt-hours (TWh), a 0.4% increase from 2014.
Generation by thermal sources, including coal, oil and natural gas, accounted for 68% of the total electricity
generated, followed by nuclear energy source at 30% and hydropower source and others at 2%.
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

51 292

Industry sector

49 129Net imports and others

237 007

Transport sector

33 410

Thermal

371 960

Total primary energy supply

272 559

Other sectors

44 331

Hydro

5 796

Coal

80 836Non-energy

47 328

Nuclear164 762

Oil

102 682

Final energy consumption*

126 579

Others

8 852

Gas

39 335Coal

11 243

Renewables

4 003

Oil

43 521Others

45 703Gas

20 498Renewables

2 429

Electricity and others

48 888

Total power generation

551 370

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half the municipal solid waste used in
power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

Korea’s final energy consumption in 2015 was 127 Mtoe, which was a 2.2% increase from the previous year.
The industrial sector accounted for the largest share at 39%, while the transport sector accounted for 26%.
The remainder (35%) was used in others (combined residential, commercial and agriculture sectors). In general,
consumption in the industrial sector has weakened since the late 1990s, and consumption in the transport andcommercial sectors have increased.
By energy source, electricity and others accounted for 39% of final energy consumption, followed by oil(34%), natural gas (16%) and coal (8.9%). Natural gas consumption has increased significantly because of theeconomy’s policy measures.
ENERGY INTENSITY ANALYSISThe 2.8% growth of Korean GDP in 2015 resulted in a 1.2% decrease in the energy intensity of the economy’s
total primary energy supply. This was an economy-wide energy intensity level decrease of 1.9 tonnes of oil
equivalent/million USD. With regard to final energy consumption, the energy intensity level decreased by
0.7%, from the 2014 level of 73.1 tonnes of oil equivalent/million USD to 72.5 tonnes of oil equivalent/million USD in 2015. This was mostly driven by the decreasing energy consumption in the industry sector,
which had decreased 0.2% from the previous year.

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Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

158.1

156.2

–1.2

Total final consumption

100.3

99.8

–0.5

Final energy consumption excluding non-energy

73.1

72.5

-0.7

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

In 2015, the share of modern renewable energy in final energy consumption was 1.3%, a decrease of 0.3%
from the previous year. Increased use of fossil fuels and others, especially coal, combined with the expansionof traditional biomass contributed to the decrease in the share of modern renewable energy by 18% over theprevious year.
Table 4: Renewable energy share analysis, 2014 vs 2015
2014

2015

124 014126 579

Change (%)
2014 vs 2015
2.1

120 880

123 428

2.1

Traditional biomass*

1 144

1 554

36

Modern renewables*

1 990

1 597

−20

Share of modern renewables in final energy
consumption (%)

1.6%

1.3%

−18%

Final energy consumption (ktoe)
Non-renewables (fossils and others)

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass. This is because solid
biofuels are typically used in these sectors for heating (residential) and cooking (residential and commercial) using
inefficient technologies that often have adverse effects on human health. This definition is applied to all APEC member
economies, including those that are members of the Organisation for Economic Cooperation and Development (OECD)and those that are not (Non-OECD). All other renewables (e.g. hydro and geothermal energy), including biogas andwood pellets, are considered modern renewables, but data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKIn the past, Korea’s energy policy has focused on ensuring a stable energy supply to sustain economic growth.
The government is currently seeking a new direction in energy policy with the aim of supporting sustainable
development that fully considers the 3Es (energy, economy and environment).
The responsibility for energy policy development and implementation is divided among a number ofgovernment institutions. The Ministry of Trade, Industry and Energy (MOTIE), which succeeded the Ministryof Knowledge Economy (MKE) in 2013, is the primary government body for energy policy.
In 2006, the Korean Government established the National Energy Committee, which is chaired by the
President and includes governmental and non-governmental experts. The committee’s role is to deliberate
upon and mediate among major energy policies and plans. In addition, it discusses the National Basic Plan for
Energy, emergency preparedness, foreign energy resource development, nuclear energy policy, thecoordination of energy policies and projects, the prevention and settlement of social conflict related to energy
issues, the transportation of energy and the physical distribution plan, the effective execution of the energy
budget, and energy issues within the United Nations Framework Convention on Climate Change (UNFCCC).

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As part of its liberalisation efforts in the energy sector, in 2001, the government established the Electricity
Regulatory Commission to take charge of regulations in the electric power sector and to manage technical andprofessional competition policy. There is no regulatory commission for the gas industry. The Fair Trade
Commission is Korea’s anti-trust agency and monitors monopoly problems and unfair business practices inthe energy sector.
The Korea Energy Economics Institute (KEEI) develops energy policies related to the production ofenergy statistics. It also considers policies with regard to consumption and supply overviews, energy
conservation and climate change, the petroleum industry, the gas industry, the electricity industry, and the new
and renewable energy industry among others. It is financed directly by the government.
The Korea Institute of Energy Technology Evaluation and Planning, funded by the government, is
Korea’s major energy technology research institute. Its mission is to contribute to growth across the economy
by developing industrial core energy technologies and deploying outcomes.
The Korea Energy Agency plays a key role in achieving Korea’s research and development (R&D) policy
goals for energy efficiency, energy conservation, clean energy and new and renewable energy technologies. It
also administers R&D planning, financial support and management.
In August 2008, faced with high energy prices and rising concerns over climate change, Korea announced
a long-term strategy, which would determine the direction of its energy policy until 2030.
On 14 January 2014, Korea launched the Second Energy Basic Plan, which is the main official plan in
the energy sector with a timeframe of up to 2035 (MOTIE, 2014a). According to the Second Energy Basic
Plan, total primary energy consumption is projected to grow at an annual average rate of 1.3% between 2011
and 2035. Final energy consumption will grow at 0.9% per year. Energy intensity is expected to drop from 0.26
tonnes of oil equivalent/million KRW in 2011 to 0.18 tonnes of oil equivalent/million KRW in 2035 with an
improvement of 1.4% per year, resulting in a 30% improvement of energy intensity, which is equivalent to a
13% reduction in final energy consumption.
The government has proposed the following six major policy strategies:
 Moving to an energy management-oriented policy;
 Building a power generation system based on distributed generations (DGs);
 Ensuring harmonisation between the environment and safety;
 Strengthening energy security; Building a stable energy supply according to source; and Pursuing an energy policy together with the public.
Heavy dependence on the Middle East for its crude oil supply led the economy to pursue a policy ofdiversifying its oil supply during the outlook period. The state-owned Korea National Oil Corporation(KNOC) will continue to be responsible for the economy’s preparedness for an oil emergency by operating oilstockpiling facilities and pursuing stakes in oil projects around the world.
In the natural gas industry, the state-owned monopoly Korea Gas Corporation (KOGAS) will continue
to be responsible for managing the import, storage, transmission and wholesale distribution of LNG. The
electricity industry will continue to be dominated by the state-owned Korea Electric Power Corporation(KEPCO). It is possible that restructuring and liberalisation may evolve in the future, allowing more private
participation in the oil, gas and electricity industries.
ENERGY MARKETSMARKET REFORM

Korea has been restructuring its energy sector since the late 1990s when it introduced the principle of freecompetition in industries traditionally considered natural monopolies, such as electricity and natural gas. In
January 1999, in a move to phase-in competition in the electricity industry, the government announced the141

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Basic Plan for Restructuring the Electricity Industry. The plan included the unbundling and privatisation of
Korea’s state-owned electricity monopoly, KEPCO.
Part of the plan has been implemented, including the establishment of the Korea Power Exchange andthe Korea Power Commission in April 2001. The power generation part of KEPCO was split into six wholly
owned companies—five thermal generation companies and the Korea Hydro & Nuclear Power Company
Limited. The five thermal generation companies were to be privatised in stages. However, in July 2008, thegovernment announced there would be no further privatisation of KEPCO and its five subsidiaries. At theend of 2015, 51% of KEPCO, a holding company, was owned by the Korean Government. KEPCO is still adominant player in the electricity sector, controlling 79% of total power generation and 100% of transmission
and distribution in Korea (KEEI, 2016).
The Korean Government has also made moves to restructure the gas industry. In November 1999, thegovernment sold 43% of its equity in KOGAS and developed the Basic Plan for Restructuring the Gas Industry
to promote further competition in the industry. The plan outlines a scheme to introduce competition into theimport and wholesale gas businesses, promote the development of the gas industry and enhance consumer
choice and service quality. A detailed implementation plan was announced in October 2001. The plan covers
ways to achieve the smooth succession of the existing import and transportation contracts, the privatisation ofimport and wholesale businesses, the stabilisation of prices and the balance of supply and consumption andthe revision of related legislation and enforcement (KEEI, 2002).
With regard to competition in the import and wholesale sectors of KOGAS, a final decision on whether
to split the sectors from KOGAS or introduce new companies will be made following discussions among
stakeholders. Given the strong public interest in this sector, the existing public utility system is expected to be
maintained. Competition in the retail sector, which is currently operated under a monopoly system within eachregion, will be introduced in stages in conjunction with the progress made in the wholesale sector. As of theend of 2017, no decision on the liberalisation of the gas market had been made.
OIL, GAS AND ELECTRICITY MARKETSOILGiven Korea’s dependence on oil imports, the government has been trying to secure supplies for the shortand long terms. To ease short-term supply disruptions and to meet International Energy Agency (IEA)
obligations, the Korean Government has been increasing its oil stockpile since 1980. At the end of 2017, Korea
held 238 million barrels in oil stock. This economy-wide stockpile capacity substantially exceeds the IEA’s 90day requirement.
The state-controlled KNOC has been actively exploring and developing oil and gas, both locally andabroad, to improve energy security. As of the end of 2017, it was conducting 31 projects in 17 countries. Privatecompanies (including SK Energy, GS Caltex, S-Oil and Hyundai Oil Bank) are also active in the oil and gas
sector as well as in the downstream market and wholesale imports.
To encourage private companies to invest in development projects overseas, the Korean Government
has expanded its policy of supplying long-term, low-interest loans through the Special Account of Energy andResources.
Korea has also been trying to diversify its crude oil supplies. The number of supply sources increased
from nine in 1980 to 29 in 2016; however, the economy’s dependency on oil imports from the Middle Eastremains high (86% in 2016). Korea is also actively strengthening its bilateral relations with oil-producing
economies as well as its multilateral cooperation through the IEA, the Asia-Pacific Economic Cooperation(APEC) forum, the Association of South-East Asian Nations (ASEAN)+3, the International Energy Forumand the Energy Charter to enhance its crisis management capabilities. In particular, the government plans toplay a leading role in energy resource development and trade in north-east Asia by creating a collaborative
framework on energy cooperation.
NATURAL GAS

Korea introduced natural gas-based city gas to the residential sector in the 1980s to reduce the economy’s
dependence on imported oil. Since then, gas use has grown rapidly and has replaced coal and oil in the142

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residential sector. KOGAS has a monopoly over Korea’s natural gas industry, including the gas import, storage,transport and wholesale businesses. Thirty-two city gas companies operate in the gas retail business in eachregion of the economy. Not only is KOGAS the world’s second-largest LNG buyer, it also promotes thedevelopment of natural gas resources abroad in economies such as Australia, Canada and Iraq.
The Twelfth Plan for Long-Term Natural Gas Demand and Supply, finalised by MOTIE in December
2015, projected natural gas consumption to decrease by 0.34% per year from 2014–29 (MOTIE, 2015). By
sector, the city gas sector’s consumption of natural gas is projected to increase by 2.1% per year, while theconsumption of gas for power generation is projected to decrease by 4.2% per year.
The Korean Government is considering new regulatory reforms on sales restrictions for private LNG
importers and on using storage facilities in the duty-free zone to facilitate international trading businesses.
ELECTRICITY

Korea’s economic growth has increased its electricity consumption substantially over the past few decades.
Throughout the 1990s, the average annual growth rate was 9.5%. Then, between 1990 and 2015, installedcapacity increased almost five-fold, from 21 gigawatts (GW) in 1990 to 103 GW in 2015.
The Eighth Basic Plan for Long-term Electricity Demand and Supply (2017–31), finalised by MOTIE in
December 2017, projects that electricity consumption will grow by 2.1% per year from 2017 to 2031 and that
additional capacity of 16 GW will be required by 2031 (MOTIE, 2017). If decommissioning is taken into
account, this translates to about 124 GW of the total generation capacity for this period.
Korea’s electricity industry is dominated by KEPCO, which was separated into six power generation
subsidiaries in April 2001: Korea Hydro & Nuclear Power, which owns the economy’s nuclear energy power
plants and large hydroelectric dams, and five state-owned generating companies, which took over ownershipof the economy’s thermal power plants. KEPCO retained the economy-wide transmission and distribution
grids.
To rectify an energy supply and consumption structure that is overly dependent on oil, the constructionof oil-fired power plants has been strictly controlled and the development of nuclear, coal and natural gas
electricity generation units has been promoted. Gas-fired power plants were first introduced in 1986. Korea
has been building nuclear energy power plants since the 1970s because nuclear energy is a strategic priority forthe government. However, it announced its energy transition roadmap which aims to replace nuclear and coal
generation with renewables and natural gas in October 2017. During the period of the Eighth Basic Plan, fivenuclear power plants are scheduled for construction while 12 nuclear energy power plants are scheduled fordecommissioning. The share of total electricity production capacity from nuclear energy power plants is
projected to decrease from 19% in 2017 to 12% by 2031.
FISCAL REGIME AND INVESTMENTIn December 2009, the Korean Government approved tax reforms to foster a business-friendly environment
and to promote investment. The tax changes included a reduction in corporate tax rates and an increase in tax
benefits for R&D.
In 2009, the corporate tax rate was 22% on taxable income over KRW 200 million and 13% on taxable
income below that amount. Under the tax reforms, these rates were scheduled to be reduced further from 22%
in 2009 to 20% in 2010, and from 11% to 10% for the same period, respectively. The tax reduction for the
lower bracket was implemented as scheduled, while the implementation for the higher bracket was delayed.
Since 2012, the corporate tax rate has been 22% on taxable income over KRW 20 billion, 20% on KRW
200 million to KRW 20 billion and 10% on taxable income below KRW 200 million.
To promote investment in R&D, which will boost economic growth, the government has increased its
tax assistance for R&D. The measures include an R&D reserve fund, an increase in investment tax credits for
R&D facilities and an increase in the deduction for R&D grants paid by corporations to universities from 50%
to 100%.

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ENERGY EFFICIENCYThe Korean Government has introduced various policy measures to improve energy efficiency, including
energy-consumption management schemes for end users, adjustment of the energy pricing system and theprovision of incentives for companies to invest in energy efficiency. These policy measures aim to improveenergy efficiency by 8.7% by 2017 compared with 2012 and to save 9.3 Mtoe in 2017. Announced in December
2014, the measures are part of Korea’s long-term energy plan, which aims to achieve a 1.4% annual energy
efficiency improvement by 2035, compared with that in 2011.
RENEWABLE ENERGY

In September 2014, the Korean Government announced the Fourth National Basic Plan for New andRenewable Energy (MOTIE, 2014c). According to the plan, the government aims to replace 11% of the total
primary energy supply with new and renewable energy (NRE) by 2035. The development of solar and wind
power as the main energy sources will also enable 13% of the total electric energy in Korea to be supplied by
NRE by 2035.
CLIMATE CHANGE

On 15 August 2008, Korea announced a new Low-Carbon, Green Growth vision aimed at shifting the
traditional development model of fossil fuel-dependent growth to an environmentally friendly model. To
realise this vision, the Presidential Commission on Green Growth was established in February 2009. The Basic
Act on Low Carbon and Green Growth was subsequently submitted and took effect in April 2010. Thislegislation provided the legal and institutional basis for green growth. To implement this vision more effectively,
the National Strategy for Green Growth was adopted in June 2009 together with the Five-Year Plan for Green
Growth in June 2014 (Government of Korea, 2014a).
The National Strategy for Green Growth calls for the construction of a comprehensive, long-term (2009–50) master plan to address the challenges caused by climate change and resource depletion. The strategy
consists of three main objectives and ten policy directions: Mitigating climate change and achieving energy independenceo Effectively reducing greenhouse gas emissions (MKE, 2009);
o Reducing fossil fuel use and enhancing energy independence; ando Strengthening the capacity to adapt to climate change.
 Creating new engines for economic growtho Developing green technologies;
o Greening existing industries and promoting green industries;o Advancing the industrial structure; ando Engineering a structural basis for a green economy.
 Improving the quality of life and enhancing international standingo Greening the land and water, and building a green transportation infrastructure;o Bringing the green revolution into people’s daily lives; ando Becoming a role model for the international community as a green growth leader.
N OTA B L E E N E RG Y D E V E L O P M E N T SRESPONSE TO CLIMATE CHANGE
NEW BUSINESS MODELS TO RESPOND TO CLIMATE CHANGE

In July 2014, MOTIE introduced six new energy-related businesses based on emerging business models to
reduce CO2 emissions and increase energy efficiency (MOTIE, 2014b). MOTIE also established the Energy

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Efficiency and Climate Change Bureau for more efficient policy support. Plans for R&D in related technology
and regulation reforms were announced in December 2014 and April 2015 (Government of Korea, 2014b and2015).
The six business models are the following:
1. A consumption management service, which collects electricity saved from buildings and factories
using electricity-saving devices and sells it to the electricity trading market.
2. An integrated energy management service, which connects finance, insurance and an energy
management system (EMS) and provides systems maintenance for companies.
3. An independent micro-grid, which replaces diesel generators with NRE generators and an electricity
storage system (ESS).
4. Photovoltaic equipment rental, which lends photovoltaic equipment to households and receives
payment through electricity gains.
5. A recharging service for electric vehicles, which provides paid recharging.
6. Used-heat recycling from thermal power plants, which utilises used heat in diversified farming.
These business models focus on reducing the consumption of fossil-fuel electricity and on increasing
R&D investments to develop related technologies, such as carbon capture and storage (CCS), ESSs and EMSs.
KOREA’S MITIGATION TARGET AND ITS AMBITION

In June 2015, the Korean Government announced its Intended Nationally Determined Contribution (INDC)
towards achieving the objective of Article 2 of the UNFCCC. Korea plans to reduce its greenhouse gas (GHG)
emissions by 37% from the business-as-usual (BAU 850.6 MtCO2 equivalent) level by 2030 across all economic
sectors, based on the BAU projection of the Korea Energy Economics Institute and the Energy and GHG
Modelling System (KEEI-EGMS).
According to CAIT of the World Resources Institute (WRI), Korea accounts for approximately 1.4% of
global GHG emissions, including land use, land-use change and forestry (LULUCF). Korea’s mitigation
potential is limited because of its industrial structure, which comprises a large share of manufacturing (32% asof 2012), and the high-energy efficiency of its major industries. Further, given the decreased level of public
acceptance following the Fukushima accident, there are now limits to the extent that Korea can make use of
nuclear energy, one of the major mitigation measures available to it.
To meet its INDC, the Korean Government announced the First Basic Plan Responding Climate Change
in December 2016 that includes basic roadmap to national GHG reduction in 2030 (Government of Korea,2016). It provides comprehensive policy directions for expanding use of renewable energy, increasing power
generation using clean fuel, improving energy efficiency, utilising a carbon market, increasing climate
technology investment and fostering new energy-related businesses.
ENERGY TRANSITION FROM NUCLEAR AND COAL TO RENEWABLES AND NATURAL GAS

In October 2017, the Korean Government released its Energy Transition Roadmap that aims to reduce nuclear
and coal use and replace them with increased use of renewables and natural gas (Government of Korea, 2017).
Under the new energy roadmap, it will nullify plans to construct new nuclear reactors and will not allow life
extensions for existing nuclear reactors.
Natural gas and renewable energy sources would have greater shares in the generation mix. The
government aims to generate 20% of electricity from renewable energy sources by 2030. The share of natural
gas is expected to be 19%, while those of coal and nuclear energy will be 36% and 24%, respectively.

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REPUBLIC OF KOREAREFERENCES

EIA(Energy Information Administration)www.eia.gov/beta/international/rankings/.

(2017),

ProvedReservesof

Natural

Gas

2015,

EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database,http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
Government of Korea (2014a), ‘2nd Five-Year Plan
http://www.greengrowth.go.kr/download/140603-2full.pdf.

for

Green

Growth’,

June

2014,

––
(2014b),‘The
3rd
EnergyTechnology
Development
Plan’,
December2014,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=156861&bbs_cd_n=81&cu
rrentPage=2261&search_key_n=title_v&cate_n=&dept_v=&search_val_v=.
–– (2015), ‘Implementation Plan for New Energy-related businesses and Core Technology Development Strategy’, press release,
April
2015,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=157176&bbs_cd_n=81&cu
rrentPage=1941&search_key_n=title_v&cate_n=&dept_v=&search_val_v=.
–– (2016), ‘The 1st National Basic Plan Responding Climate Change’, press release, December 2016,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=158865&bbs_cd_n=81&cu
rrentPage=291&search_key_n=title_v&cate_n=&dept_v=&search_val_v=.
––(2017),‘EnergyTransition
Roadmap’,press
release,
October
2017,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=159746&bbs_cd_n=81&currentPage=311&search_key_n=title_v&cate_n=&dept_v=&search_val_v=.

KEEI (Korea Energy Economics Institute) (2002), An Analysis of Policy Issues in Natural Gas Industry Restructuring,
http://www.keei.re.kr/main.nsf/index_en.html?open&p=%2Fweb_keei%2Fen_publish.nsf%2F0%2F
d2caf2029a12d344c9256b5b0006859f&s=%3FOpenDocument%26Click%3D.
–– (2016), Yearbook of Energy Statistics, www.keei.re.kr/keei/download/YES2016.pdf.
MKE (Ministry of Knowledge Economy) (2009), ‘Korea Promises to Cut Carbon Emissions’, press release, 17
November2009,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=56268&bbs_cd_n=81&currentPage=41&search_key_n=title_v&cate_n=&dept_v=&search_val_v=
MOTIE (Ministry of Trade, Industry and Energy) (2014a), ‘The Second Energy Basic Plan’, press release, January2014,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=78654&bbs_cd_n=81&currentPage=3301&search_key_n=title_v&cate_n=&dept_v=&search_val_v=.
–– (2014b), ‘Facilitating New Energy-related Businesses as a Climate Change Response’, press release, July 2014,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=79165&bbs_cd_n=81&currentPage=2741&search_key_n=title_v&cate_n=&dept_v=&search_val_v=.
–– (2014c), ‘The Fourth New and Renewable Energy Basic Plan’, press release, September 2014,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=79320&bbs_cd_n=81.
–– (2015), ‘The Twelfth Plan for Long-Term Natural Gas Demand and Supply’, press release, December 2015,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=157895&bbs_cd_n=81&currentPage=1231&search_key_n=title_v&cate_n=&dept_v=&search_val_v=.
–– (2017), ‘The Eighth Electricity Demand and Supply Basic Plan’, press release, December 2017,
http://www.motie.go.kr/motie/ne/presse/press2/bbs/bbsView.do?bbs_seq_n=160040&bbs_cd_n=81&currentPage=61&search_key_n=title_v&cate_n=&dept_v=&search_val_v=
UN(UnitedNations)(2017),‘WorldStatistics
Pocketbook’,
http://unstats.un.org/unsd/publications/pocketbook/files/world-stats-pocketbook-2017.pdf.

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REPUBLIC OF KOREAUSEFUL LINKS

Korea Electric Power Corporation—www.kepco.co.kr/eng/
Korea Energy Economics Institute—www.keei.re.kr
Korea Energy Agency—www.energy.or.kr
Korea Gas Corporation—www.kogas.or.kr
Korea National Oil Corporation—www.knoc.co.kr
Ministry of Trade, Industry and Energy—http://english.motie.go.kr
Ministry of Strategy and Finance—http://english.mosf.go.kr
Statistics Korea—http://kostat.go.kr/portal/english/index.action
World Resources Institute (CAIT Climate Data Explorer)—http://cait.wri.org

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MALAYSIAM A L AY S I A
I N T ROD U C T I ON

Malaysia is located in Southeast Asia and lies entirely in the equatorial zone, with an average daily temperaturevarying between 21C and 32C. It has a total territory of approximately 330 323 square kilometres (km2),
covering 11 states and two federal territories in Peninsular Malaysia as well as two states and one federal territoryon the Borneo Island (EPU, 2017). In 2015, Malaysia’s population stood at 30.7 million, an increase of 1.6%
over the 2014 level of 30.2 million (EGEDA, 2017).
Malaysia’s gross domestic product (GDP) reached USD 752 billion (2010 USD purchasing power parity[PPP]) in 2015, an increase of 5% from USD 717 billion in 2014. The GDP increase contributed to a 3.3%
improvement in GDP per capita from USD 23 706 in 2014 to USD 24 483 (EGEDA, 2017). The largest
contributions to GDP were from services (54%), manufacturing (23%), agriculture (9.0%), mining andquarrying (9.1%) and construction (4.4%) (EPU, 2017). In 2015, the main export products were electrical andelectronic (E&E) products (approximately 36% of the total exports), chemicals and chemical products (7.1%),
petroleum products (7%) and LNG (6%) (MATRADE, 2016).
Compared with other large economies in the APEC, Malaysia’s energy resources can be considered to bemoderate in absolute terms. A 2016 data published by the Energy Commission (EC) of Malaysia showed that
the East Malaysian states hold nearly two-thirds of Malaysia’s energy reserves and that the rest are located in
Peninsular Malaysia. The economy’s oil reserves (including condensate) were 5.9 billion barrels, 37% of which
is found in Peninsular Malaysia (the Malay Basin). The natural gas reserves of the economy are estimated at
approximately 2.8 trillion cubic metres (tcm) or 100 trillion cubic feet (Tcf) in 2015. More than half of thereserves are found in the Sarawak Basin. The coal reserves, assessed at 1.9 billion tonnes, are located mostly in
Sarawak and Sabah (EC, 2017a).
Malaysia being an equatorial economy enjoys a high irradiance level throughout the year and is well suitedfor harnessing solar power. Although Malaysia has a huge potential to develop solar power, cloud cover that
constantly manifests itself in the region may hamper some of the effort to expand solar photovoltaic (PV)installation in the economy. According to the New and Renewable Energy Policy and Action Plan (NREPAP)
released in 2009, Malaysia’s reasonable target for grid-connected solar PV as building integrated PV (BIPV)
application is 850 MW by 2030 and may increase to more than 8,000 MW by 2050 (SEDA, 2011).
The economy also has vast potential for biomass as an energy source owing to the presence of palm oil
plantations and industries in the economy. As of 2016, Malaysia constituted 30% of the world’s palm oil
production and 37% of the world’s palm oil exports (MPOC, 2016). This production creates abundantagricultural residue, particularly empty fruit bunches. 1
Table 1: Key data and economic profile, 2014
Key dataa, bArea (km2)

Energy reservesc
330 323

Population (million)31

Oil (billion barrels)

5.9

Gas (trillion cubic metres)

2.8

GDP (2010 USD billion PPP)

752

Coal (million tonnes)

GDP (2010 USD PPP per capita)

24 483

Uranium (kilotonnes U)

1 938
–

Sources: a EPU (2017); b EGEDA (2017); c EC (2017a).

1 Palm oil production generates large amounts of residue, such as empty fruit bunches (EFBs) of palm. EFBs are a type ofwoody biomass with a calorific value of 4 400 kilocalories per dry kilogram (kcal/kg-dry); they are regarded as a safe andpromising biofuel resource because they have a very low chlorine content (Asia Biomass, 2009).

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MALAYSIAE N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Malaysia’s total primary energy supply was 80 104 kilotonnes of oil equivalent (ktoe) in 2015, an increase of
1.9% from the 2014 level of 78 626 ktoe. This increase is higher than 2013-14 level, which recorded only 0.8%.
Gas contributed the largest share at approximately 41% (32 993 ktoe), followed by oil with 35% share (27 788
ktoe) and coal with a 22% share (17 506 ktoe). Other resources include hydro, which in 2014 provided a minimal
share of 2.3% (1 816 ktoe) to the primary energy supply (EGEDA, 2017). Compared with the previous year,
the 2015 primary energy supply saw major changes in Malaysia’s energy mix, with natural gas overtaking oil as
the largest share of primary energy. Among the primary energy sources, consumption of gas, coal andrenewables increased by 15%, 13% and 12%, respectively, over the 2014–15 levels, while oil consumption
decreased by 15%.
In the past six years, growth rate for renewables has shown tremendous improvement, tripling from 606
ktoe in 2010 to 1 816 ktoe in 2015. This huge increase is partly due to the New and Renewable Energy Policy
and Action Plan introduced by the government in 2009, under which the Feed-in Tariff (FiT) for renewableenergy was introduced (Figure 1).
Figure 1: Primary energy growth index and total primary energy supply, 2010–15

Source: EGEDA (2017) and APERC analysis

Traditionally, Malaysia has been an energy exporter of mainly crude oil and natural gas (through pipelines
and in the form of LNG). The economy registered total energy exports2 of 46 035 ktoe in 2015, an increase of
11% from the 2014 level of 41 414 ktoe. Most of the growth in energy exports came from the sudden increaseof crude oil exports from 2 051 ktoe in 2014 to 7 696 ktoe in 2015, a level that was last seen in 2007. During
the same period, total energy imports decreased by 0.4% from 38 080 ktoe to 37 927 ktoe, which happened in
two consecutive years. Most of the decrease occurred in the petroleum product sector, which saw imports
decrease from 16 009 ktoe in 2014 to 14 218 ktoe in 2017 (EC, 2017a).
OIL

Malaysia’s oil reserves are the fourth-largest in the Asia-Pacific Region and are mostly in offshore fields.
Malaysia’s continental shelf is divided into three producing basins, namely, the offshore Malay Basin in
Peninsular Malaysia in the west and the Sarawak and Sabah basins in the east (EC, 2017a). The bulk of the oil
reserves are in the Malay Basin, which produces light and sweet crude oil (EIA, 2017). Malaysia’s average daily
oil production was 662 thousand barrels per day in 2015, approximately 85% of which were crude oil while therest were condensates. In 2014, Peninsular Malaysia yielded 40% of the total oil production, followed by Sabah(37%) and Sarawak (approximately 23%) (EC, 2017a).

2 Total energy exports/imports is equivalent to the sum of LNG and piped gas exports/imports, crude oil exports/imports,

petroleum products exports/imports and coal exports/imports.

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MALAYSIA

Malaysia has five oil refineries with a combined capacity of 566 thousand barrels per day (kbbl/d)(including condensate splitter capacity). Petroliam Nasional Berhad (PETRONAS), the state-owned nationaloil company, has three refinery facilities that provide more than 50% of the total daily refinery production.
Petrol and diesel constituted 78% of total domestic sales of petroleum products in 2014 (EC, 2017a).
The Malaysian Government, in the wake of the Economic Transformation Program, embarked on alarge-scale oil and gas project in Southern Peninsular Malaysia, known as the Pengerang Integrated Petroleum
Complex (PIPC). The PIPC is divided into two mega projects: the Pengerang Independent Deepwater
Petroleum Terminal (PIDPT) project undertaken by private companies and the Petrochemical Integrated
Development (RAPID) project with PETRONAS as the major developer. Owing to the size of the project,
Platts, an energy information provider that produced the free on board (FOB) Singapore oil benchmark pricefor the oil trade, will expand the price benchmarking scope to include oil storage terminals from Malaysia andrename it FOB Straits (Platts, 2015a).
About a quarter of Malaysian crude oil production currently originates from the Tapis field in the offshore
Malay Basin (EIA, 2017). Tapis crude, which is produced from this field, is very light and sweet. Crude oils thatare light (higher degrees of American Petroleum Institute [API] gravity or lower density) and sweet (low sulphur
content) are usually priced higher than heavy, sour crude oils. This is partly because petrol and diesel fuel, which
typically sell at a significant premium compared with residual fuel oil and other ‘bottom of the barrel products’,
can usually be more easily and cheaply produced using light, sweet crude oil (Figure 2) (EIA, 2012).
ExxonMobil, one of the world’s major oil companies, holds 30% of the equity in the Enhanced Oil Recovery(EOR) project at the Tapis field, while the rest of the equity belongs to PETRONAS. According to
ExxonMobil, Tapis Blend is a high quality, extra light, low sulphur crude. It has a high-quality clean productand conversion feed, with an API Gravity3 of 42.7 and sulphur level of 0.04% (ExxonMobil, 2018).
Figure 2: Density and sulphur content of selected crude oils

Source: EIA (2012)

3 American Petroleum Institute (API) gravity is a measure of the specific gravity of crude oil or condensate in degrees, anarbitrary scale expressing the gravity or density of liquid petroleum products. The measuring scale is calibrated in terms ofdegrees API (EIA, 2018).

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Based on UN Comtrade data, Malaysia’s crude oil was exported mainly to Asia-Pacific economies,
particularly Australia, India, China and Thailand (UN Comtrade, 2018). At the same time, Malaysia imported
slightly under half of its total crude oil in 2015 from the Middle East and North Africa (MENA)4 region.
Imports from the Americas region has been increasing since 2010, accounting for 22% of total imports in 2015,
an increase from 10% of total imports in 2010 (Figure 3).
Figure 3: Crude oil export and import, 2000–15

Source: UN Comtrade (2018)
NATURAL GAS

Most of the gas reserves of Malaysia are offshore in Peninsular Malaysia in the eastern areas of Sarawak and
Sabah. Most of the gas reserves are non-associated (86%), while the remaining reserves are associated with oilbasins (14%). Sarawak hosts slightly more than half the total reserves, followed by Peninsular Malaysia (32%)
and Sabah (15%). In 2015, the average daily natural gas production was 6 472 million standard cubic feet per
day (MMscf/D), a decrease of 1.8% from the 2014 level of 6 593 MMscf/D (EC, 2017a). Most of the
production (64%) came from Sarawak, followed by Peninsular Malaysia (30%) and Sabah (6%). Besides local
production, Malaysia also imports piped gas from the Malaysia–Thailand Joint Development Area (MTJDA),
from Indonesia (EC, 2013) and LNG imports from Qatar, Brunei Darussalam and Algeria.
Although Malaysia is one of the world’s largest LNG exporters, a geographical mismatch between where
the gas is produced (Sabah and Sarawak) and the regions of highest consumption (Peninsular Malaysia)
prompted Malaysia to build a LNG regasification terminal (RGT) to facilitate LNG imports. In 2015, Malaysia
imported approximately 1 873 ktoe of LNG, a decrease of 7.2% from 2 019 ktoe in 2014 (EC, 2017a) (Figure
4).
Malaysia has an extensive gas pipeline network running through Peninsular Malaysia, with pipelines
connected to offshore fields on the east coast of Peninsular Malaysia. The Peninsular Gas Utilisation (PGU)
network, which started in 1984, covers more than 2 500 km of pipelines composed of main pipelines, supply
pipelines and laterals, which link most cities in Peninsular Malaysia. The pipelines also have cross-borderinterconnections to Singapore and Songkhla, Thailand. The PGU network comprises six gas-processing plants
4 Based on the World Bank's definition, the MENA region covers Algeria, Bahrain, Djibouti, Egypt, Iran, Iraq, Israel,

Jordan, Kuwait, Lebanon, Libya, Malta, Morocco, Oman, Qatar, Saudi Arabia, Syria, Tunisia, United Arab Emirates, WestBank and Gaza, and Yemen.

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with a combined capacity of 56 million cubic metres per day (mcm/d) (2 000 MMscf), producing methane,
ethane, butane and condensate (Gas Malaysia, 2015).
Figure 4: Natural gas import into and exports from Malaysia, 1990–2015

Source: EC (2017a) and APERC analysis.
COAL

Malaysia’s coal resources mostly comprise bituminous and sub-bituminous coal. Estimated reserves areapproximately 1 938 million tonnes (Mt), which are found in Sabah and Sarawak. Nearly two-thirds of thesereserves have been categorised as inferred. Even with substantial coal resources, domestic coal production has
not been that aggressive because most of the coal deposits are far inland, which makes extraction costs high.
Likewise, some areas have been declared as protected, such as the Maliau Basin in Sabah, thereby prohibiting
coal-mining activities. Only Sarawak allows coal-mining activity, and the areas are Mukah (the largest coal basin)with 1.8 million metric tonnes of production in 2015, Kapit with 0.7 million metric tonnes and Sri Aman with
25 842 metric tonnes (EC, 2017a).
According to IEA Energy Statistics 2017, Malaysia was the eighth-largest coal importer in the world in2015, with coal consumption reaching 29 Mt (IEA, 2017). This reflects a rapid expansion of coal generation
capacity, especially during 2000–15 when coal consumption in the power sector increased from 1.5 million
tonnes of oil equivalent (Mtoe) to nearly 16 Mtoe. Coal generation capacity expanded to meet increasing
electricity consumption and reduce dependence on natural gas, which previously dominated generation with ashare as high as 70% in the 1990s (EC, 2017a).
ELECTRICITY

There are three major electricity grids in Malaysia. The national grid in Peninsular Malaysia and the Sabah gridare both regulated by the federal government; the Sarawak grid is under the jurisdiction of the state government.
The national grid is connected to Thailand’s grid to the north (with a power transfer capacity of 380 MW) andto Singapore’s main grid to the south (with a power transfer capacity of 450 MW) (ACE, 2015). The Sarawak
grid is connected to the Kalimantan grid in Indonesia. The power transfer reached 70 MW by May 2016 (TheStar, 2016).
Malaysia’s total licensed power generation capacity in 2014 was recorded at 32 005 MW, an increase of
6.2% from the 2014 level of 29 953 MW. This increase in installed capacity was attributed to the additional
capacity of 700 MW of the hydro project in Sarawak and an additional 1 000 MW of coal power plants in
Peninsular Malaysia. Approximately 60% of the total licensed capacity was owned by the independent power
producers (IPPs) and the rest by government-linked utilities, self-generation facilities and cogeneration facilities(EC, 2016).
In the same year, total electricity generation was 150 123 gigawatt-hours (GWh), an increase of 1.8%
from the 2014 level. Thermal generation, mostly from natural gas and coal, constituted 90% of total power
generation, while hydropower and other fuels accounted for the remainder (EGEDA, 2017).
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Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

94 219Industry sector

13 728Net imports and others–11 611

Transport sector

20 900

Thermal135 175

Total primary energy supply

80 104

Other sectors

8 448

Hydro

13 924Coal

17 506Non-energy

5 652

Nuclear-Oil

27 788

Final energy consumption*

43 076

Others

1 024

Gas

32 993

Coal

1 777

Renewables

1 816

Oil

25 106

1

Gas

4 823

OthersPower generation (GWh)

Renewables

Total power generation

150 123

0Electricity and others

11 369Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type, do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

In 2015, Malaysia’s total final consumption reached 48 727 ktoe, an increase of 0.5% from the 2014 level. This
marked the second consecutive year for total final energy consumption growth to be below 1%, where thegrowth in 2013–14 was 0.2%, although the economy grew at 6% in 2014 and 5% in 2015. The transport sector
was the largest energy consumer, constituting 43% of the total final consumption, equivalent to 20 900 ktoe. It
was followed by the industry sector with a 28% share or 13 728 ktoe, the non-energy sector with a 12% shareor 5 652 ktoe and other sectors (residential, commercial and agriculture sectors combined) with a share of 17%
or 8 448 ktoe (EGEDA, 2017).
In terms of fuel type, oil was still the most consumed fuel, particularly in the transport sector, constituting
52% of final energy consumption (excluding non-energy uses). This was followed by electricity with a 23%
share, gas with a 10% share and coal with a 4% share. Oil consumption decreased by 0.7% to 25 106 ktoe in2015 from 25 271 ktoe in 2014. However, natural gas and coal consumption increased by 3% and 4.1%,
respectively (EGEDA, 2017).
ENERGY INTENSITY ANALYSIS

Malaysia’s primary energy intensity decreased from 110 tonnes of oil equivalent per million USD (toe/million
USD) in 2014 to 106 toe/million USD in 2015, representing a 2.9% reduction. The reduction in 2015 marked
the fifth consecutive year of primary energy intensity reduction for Malaysia. Final consumption intensity also
decreased at the same rate of 4.3% from 68 toe/million USD in 2014 to 65 toe/million USD in 2015. Excluding
the non-energy sector, the final energy consumption intensity reduction would stand at 3.9% (EGEDA, 2017).
However, based on Malaysia’s National Energy Balance 2015, final energy consumption in 2015 reached 51
806 ktoe, a decrease of 0.8% from 2014 (52 210 ktoe) (EC, 2017a).
7

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Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

EnergyChange (%)

2014

2015

2014 vs 2015

Total primary energy supply

110

106

-2.9

Total final consumption

68

65

-4.3

Final energy consumption excl. non-energy

60

57

-3.9

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

Since the introduction of the New and Renewable Energy Policy and Action Plan, Malaysia’s consumption ofmodern renewables has been increasing every year. The share of modern renewables in final energy
consumption increased from 2.5% in 2014 to 2.6% in 2015. Based on year-on-year growth, modern renewables
registered a 5.7% increase in final consumption.
Table 4: Renewable energy share analysis, 2014 vs 2015
Change (%)

2014

2015

42 69743 076

0.9

41 62641 944

0.8

Traditional biomass

0

0

0

Modern renewables

1 071

1 132

5.7

Share of modern renewables to final energy
consumption (%)

2.5

2.6

4.8

Final energy consumption (ktoe)
Non-renewables (Fossils and others)

2014 vs 2015

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal and so on) including biogas and wood pellets are
considered modern renewables, although data on wood pellets are limited .
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKMalaysia’s National Energy Policy, which was first formulated in 1979, serves as the overall framework for thedevelopment of the energy sector. It consists of the following three principal objectives.


The supply objective: To ensure the provision of an adequate, secure and cost-effective supply of energy
through the development of indigenous energy resources and the diversification of energy supply fromdomestic and international sources.



The utilisation objective: To promote the efficient utilisation of energy and discourage wasteful and nonproductive patterns of energy consumption.

The environmental objective: To minimise the negative impacts of energy production, transportation,
conversion, utilisation and consumption on the environment (KeTTHA, 2015).

This policy has been instrumental in the development of Malaysia’s energy sector. Subsequent policies
have been designed to support these objectives and their implementation.
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In 1980, the National Depletion Policy was enacted to safeguard and preserve Malaysia’s energy resources,
particularly its oil and gas resources. Under this policy, the total annual production of crude oil should notexceed 3% of ‘oil initially in place’. As a result, production of crude oil was limited to 650 000 barrels per day.
The policy also limits the natural gas production to 2 000 MMscf/D in Peninsular Malaysia (UNPAN, 1999).
A year later, Malaysia introduced the Four-Fuel Diversification Policy to expand the fuel mix for power
generation. Initially, the focus of the policy was to reduce the economy’s dependence on oil as the dominantenergy source. The scope of this policy was further expanded in 2001 with the implementation of the Five-Fuel
Diversification Policy, which incorporated renewable energy (RE) (for example, biomass, solar and mini-hydro)
as the fifth fuel (KeTTHA, 2015).
In support of the Five-Fuel Diversification Policy, Malaysia launched the National Biofuel Policy in 2006
and introduced the NREPAP in 2010 as the policy framework to advance the development of indigenous RE
and expand its contribution to the power generation mix. The NREPAP provides long-term goals and a holistic
approach for the sustainable development of RE (SEDA, 2011). The RE power capacity is expected to increase
to 2 080 MW (11 GWh) by 2020 contributing 7.8% to the total power generation mix (EPU, 2015).
The National Green Technology Policy (NGTP) was launched in 2009 as an initial step towards
embracing sustainable development of the economy. The policy has four pillars, namely energy, environment,
economy and society. The NGTP has identified green technology as a key driver to accelerate the national
economy and promote sustainable development. Spearheaded by its Ministry of Energy, Green Technology
and Water (KeTTHA, 2017), Malaysia has introduced various programs and incentives to advocate the use ofgreen technology in key economic sectors. The NGTP aims to facilitate the growth of the green technology
industry and enhance its contribution to the national economy to increase national capability and capacity forinnovation and enhance Malaysia’s competitiveness in the global market. In addition, it aims to conserve theenvironment and ensure sustainable development for future generation (KeTTHA, 2017).
In May 2015, the government launched the Eleventh Malaysia Plan 2016–20 as the final stage in thejourney towards realising Vision 2020, a long-term development plan launched in 1991 that envisions Malaysia
as a fully developed economy across all dimensions by 2020. Six strategies are outlined in the Eleventh Malaysia
Plan. These include pursuing green growth for sustainability and resilience and strengthening the infrastructure
to support economic expansion, both of which have implications for energy initiatives (EPU, 2015). In thepast, the focus in economic growth was on quantity over quality. The Eleventh Malaysia Plan places greater
emphasis on quality growth, considering the economy’s natural resources and the impact of their use on theenvironment.
To pursue the green growth stated in the Eleventh Malaysia Plan, KeTTHA launched the GreenTechnology Master Plan (GTMP) in 2017 to earmark green growth as one of the six game changers that would
alter the trajectory of the economy’s growth. The GTMP creates a framework for facilitating the mainstreamingof green technology into the planned development of Malaysia while encompassing the four pillars set out in
the NGTP (KeTTHA, 2017).
ENERGY SECTOR STRUCTURE

The key ministries and government agencies for the Malaysian energy sector are as follows (APERC, 2014):
The Economic Planning Unit (EPU) sets the general direction and broad strategies for Malaysia’s energy
policies, such as formulating and implementing the national policy on energy and developing the oil andgas industry.



The Ministry of Energy, Green Technology and Water (KeTTHA) oversees programs and projects instrengthening energy resources to ensure electricity supply is of good quality, reliable and cost effective.
It also drives the development of RE and the promotion of energy efficiency, among others. Part of theministry’s role is also to assist the EPU in formulating the energy policy.



The EC is a statutory body established in 2001 to serve as a regulator for the electricity and piped gas
supply industries in Peninsular Malaysia and Sabah. The commission’s main functions are to establish
technical and performance regulations for the electricity and piped gas supply industries; act as the safety

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regulator; and protect consumers by ensuring high-quality services, regular supply of electricity and piped
gas and reasonable prices.
Besides the key agencies listed above, other authorities involved in energy development in Malaysia are as
follows:


The Ministry of Natural Resources and Environment that oversees the overall Malaysian environmental
targets as well as natural resources other than oil and gas;The Ministry of Plantation Industry and Commodity that oversees the biofuel development in Malaysia;
and

The Ministry of International Trade and Industry that promotes investment in Malaysia as well as helps
the government set gas prices for industrial use.

PETRONAS is Malaysia’s national petroleum corporation, wholly owned by the Malaysian Governmentand created under the Petroleum Development Act of 1974. PETRONAS is vested with exclusive rights forthe exploration and production of petroleum whether onshore or offshore in Malaysia. It also has the
responsibility for the planning, investment and regulation of the upstream sector. Any foreign or privatecompany wanting to explore and produce petroleum in Malaysia has to enter into a Production Sharing
Contract (PSC) with PETRONAS.
Malaysia’s power industry is dominated by three vertically integrated utilities, namely, Tenaga Nasional
Berhad (TNB) serving Peninsular Malaysia, Sabah Electricity Sendirian Berhad (SESB) in Sabah and Sarawak
Energy Berhad (SEB) in Sarawak. These utilities undertake electricity generation, transmission, distribution andsupply activities in their respective areas. Various IPPs, dedicated power producers and cogeneratorscomplement the three utilities.
ENERGY SECURITY

The Tenth Malaysia Plan, launched in 2010, outlines the strategic approaches designed to improve energy
supply security. The Eleventh Malaysia Plan, launched in 2016, outlines the strategic approaches designed to
improve energy supply security. Demand-side management (DSM), a major paradigm shift, which incorporates
energy efficiency and conservation measures, together with higher penetration targets of RE, will be
implemented to ensure the sustainable management of energy resources and improved energy security.
Another measure to improve energy security is to diversify LNG imports. The economy is faced with theissue of geographic disparity of natural gas supply and demand among its regions. Peninsular Malaysia requires
a greater natural gas supply for power and industrial use, while Sarawak and Sabah produce natural gas but lack
local demand. To address these concerns, LNG RGTs are being constructed to increase supply security throughimports of LNG from the global gas market. Malaysia completed its first RGT in Malacca, which commenced
operations in May 2013 with a total capacity of 260 000 cubic metres and an annual storage volume of 3.8 Mt(PETRONAS, 2012). The RGT will improve the security of natural gas supply in Peninsular Malaysia. A second
RGT was built at the southern part of Peninsular Malaysia as part of the PIPC and based on the latest update,the terminal received the first commercial LNG cargo on 1 November 2017 (LNG World News, 2017).
Regional energy cooperation under the Association of Southeast Asian Nations (ASEAN) framework
also addresses energy security. Among the agreements reached on energy security is the ASEAN Petroleum
Security Agreement (APSA) signed in 1986 and updated in 2009. Its purpose is to enhance petroleum security
in the ASEAN region. ASEAN members, through the Trans-ASEAN Gas Pipeline (TAGP) and the ASEAN
Power Grid (APG) projects have entered into interconnection cooperation agreements on power and naturalgas. The TAGP will provide the region with a secure supply of natural gas through the interconnection of gas
pipelines and associated infrastructure. The APG will integrate the power grids of ASEAN members to enableregional sales of electricity. The APG will also optimise the development of energy resources in the region.
GREEN TECHNOLOGY POLICY

In its pursuit of a low-carbon economy, the Malaysian Government launched the NGTP in July 2009. This
serves as the basis for all Malaysians to enjoy an improved quality of life by ensuring that the objectives of the156

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national development policies continue to be balanced with environmental considerations. The policy is built
on the following four pillars.
Energy - Seeking energy independence and promoting efficient utilisation;Environment - Conserving and minimising the impact on the environment;

Economy - Enhancing national economic development through the use of technology; andSociety - Improving the quality of life for all.

The following four sectors have been identified as the primary focus of the policy.
Energy - The application of green technology in power generation and in energy supply-side management,
including cogeneration by industrial and commercial sectors, in all energy-consuming sectors and in DSM
programs;

Buildings - The adoption of green technology in the construction, management, maintenance anddemolition of buildings;



Water and waste management - The use of green technology in the management and use of water
resources, wastewater treatment, solid waste and sanitary landfill; andTransport - The incorporation of green technology into the transportation infrastructure and vehicles,
related particularly to biofuels and public road transport (KeTTHA, 2011).

Among the policy’s long-term goals is the infusion of green technology and a significant reduction ofenergy consumption into Malaysian culture. Malaysia has joined the global endeavour by earmarking thepromotion of green technology through the establishment of the Ministry of Energy, Green Technology andWater in April 2009, which replaced the Ministry of Energy, Water and Communication. In addition, theMalaysian Energy Centre was restructured as the Malaysian Green Technology Corporation and has become
the lead agency of the ministry for the promotion, development and implementation of green technology.
The Green Technology Financing Scheme (GTFS) was established in 2010 to accelerate the expansionof the green technology industry with an allocated government fund of MYR 3.5 billion (USD 813 million)5
until 2017. The objective behind establishing the fund is to provide a special financing scheme for soft loans
to companies that produce and use green technology. As of 31 December 2017, 356 companies had received
the GTFS Certification, with financing amounting to MYR 3.64 billion (USD 845 million) (Green Tech
Malaysia, 2018).
The introduction of the MyHIJAU Labelling Programme is intended to ensure the availability of green
products and services in accordance with international standards and regulations. Currently, three agencies in
Malaysia have been recognised as providing environmentally friendly certification schemes. They are as follows:(i) SIRIM Eco Labelling by SIRIM Berhad for certifying the environmental attributes of green products
and services;(ii) Energy Efficiency Labelling by the EC for energy-efficiency labelling of electrical appliances; and(iii) Water-Efficient Products Labelling by the National Water Services Commission or SPAN.
The Green Building Index (GBI) has been developed as a rating tool to promote green technology in thebuilding sector. It also intends to raise awareness among developers and building owners about the design andconstruction of green and sustainable buildings. A GBI certificate is granted to developers and building owners
who have satisfied the standards in six areas: energy efficiency, indoor environmental quality, sustainable siteplanning and management, materials and resources, water efficiency and innovation.
To encourage the adoption of green building design, the government intends to establish itself as themarket leader. All new government buildings will have to adopt green features and designs, while existing
government buildings will be gradually retrofitted. Other initiatives that are being implemented are theGovernment Green Procurement (GGP) and Green Township projects. The GGP integrates environmental
5 The exchange rate is based on average daily conversion data from Bank Negara Malaysia in 2017 (BNM, 2018).

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considerations into the public sector procurement process to protect the natural environment, conserve
resources and lessen the harmful effects of human activities. By 2020, the GGP will be implemented in all
government offices and will ensure that 20% of the public sector’s purchases of products and services aregreen-labelled. The Green Township project advocates the adoption of a Low-Carbon Cities Framework &Assessment System (LCCF) by city councils, developers and town planners. The project provides a systematic
process and strategies for reducing carbon emissions in urban developments in accordance with thegovernment flagship and ongoing projects.
As mentioned above, Malaysia launched its GTMP to serve as a guide for the development of action plans,
programs and projects for the Eleventh and Twelfth plans. Under this master plan, six areas have been
identified as target areas: energy, manufacturing, transport, building, waste and water. Derived from NGTP,
the GTMP lists five major strategic thrusts to foster a ‘green culture’ in Malaysia.
Table 5: GTMP strategic thrust
Strategic
ThrustKey AreasPromotion andawarenessMarket enablers






Outcomes

Tailored communication strategy
Industry and business promotion via
International Greentech and Eco
Products Exhibition and otherplatforms.
Collaboration with primary andsecondary educational institutions



Government Green Procurement(GGP)
Green incentives
Innovative financing
Green cities
International collaborations










Human capitaldevelopment

Research anddevelopment andcommercialisation(R&D&C)
InstitutionalframeworkCapability building in the public sector
Capability building in the private sector
Collaboration with higher education
institutions



R&D&C funding
Public-private partnership







Governance (policy leadership)
Policy planning
Policy implementation








Improved awareness and receptivenesstowards green technology
Increase in business transactions,entrepreneurship and global value chain
integration
Improved knowledge of GT among theyounger generation to drive behaviouralchangeStrengthened industry readiness in the
production of green products and services
Improved financial feasibility of green
projects and affordability of green products
and services
Improved infrastructure readiness for green
adoption
Creation of export opportunities throughregional collaborations
Improved knowledge among government
officials
Increase in recognition of skills andcompetencies
Improved workforce readiness of fresh
graduates
Demand-driven, market and result-oriented
R&D&C projects
Stronger collaboration between government
bodies and research institutes in information
sharing to enable efficient strategic planningand resource deployment
Strengthened governance to facilitate crosssectoral cooperation among Government
bodies to improve the ease of doing business

Source: KeTTHA (2017)
ENERGY MARKETSMARKET REFORM

Malaysia’s energy market is a regulated one. Furthermore, the government provides subsidies to energy
consumers. However, Malaysia intends to implement energy market reforms, as suggested in the Eleventh
Malaysia Plan, through the gradual removal of energy subsidies. As a strategy to rationalise subsidies, the planstates that gas prices for power and non-power sectors will be revised every six months to gradually reflect

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market-based prices. The intention of this approach is to unbundle energy bills to itemise subsidy values. This
will eventually delink subsidies from energy use.
As part of the market reform initiative and to move towards better regulation, the EC subject utilities toan Incentive-Based Regulation (IBR) in 2013. The implementation of IBRs will continue to ensure that utility
companies provide efficient services. The IBR framework is designed to incentivise utility companies to reduce
costs and improve service levels. The separation of generation, transmission and distribution tariffs with
automatic adjustments will consider changes in fuel prices to increase the transparency and efficiency ofelectricity supply. New power plants and extensions of existing power plants will continue to be undertaken
through competitive bidding to ensure greater transparency. This will create healthy competition amongindustry players, resulting in more competitive tariffs, and in turn, benefit end consumers (EPU, 2015).
In addition to IBRs, the Eleventh Malaysia Plan states that the Gas Supply Act 1993 (Act 501), which
regulates the supply of gas to consumers through pipelines, will be amended to create a level playing field forthird-party gas players. Such players can then use the natural gas supply infrastructure, which is the PGU
pipeline and the RGT, at fair and transparent fees. The amended act will come into force in 2016 through theEC, which covers the economic regulation of the domestic natural gas market. This will include the RGT, thePGU pipeline and the distribution pipeline infrastructure. The aim is to unlock additional revenue from the gas
industry valued at an estimated MYR 2.9 billion (USD 684 million) per year (EPU, 2015).
As a further commitment to electricity market reform, the EC announced the launching of single buyer(SB) and grid system operator (GSO) websites. Previously, both SBs and GSOs were the same department
under the TNB (EC, 2017b).
Figure 5: Latest electricity market regulatory structure in Peninsular Malaysia

Source: APERC analysis

According to an announcement made by the EC, the establishment of SB and GSO was one of theinitiatives aimed at creating a more transparent electricity supply industry in Malaysia. The EC separated theoperations of SB and GSO from the other activities of the TNB through the enforcement of the Electricity
Supply Act (Amendment) 2015, which came into force on 1 January 2016. With the separation arrangement,
SB and GSO are now operating autonomously where their functions, operations and performance come under
the supervision and regulations of the EC.
SB is responsible for the management of electricity purchases from power generation plants, while GSO
is responsible for the day-to-day real-time operation and management of the Peninsular Malaysia grid system,
including interconnections with Thailand and Singapore.
ELECTRICITY AND GAS MARKETS

Malaysia’s electricity supply industry can be considered as an oligopoly. It is vertically integrated whereby eachutility company (TNB, SESB and SEB) undertakes the generation, transmission and distribution of electricity
in its respective region. However, IPPs provide nearly half the electricity generated to the utility companies. All
electricity utilities have a government stake as either a government-owned entity or a main shareholder. The
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industry is highly regulated and governed by several institutions (EPU, KeTTHA and EC), each of which has
specific functions and jurisdiction.
In view of the volatility of global energy prices and declining domestic gas production, Malaysia intends
to continue its efforts to ensure greater electricity supply and a sustainable electricity supply system as adopted
under the Eleventh Malaysia Plan. Further, this plan espouses the importance of enhancing the productivity
and efficiency of utility providers. The strategies that the plan has identified for a reliable and stable electricity
supply industry include increasing and diversifying generation capacity, strengthening the transmission anddistribution networks, restructuring the electricity supply industry and improving customer service delivery.
To lower the cost of energy subsidies and reduce market distortions, the Malaysian Government intends
to continue to institute market-based energy pricing. In December 2014, for example, the government
abolished petroleum product subsidies. Under the Eleventh Malaysia Plan, the government proposes to remove
the special industrial tariff (SIT) for the industrial sector. This tariff was introduced during the Asian financial
crisis in 1997–98 to help manufacturers stay competitive. Although launched as a temporary measure, the SIT
has remained in place. The SIT will be abolished in stages and fully removed by 2020. Its removal should
encourage industry to be more energy efficient in the future. Similar electricity subsidy rationalisation is also
expected to occur during 2016–20 (EPU, 2015).
The gradual reduction of the gas subsidy will eventually enable the adoption of a market price level forgas. This is expected to have a significant effect on the electricity supply industry. Currently, gas for power
generation supplied by the PGU pipeline system is heavily subsidised by the government. Other reforms will
also be implemented, such as the introduction of performance-based regulation, the renegotiation of powerpurchase agreements and separate accounting (unbundling) for generation, transmission and distribution
activities. To achieve these goals, the Malaysian Government plans to introduce IBR as an instrument toregulate the gas supply industry to make it more efficient and competitive.
In addition, access to the electricity supply in rural areas will be extended through grid expansion andalternative systems, such as mini hydro and solar hybrid. Under the Eleventh Malaysia Plan, the coverage ofelectricity supply, on a household basis, is targeted to be nearly 100% in Peninsular Malaysia and 99% in Sabah
and Sarawak by 2020 (EPU, 2015).
ENERGY EFFICIENCY

A lack of holistic and long-term policy for DSM has been identified as one of the main barriers in implementing
energy efficiency initiatives in Malaysia, even though it is considered to be an important element in Malaysia’senergy plan and policy. Energy efficiency initiatives are set to receive renewed attention under the Eleventh
Malaysia Plan through a reinvigoration of DSM. This is intended to be achieved by formulating acomprehensive DSM master plan. The EPU will initiate a study on DSM, which covers the whole spectrum of
the energy sector (EPU, 2015).
Table 6: Energy efficiency targets under the Eleventh Malaysia Plan
Item
Comprehensive longterm DSM master plan

Buildings

Industries

TargetFormulate policy and an action plan covering the entire spectrum of the energy sector
including electrical, thermal, and use in the transport sector
Achieve a target of 700 registered electrical energy managers (REEMs)
Extend EPC to other government buildings
Ensure all new government buildings adopt energy efficient designs
Retrofit 100 government buildings
Register 70 energy service companies (ESCOs)
Target 100 companies to implement ISO 500016
Introduce enhanced time of use (EToU) with three different time zones
Abolish the Special Industrial Tariff (SIT)
Install 4 million smart meters
Increase on-grid cogeneration capacity of 100 MW or more by reviewing utility standby
charges

6 ISO 50001 is a voluntary international standard to provide organisations with a recognised framework to manage andimprove their energy performance.

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APEC ENERGY OVERVIEW 2017

Households

MALAYSIA

Encourage additional appliances with minimum energy performance standards (MEPSs)
and extend existing labelling programme

Source: EPU (2015)
RENEWABLE ENERGY

Malaysia’s Five-Fuel Policy in 2001 recognised the importance of RE and adopted it as the fifth fuel in theenergy supply mix alongside natural gas, oil, hydro and coal. During the Tenth Malaysia Plan (2010–15), thefocus was on implementing greenhouse gas (GHG) mitigation measures. Among the measures taken were theintroduction of the RE Act in 2011 and the implementation of the Feed-in Tariff (FiT) mechanism. The
Sustainable Energy Development Authority (SEDA) Malaysia, a statutory body established by the government
to promote RE and energy demand management, set a target of 415.5 MW of additional RE capacity by 2015
(EPU, 2015). As of 1 February 2018, the total installed capacity of RE (excluding hydropower with capacity
above 30 MW and only covering Peninsular Malaysia and Sabah) in commercial operation was 532.3 MW, ofwhich biomass was 87.9 MW, biogas was 56.2 MW, small hydro was 30.3 MW and solar PV was 357.9 MW(SEDA, 2018).
The government has identified challenges that have affected the growth of RE in Malaysia. Among these
are issues that affect the reliability of RE plants and problems in securing adequate feedstock for long-term
supply, particularly for biomass. Other challenges are the lack of experts in the sector, including RE project
developers, financial personnel and service providers. There are also difficulties in securing financing to develop
RE installations. Current RE sources under the FiT portfolio focus on biomass, biogas, small hydro, geothermaland solar PV.
Under the Eleventh Malaysia Plan, the government has set a target for RE capacity to reach 2 080 MW,
thereby contributing 7.8% of the total installed capacity in Peninsular Malaysia and Sabah. Strategies have also
been identified to boost RE capacity. For example, studies are being conducted to identify new RE sources
such as wind, geothermal and ocean energy to diversify the power generation mix.
To complement the current FiT mechanism, a new instrument termed net energy metering (NEM) will
be implemented in the Eleventh Malaysia Plan. The objective of NEM is to promote and encourage more Solar
PV generation by prioritising internal consumption before any excess electricity generated is fed to the grid.
NEM is expected to encourage manufacturing facilities and the public to generate clean electricity. This willfurther assist the government’s effort to increase the contribution of RE in the generation mix. NEM isregulated by the EC and implemented by SEDA and started on 1 November 2016. The total quota allocatedfor the five-year period (2016–20) is 500 MW.
Solar PV under the FiT will no longer have new quota release post 2017. As a continuation of thegovernment’s effort to boost solar PV market in the economy, the EC has been tasked with implementing thelarge scale solar (LSS) program, which is based on a bidding process. The total quota allocated for the LSS from2017 to 2020 is 1 250 MWac 7. Of this, 250 MWac was granted direct award under the fast track program andthese projects will go into commercial operations in 2017. The remaining 1 000 MWac comes under the bidding
mechanism.
In August 2017, the EC announced the bid open price for LSS PV Plants for 2019/2020. The bid was
divided into three categories based on capacity: from 1 MW to 5.99 MW; 6.00 MW to 9.99 MW; and 10.00 MW
to 30.00 MW. The results showed that the lowest bid received was in the 10.00 MW to 30.00 MW category,with a tariff of MYR 0.3398/kWh (USD 0.079/kWh) (EC, 2017c).
CLIMATE CHANGE

Malaysia is a signatory to the United Nations Framework Convention on Climate Change (UNFCCC) andratified the treaty on 17 July 1994. Subsequently, the National Climate Committee was established in 1995. Thisis composed of various government agencies and stakeholders from business and civil society groups. Its
purpose is to guide national responses to climate change mitigation and adaption.

7 Unless specified, all PV capacities in this report are dc-rated.

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APEC ENERGY OVERVIEW 2017

MALAYSIA

At the 2015 United Nations Climate Change Conference in Paris, Malaysia’s prime minister made a pledge
to reduce the GHG emission intensity of the economy’s GDP by 45% by 2030 relative to the emission intensity
of GDP in 2005. The 45% figure comprises 35% on an unconditional basis and a further 10% conditional uponreceipt of climate finance, technology transfer and capacity building from developed countries (UNFCCC,2015). The sectors covered under this emission intensity reduction target are energy; industrial processes; waste;agriculture; and land use, land use change and forestry (LULUCF).
Two significant policies approved in 2009 support this goal: the NGTP and the National Climate Change
Policy (NCCP). These policies strengthen the national agenda on environmental protection and conservation.
The NCCP has three main objectives. First, to mainstream measures to address climate change through theefficient management of resources and enhanced environmental conservation, resulting in strengthened
economic competitiveness and improved quality of life. Second, to integrate responses into national policies,
plans and programs to strengthen resilience to the potential impact of climate change. Third, to strengthen
institutional and implementation capacity to harness opportunities to reduce the negative impact of climatechange more effectively (NRE, 2009).
The Eleventh Malaysia Plan also stressed the effort needed to address the challenges of climate change
by developing a roadmap for climate resilient growth, which covers adaptation and mitigation approaches. To
reduce the economy’s carbon footprint, development work will focus on creating green markets, increasing theshare of renewables in the energy mix, enhancing DSM, encouraging low-carbon mobility and managing waste
holistically (EPU, 2015).
N OTA B L E E N E RG Y D E V E L O P M E N T S
GREEN TECHNOLOGY MASTER PLAN LAUNCHED

Malaysia launched the GTMP in October 2017 after launching the Eighth International Greentech & Eco
Products Exhibition and Conference Malaysia (IGEM, 2017). The ministry will be seeking MYR5 billion fromfederal funding over the next five years to develop and implement this plan. The GTMP will help the sector
achieve a revenue of MYR80 billion and create more than 200 000 green jobs by 2030 (The Sun Daily, 2017).
PENGERANG INTEGRATED PETROLEUM COMPLEX

The PIPC is being developed as part of the Economic Transformation Program to establish a dynamic oil andgas downstream industry. The project is located on a single plot of land (approximately 8 100 hectares) in
Pengerang, Johor, at the south-eastern tip of Peninsular Malaysia. This is strategically accessible to majorinternational shipping lanes. To efficiently manage and administer the different projects within the PIPC, a newfederal government agency has been created—the Johor Petroleum Development Corporation (JPDC).
The PIPC will house oil refineries, naphtha crackers, petrochemical plants, and an LNG RGT. As ofJanuary 2013, two projects have been committed to the PIPC area. The first is the PIDPT, a Deepwater oil
terminal that is expected to be completed by 2020 with planned total storage capacity of 5 mcm Another projectis PETRONAS’s RAPID, which will include a 300 000 barrels per day crude oil refinery that will provide
feedstock for RAPID’s petrochemical complex and produce petrol and diesel that meet European
specifications (MPRC, 2013). The project is also aimed at meeting domestic demand for petroleum products
and the Malaysian Government’s future legislative requirements for the implementation of Euro 5
specifications (PETRONAS, 2016).
Despite the low oil price, the RAPID project is on track for Phase 2 of the site preparation. The refineryand cracker construction is progressing on schedule. The project will be completed by March 2019, andcommercial operations will begin immediately thereafter (Platts, 2015b).
Based on the latest update, the newly commissioned RGT at Pengerang received the first commercial
LNG cargo after successfully receiving three commissioning cargoes on 1 September, 23 September and 17
October (LNG World News, 2017). In other updates, PETRONAS celebrated its 10 000th cargo from its
Bintulu LNG Complex in Malaysia, delivered to Japan on 4 October (PETRONAS, 2017).

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MALAYSIA

MALAYSIA ENERGY STATISTICS MOBILE APPLICATIONAs a step towards a more transparent energy sector and realising the importance of energy data especially inpolicymaking, the EC, as the hub for energy data in Malaysia, has developed a mobile application on energy
statistics. Known as ‘MyEnergyStats’, the application, which is the first mobile application on energy statistics
in the ASEAN region, displays information on energy reserves, energy supply, energy transformation, energy
consumption, energy prices, energy indicators, electricity supply performance as well as gas distribution
statistics.
The application, which can be downloaded for free from the Apple Appstore and Google Playstore, wasdeveloped in 2016 and became fully operational in July 2017. Users can select their desired parameter, and theapplication will display the data in a tabular or graphical form (EC, 2017d).

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MALAYSIAREFERENCES

ACE (ASEAN Centre of Energy) (2015), ASEAN Plan of Action for Energy Cooperation (APAEC) 2016-2025,
http://www.aseanenergy.org/wp-content/uploads/2015/12/HighRes-APAEC-online-versionfinal.pdf.
APERC (Asia Pacific Energy Research Centre) (2014), Peer Review on Low Carbon Energy Policies (PRLCE) in
Malaysia, May 2014,
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BNM (Bank Negara Malaysia) (2018), Exchange Rates,
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artYr=2017&EndMth=12&EndYr=2017&sess_time=1200&pricetype=Mid&unit=rm.
EC (Energy Commission of Malaysia) (2013), National Energy Balance 2012,
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––(2016), Performance and Statistical Information on Electricity Supply Industry in Malaysia 2015,
http://www.st.gov.my/index.php/en/downloads/category/99-statisticselectricity?download=647:performance-and-statistical-information-on-electricity-supply-industry-inmalaysia-2015––(2017a), National Energy Balance 2015, http://www.st.gov.my/index.php/en/downloads/category/111national-energy-balance?download=658:national-energy-balance-2015.
––(2017b), Launching of Single Buyer and Grid System Operator Websites,
http://www.st.gov.my/images/article/speech/2017/Press_Release_121017.pdf.
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http://www.st.gov.my/index.php/en/highlight/item/769-large-scale-solar-lss-photovoltaic-plants-for2019-2020-bid-opening-price-large-scale-solar-lss-photovoltaic-plants-for-2019-2020-bid-opening-price.
––(2017d), Launch of Malaysia Energy Statistics Mobile Application,
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EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
EIA (US Energy Information Agency) (2012), Crude Oils Have Different Quality Characteristics,
https://www.eia.gov/todayinenergy/detail.php?id=7110.
–– (2017), Malaysia Overview, April 2017, https://www.eia.gov/beta/international/analysis.cfm?iso=MYS.
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EPU (Economic Planning Unit) (2015), Eleventh Malaysia Plan 2016–2020,
http://epu.gov.my/en/rmk/eleventh-malaysia-plan-2016-2020.
––(2017), Malaysian Economy in Figures 2017, http://www.epu.gov.my/sites/default/files/MEIF_2017.pdf.
ExxonMobil (2018), Tapis, http://corporate.exxonmobil.com/en/company/worldwide-operations/crudeoils/tapis.
Gas Malaysia (2015), website ‘Peninsular Gas Utilisation Project’ page,www.gasmalaysia.com/index.php/gas-fundamentals/peninsular-gas-utilisation-project.
Green Tech Malaysia (Green Technology Corporation) (2018), List of GTFS Certified Company (accessed on 2
February 2018), http://www.gtfs.my/certified
IEA (International Energy Agency) (2017), Key World Energy Statistics 2017,https://www.iea.org/publications/freepublications/publication/KeyWorld2017.pdf.
KeTTHA (Ministry of Energy, Green Technology and Water) (2011), National Green Technology Policy,
www.kettha.gov.my/portal/index.php?r=kandungan/index&menu1_id=3&menu2_id=75&menu3_id=92#.VEih1fmUeNg.

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APEC ENERGY OVERVIEW 2017

MALAYSIA––(2015), National Energy Policy 1979,
www.kettha.gov.my/portal/index.php?r=kandungan/index&menu1_id=2&menu2_id=26&menu3_id=110#.
––(2017), Green Technology Master Plan,
http://www.kettha.gov.my/portal/document/files/Green%20Technology%20Master%20Plan%20Mal
aysia%202017-2030.pdf.
LNG World News (2017), Malaysia’s Petronas Gets 1st Commercial Cargo at Its New Pengerang LNG Terminal,
https://www.lngworldnews.com/malaysias-petronas-gets-1st-commercial-cargo-at-its-new-pengeranglng-terminal/.
MATRADE (Malaysia External Trade Development Corporation) (2016), Top 10 Major Export Products, 2015,
http://www.matrade.gov.my/en/28-malaysian-exporters/trade-statistics/3447-top-10-major-exportproducts-2016.
MPOC (Malaysia Palm Oil Council) (2016), Malaysian Palm Oil Industry,
http://www.mpoc.org.my/Malaysian_Palm_Oil_Industry.aspx.
Nikkei (2017), Saudi Aramco pours $7bn into Malaysian petrochemical project,https://asia.nikkei.com/Business/Companies/Saudi-Aramco-pours-7bn-into-Malaysianpetrochemical-project.
NRE (Ministry of National Resources and Environment, Malaysia) (2009), National Policy on Climate Change,
www.nre.gov.my/ms-my/PustakaMedia/Penerbitan/Dasar%20Perubahan%20Iklim%20Negara.pdf.
PETRONAS (Petroliam Nasional Berhad) (2012), ‘Malaysia’s First LNG Re-Gasification Terminal Reaches
Completion’, press release, www.petronas.com.my/media-relations/mediareleases/Pages/article/MALAYSIA%E2%80%99S-FIRST-LNG-RE-GASIFICATION-TERMINALREACHES-COMPLETION.aspx.
––(2016) PM Visits PETRONAS Pengerang Integrated Complex, www.petronas.com.my/media-relations/mediareleases/Pages/article/PM-VISITS-PETRONAS-PENGERANG-INTEGRATED-COMPLEX.aspx––(2017) Petronas Calls for Collaboration Between LNG Producers and Consumers for Sustainable LNG Market,
http://www.petronas.com.my/media-relations/media-releases/Pages/article/PETRONAS-CALLSFOR-COLLABORATION-BETWEEN-LNG-PRODUCERS-ANDCONSUMERS-FORSUSTAINABLE-LNG-MARKET.aspx
Platts (2015a), Beyond FOB Singapore Towards FOB Straits,
www.platts.com/IM.Platts.Content/MethodologyReferences/MethodologySpecs/fob-singaporestraits-faq.pdf.
––(2015b), Malaysia's PETRONAS Says Committed to Capex Plans Despite Continuing Challenges,
www.platts.com/latest-news/natural-gas/singapore/malaysias-petronas-says-committed-to-capexplans-26275638.
SEDA (Sustainable Energy Development Authority) (2011), National Renewable Energy Policy and Action Plan,
http://seda.gov.my/gohome.php?omaneg=00010100000001010101000100001000000010100001000110&id=263.
–– (2018), FiT Dashboard – RE Capacity (data accessed on 2 February 2018), http://seda.gov.my/.
The Star (2016), Sarawak Exporting Electricity to West Kalimantan,
http://www.thestar.com.my/news/nation/2016/05/11/sarawak-exporting-power-to-westkalimantan/.
The Sun Daily (2017), Green Technology Roadmap to Create Over 200k Green Jobs by 2030,
http://www.thesundaily.my/news/2017/10/12/green-technology-roadmap-create-over-200k-greenjobs-2030.
UN Comtrade (2018), UN Comtrade Database (accessed on 2 February 2018), https://comtrade.un.org/data/.
UNFCCC (United Nations Framework Convention on Climate Change) (2015), Intended Nationally Determined
Contributions (Malaysia),165

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MALAYSIA

http://www4.unfccc.int/Submissions/INDC/Published%20Documents/Malaysia/1/INDC%20Malay
sia%20Final%2027%20November%202015%20Revised%20Final%20UNFCCC.pdf.
UNPAN (United Nations Public Administration Network) (1999), Sustainable Energy Policy and Strategies: A
Pre-Requisite for the Concerted Development and Promotion of the RE in Malaysia,
http://unpan1.un.org/intradoc/groups/public/documents/apcity/unpan003226.pdf.
U SEF UL LI N K S
Prime Minister’s Office—www.pmo.gov.my
Economic Planning Unit, Prime Minister’s Department—www.epu.gov.my
Energy Commission—www.st.gov.my
Green Technology Financing Scheme—www.gtfs.my
Grid System Operator—www.gso.org.my
Malaysia Green Technology Corporation—www.greentechmalaysia.my
Malaysian Palm Oil Board—www.mpob.gov.my
Ministry of Energy, Green Technology and Water—www.kettha.gov.my
Ministry of Finance—www.treasury.gov.my
Ministry of National Resources and Environment—www.nre.gov.my
PETRONAS—www.petronas.com.my
Sabah Electricity Sdn.Bhd.—www.sesb.com.my
Sarawak Energy Berhad—www.sarawakenergy.com.mySingle Buyer Department—www.singlebuyer.com.my
Sustainable Energy Development Authority—www.seda.gov.my
Tenaga Nasional Berhad—www.tnb.com.my

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MEXICOMEXICOI N TRO D U C T I O N

Mexico, officially known as the United Mexican States (Estados Unidos Mexicanos in Spanish), is a federal republicbordered by the United States to the north, Belize and Guatemala to the south, and the Atlantic and Pacific
Oceans on the east and west, respectively. For cultural and historic reasons, Mexico has been commonly
regarded as a Latin American economy, whereas its geographical location and economic integration are in
North America.
Mexico is rich in biodiversity, with abundant fossil and renewable energy resources over its land area ofapproximately 2 million square kilometres (km2). There are diverse climatic conditions across the Mexican
territory that range from very dry with high temperatures in the north to very humid with high temperaturesin the south and mild temperatures in the centre and warm coasts. The total population of Mexico is
125 million, the 10th most populated economy in the world. Mexico City is the capital and is one of the largest
urban centres in the world. Mexico City’s metropolitan area is home to more than 20 million people, with 9
million living in Mexico City proper and more than 11 million in the 60 surrounding municipalities in the statesof Mexico and Hidalgo (INEGI, 2013). After Mexico City, the other most important cities are Guadalajara andMonterrey, located in the west-central and north-eastern sides of the territory, respectively.
Several major reforms and free trade agreements introduced since the 1990s have resulted inmacroeconomic stability and increased flows of foreign direct investment and the creation of a robust
manufacturing industry, making it the 15th largest economy of the world with a similar size to that of Spain orAustralia. Despite these milestones, the growth of the Mexican economy between 2000 and 2015 has beenmodest, rising little more than 2.3% annually, with real gross domestic product (GDP) in 2014 reaching USD
1 994 billion (2010 USD purchasing power parity [PPP]) (EGEDA, 2017).
The accomplishment of significant political, economic and energy reforms was expected to underpin amore robust economy, but GDP only increased by 2.6% from 2014 to 2015. Despite this growth and theimplementation of social programmes to improve standards of living, the growth of Mexico’s GDP on a percapita basis has been small, with an annual rate of 0.7% from 2000 to 2015 (EGEDA, 2017). In addition, by
the end of 2016, around 44% of the Mexican population was deemed to be living under poverty conditions,with this share being roughly the same as in 2010 (CONEVAL, 2016).
Energy, particularly oil, is a significant component of the Mexican economy. In 2016, the value of crude
oil exports represented only about 5% of Mexico’s total exports, in contrast to around 11% in 2014. However,in that same year, crude oil revenue provided 36% of the government’s total revenue; that share decreased to
24% in 2016. (Banxico, 2018). This reduction is mainly explained by the low oil prices and a decrease in oil
production, highlighting the risks of relying on oil revenue. Moreover, Mexico has the lowest tax revenue rate
as a share of GDP among the Organisation for Economic Cooperation and Development (OECD) members(OECD, 2018).
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesc, dArea (million km2)

2

Population (million)

125

Oil (billion barrels)8

Gas (billion cubic metres)

200

GDP (2010 USD billion PPP)

1 994

Coal (billion tonnes)

1.2

GDP (2010 USD PPP per capita)

15 842

Uranium (kilotonnes U)

6.3

Sources: a World Bank (2018); b EGEDA (2017); c BP (2017); d NEA (2016).

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MEXICOE N E RG Y SU P P LY A ND C O N SU M P T I O NPRIMARY ENERGY SUPPLY

In 2015, the total primary energy supply in Mexico was 187 366 kilotonnes of oil equivalent (ktoe), a decreaseof 0.4% from 2014 as domestic oil production continues to wane since it peaked in 2004. Fossil fuels
constituted 90% of the primary energy supply of the economy, with other non-fossil sources, such as nuclear
and renewable energy, constituting the remaining 10% (EGEDA, 2017). With an economy endowed with
abundant fossil and renewable energy resources, Mexico’s oil reserves stood at 8 billion barrels of crude oil(eighteenth-largest in the world) by the end of 2015, whereas gas reserves were around 200 billion cubic meters(bcm) and coal stood at 1.2 billion tonnes of coal (BP, 2017).
Mexico is a major oil producer, producing around 1.9 million barrels per day (Mbbl/D) of crude oil in
2017, mostly the heavy type (SIE, 2018). This volume was almost 10% lower than that in 2016, mostly becauseof the decline in several major fields. Mexico faces the challenge of replacing the output from its once largest
oil asset Cantarell, a supergiant field, which, at its peak in 2004, produced 2.1 Mbbl/D, constituting more than
60% of the total crude oil production in Mexico. However, its productivity has been decreasing steadily sincethen. By 2017, Cantarell produced less than 0.2 million barrels, representing only 9% of the economy-wide
production (SIE, 2018).
Petróleos Mexicanos (PEMEX), the state-owned oil company, has focused its strategy on the discovery
and development of new oil fields that can offset the natural decline of its major assets. Mexico is a net crude
oil exporter with around half of its total indigenous crude oil production being exported, especially to theUnited States (SIE, 2018). Historically, Mexico has been one of the largest crude suppliers to the US, after
Canada and Saudi Arabia; however, Mexican crude exports have been decreasing sharply since 2011 (EIA,
2018).
Despite Mexico’s robust production of crude oil and a domestic distillation capacity of 16 Mbbl/D in six
refineries located across its territory, Mexico is a net importer of oil-based products, especially gasoline. With
the increase in internal consumption and decrease in production, net exports have decreased at an average rateof 4%/ year in the last decade (PEMEX, 2017).
Mexico’s significant proven natural gas reserves are under-exploited with production in 2016 reaching
only 37 bcm, of which more than three-quarters were associated with the production of crude oil (SENER,
2017g). This is enough to cover around half of Mexico’s growing gas consumption. As a net natural gas
importer, Mexico is looking to boost domestic gas resources, including the development of its unconventional
resources, such as shale gas. However, the challenges in early shale gas development and the ready availabilityof cost-competitive natural gas from the United States have favoured a rising volume of imports and have
prevented a more accelerated domestic gas production.
By the end of 2016, the contribution of domestic gas production to the natural gas supply in Mexico
amounted to 47%, much lower than the 2007 level of 81% (SENER, 2017g). Of the 53% of the natural gas
imported in 2016, approximately 13% was from Liquefied Natural Gas (LNG) and 87% was from pipeline
imports, all of the latter one coming from the United States. From 1999 to 2004, the US gas exports to Mexico
grew from 1.7 to 11 bcm. The US exports to Mexico remained stable until 2010, when Mexico’s gas production
peaked and started decreasing. With domestic production plummeting and with inexpensive and competitive
shale gas flowing from the US, imports to Mexico started growing almost exponentially, from around 11 bcm
in that year to 43 bcm in 2016, reaching a new historical record each year. With increasing import needs andreliance on the United States, Mexico built three regasification terminals: Altamira, on the Gulf Coast andEnsenada and Manzanillo in the Pacific Coast. LNG imports have averaged 6 bcm since 2012.
COAL

In comparison to most other economies in the APEC region, coal is not as widely used in the primary energy
supply of the economy representing less than 7% of the total supply in 2015, 13 654 (EGEDA, 2017). Mostof Mexico’s recoverable coal reserves of 1.2 billion tonnes are in the state of Coahuila in the north-eastern partof the territory, with some significant additional resources in the states of Chihuahua and Sonora in thenorthwest, and Oaxaca in the south.

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Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

191 785

Industry sector

35 352

Net imports and others−1 570Transport sector

51 096

Thermal

251 636

Total primary energy supply

187 366

Other sectors

28 035Hydro

30 815Coal

13 654Non-energy

5 321

Nuclear

11 577

Oil

90 632

Final energy consumption*

114 483

Others

17 110Gas

64 644

Coal

3 769

Renewables

15 467

Oil

67 985

Others

2 969

Gas

13 446

Renewables

7 142

Electricity and others

22 141

Total power generation

311 138

Source: EGEDA (2017) (data collected in September 2017).
*Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
ELECTRICITYElectricity generation in Mexico amounted to more than 311 terawatt-hours in 2015, mostly derived fromthermal power plants (EGEDA, 2017) largely fuelled by natural gas. In 2015, the total installed power capacity
was around 68 gigawatts (GW). This installed capacity represented an increase of almost 3 GW over theprevious year level. Natural gas is the dominant fuel in power generation with 46% of the total share, followedby oil with 18%, hydropower with 17%, coal with 8%, wind with 6%, nuclear energy with 2% and otherrenewables with 3%.
Figure 1: Mexico’s power generation capacity, 2016
1%

1%

2%

1%
Gas

6%

Oil
Coal

17%

46%

Hydro
Wind

8%

Geothermal
PV

18%

Nuclear
Bioenergy

Comisión Federal de Electricidad (CFE), Mexico’s state-owned and largest power utility, developed thebulk of the electricity generation infrastructure and currently owns 60% of Mexico’s capacity. (SENER, 2017c).
However, the number of private generators has grown fast over the last two decades since reforms in the
sector.

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Although CFE and private generators predominantly rely on combined cycle technologies fuelled by gas,
the use of renewable energy, particularly wind energy, has grown robustly, with additions of approximately 4
GW in the past 6 years. This growth is aligned with the government goals of electricity generation based onclean sources of 25% by 2018, 30% by 2021 and 35% by 2024.
Mexico’s electricity system comprises a main grid covering most of its territory, complemented with one
grid in the north and two in the south of the Baja California Peninsula. The interconnection between the three
Baja California Peninsula’s grids with the main grid is planned to be functional by 2022. It is expected tounderpin the optimisation of infrastructure and energy sources across the Mexican territory, and it could have
deeper effects on the entire system’s configuration in the long term. (SENER, 2017c)
FINAL ENERGY CONSUMPTION

In 2015, total final consumption in Mexico reached 119 804 ktoe, an increase of 0.9% from 2014, despite adecrease in energy consumption in the most energy-intensive transport sector. By end-use, the transport sector
was the largest consumer of energy (43%), followed by the industry sector (30%) and the residential,commercial and agriculture sectors combined (23%). The remaining 4% comes from feedstock for non-energy
purposes. By energy source, oil-based products accounted for 59% of final energy consumption (excluding
non-energy consumption); electricity and others for 19%; natural gas for 12%, renewables for 6.2% and coalfor 3.3% (EGEDA, 2017). This structure has remained with the same trend since 2010.
ENERGY INTENSITY ANALYSIS

In the last decades, Mexico has implemented initiatives to improve its energy efficiency, with a cumulative
positive effect on its energy intensity levels. As shown in Table 3, from 2014 to 2015, primary energy supply
intensity improved more than 3%. Following the same trend, total final energy consumption intensity
decreased by 1.7% compared to 2014, whereas it was only 0.7% when excluding non-energy consumption suchas petro-chemistry, plastics and others.
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

97

94

−3.0

Total final consumption

61

60

−1.7

Final energy consumption excl. non-energy

58

57

−0.7

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

Modern renewables consumption decreased by 7.9% from 2014 to 2015. The share of final energy
consumption decreased even further as consumption of non-renewables increased by 2.5%. Traditional
biomass, which decreased by 0.5% in 2015, has been in decline in Mexico; however, it retains a share of about
37% on the residential sector.

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Table 4: Renewable energy share analysis, 2014 vs 20152014
112 3812015
114 483

Change (%)
2014 vs 2015
1.9

101 414103 933

2.5

Traditional biomass*

6 068

6 038

−0.5

Modern renewables*

4 899

4 512

−7.9

Share of modern renewables to final energy
consumption (%)

4.4%

3.9%

−9.6%

Final energy consumption (ktoe)
Non-renewables (Fossils and others)

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial) using inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (e.g. hydropower and geothermal), including biogas and wood pellets,
are considered modern renewables, but data on wood pellets are limited.
P O L I C Y OV E RVI E W
ENERGY POLICY FRAMEWORK

Mexico’s energy policy is led by the Ministry of Energy (Secretaría de Energía, or SENER), which is required bylaw to develop an energy sector programme with the main energy goals and strategies to be enforced at the
beginning of every six-year presidential term. The current programme, in force until 2018, aims to remove
hurdles for ensuring a more vigorous energy supply and infrastructure development, foster regulatory
institutions and state-owned companies. The milestone reform passed in 2013 profoundly changed the sector
dynamics, introducing a new structure and institutional arrangement.
In the oil and gas industry, the Ministry of Finance determines the fiscal terms for oil and gas explorationand production contracts, whereas the National Hydrocarbons Commission (CNH) awards these contracts
and authorises the working plans originating from them. Regarding exploration and production activities,
SENER selects the areas to tender and designs the technical guidelines to observe. SENER is also responsible
for granting permits related to oil and natural gas processing.
The reform reaffirmed state ownership of all hydrocarbons in the subsoil while introducing morecompetition in the energy sector. These changes seek to foster investment in the sector by allowing privatecompanies to participate across the entire value chain of the oil, gas and power industries. Before the reform,
most of the value chain of these industries were monopolised by the two state-owned companies: Pemex in
the oil and gas sector and CFE in the power industry. With the new electricity industry framework, the private
sector can participate in electricity generation and marketing activities under state regulation, except for nuclear
energy. Concerning transmission and distribution, private parties may participate under contract with CFE.
As part of this transformation and with the participation of new players as well as with increasing
competition in the sector, regulators had their mandates expanded and capacities strengthened. Responsibilities
that used to be in the hands of the state-owned monopolies were transferred to regulatory bodies. The existing
CNH and the Energy Regulatory Commission (CRE) became coordinated regulatory organisations withtechnical and management autonomy and budgetary self-sufficiency. The CNH is responsible for regulation in
the oil and gas upstream industry and for conducting bids and administering contracts. The CRE is theregulator for hydrocarbons midstream and downstream operations and the whole electricity value chain.
Moreover, in addition to enhancing regulators, the reform created institutions such as Independent
System Operators and other agencies. The National Centre for Natural Gas Control (CENAGAS) was createdas the independent transmission gas pipelines operator. CENAGAS is also responsible for managing natural

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APEC ENERGY OVERVIEW 2017

MEXICOgas storage. Similarly, an independent electricity grid operator, the National Centre for Energy Control(CENACE), was created by withdrawing it from CFE; becoming responsible for operating the newly createdwholesale power market and for ensuring open and non-discriminatory access to the transmission anddistribution grids. In addition, the Agency of Security, Energy and Environment (ASEA) was created asattached to the Federal Ministry of Environment and is responsible for industrial safety and environmental
protection in the oil and gas industry. Finally, the Mexican Oil Fund for Stabilisation and Development, wasstablished under the management of the central bank and a board comprising the ministers of finance andenergy, the chairman of the central bank and four independent members nominated by the president andratified by the senate. This oil sovereign fund is in charge on holding all royalties and resource rents from theoil and gas upstream sector. The new institutional arrangement of Mexico’s public energy sector and its areasof influence are shown in a schematic representation in Figure 2.
Figure 2: Current institutional arrangement of Mexico’s public energy sector
Areas of Influence
Gas

Oil

NuclearElectricity

EnergyEfficiency

SENER

Legal Status
Sector Head

CNSNS

CRE*

CONUEE

Ministry’s
Decentralised
Entities
Regulatory
Bodies

CNH**
PEMEX

CENAGASIMP

State
Productive
Enterprises

CFE

Independent
MarketOperators

CENACE

INEEL

ININ

Research
Institutions

Source: APERC analysis.
* In the oil and gas industry, the regulations are applicable only to the midstream and downstream segments.
** In the oil and gas industry, the regulations are applicable only to the upstream segment.
Note: SENER: Ministry of Energy; CNSNS: National Commission for Nuclear Safety and Safeguards; CONUEE:
National Commission for the Efficient Use of Energy; CRE: Energy Regulatory Commission; CNH: National
Hydrocarbons Commission; PEMEX: Petróleos Mexicanos; CFE: Federal Electricity Commission (utility); CENACE:
National Centre for Energy Control; CENAGAS: National Centre for Natural Gas Control; IMP: Mexican Petroleum
Institute; ININ: National Institute for Nuclear Research; INEEL: National Institute for Electricity and Clean Energy.
OIL AND GASWith the reform enacted in Mexico, international and domestic companies other than Pemex are alreadyconducting hydrocarbon exploration and extraction activities. These contracts awarded by the CNH have been
the result of eight bidding processes conducted since July 2015. In fact, some of these companies haveestablished partnerships with Pemex for specific contracts and projects. The reform established four types of172

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MEXICO

contracts for hydrocarbons: services, profit sharing, production sharing and licenses. The last three allow thetransfer of the geological and financial risks involved in the exploration and extraction activities to contractors.
The state-owned oil and gas company, Pemex, was provided with a new tax regime and a corporate
management board. Pemex and CFE were re-labelled as ‘state productive enterprises’, a way to show that they
now aim for maximising productivity and value creation. In 2014, a ‘Round Zero’, whereby PEMEX requested
to retain certain strategic oil and gas assets prior to any public tenders for private competitors, handed over toPemex 83% of Mexico’s 2P reserves and 21% of prospective resources.
Apart from its role of hydrocarbon upstream regulator, the CNH is also responsible for the quantificationof Mexico’s oil and gas potential and geological records and for overseeing the technical issues related to
upstream permits. Conversely, the CRE is responsible for hydrocarbon regulation on midstream anddownstream, such as oil products transportation, distribution and commercialisation. Therefore, these
institutions oversee passing from a monopolistic oil and gas regime to a competitive, market-oriented oil andgas sector.
ELECTRICITY

Since 1992, the private sector has participated in electricity generation in Mexico owing to the industry’s partial
liberalisation, which allowed private companies to generate electricity. However, it had to be either sold to thestate-owned power utility, CFE, or used for their own purposes. The 2013 Energy Reform also meant a deeptransformation in the electricity sector, sometimes overshadowed by oil and gas industry changes.
The reform opened the generation segment to companies other than CFE and mandated its unbundlingalong the value chain. Private companies could participate in the supply segment for large consumers (morethan 1 MW). Supply to the rest of consumers, transmission and distribution and nuclear power generation
were maintained as a responsibility of CFE. However, private companies, in association with CFE, canparticipate on the expansion of the transmission and distribution grids.
The CRE’s duties span the electricity industry, including the generation, transmission, distribution, supply
and rates to final consumers. The newly independent CENACE, the power grid operator, operates thewholesale power market to ensure open and non-discriminatory access to the public transmission anddistribution grids. CENACE does not receive funding from the government but income from its operations.
Mexico also enacted the Energy Transition Law in 2015, which further opens the market to the private
sector to improve the sustainability of the electricity system through the increased use of clean energy. The law
establishes the goals for electricity clean generation: 25% by 2018, 35% by 2024 and 50% by 2050. In the law’s
definition of clean generation, apart from all non-fossil fuel generation, natural gas ‘efficient cogeneration’ isincluded.
The 2013 reform also created the clean energy certificates (CELs). These green certificates are granted tocompanies that produce power from designated clean energy technologies. SENER established requirements
to use a percentage of clean energy that all load-serving entities, including retailers and large consumers, must
fulfil. Non-compliers must procure required shares of clean energy certificates from CRE-certified clean energy
generators. Alternatively, they may buy them in the market that will be put in place in 2018 (IEA, 2016).
NUCLEAR ENERGY

Mexico’s experience in the development of nuclear energy for power generation is limited to only one plantwith two nuclear reactors (Laguna Verde), operated by CFE since 1990. Mexico has not explicitly published
any nuclear projects, but plans to expand its nuclear-installed capacity by 4 GW by 2030 (SENER, 2017c).
ENERGY EFFICIENCY

Mexico has had energy efficiency programmes since 1989. The institution in charge of promoting these
programmes and providing technical advice is the National Commission for Efficient Energy Use (CONUEE).
SENER and CONUEE drafted jointly the National Programme on the Sustainable Use of Energy 2014–18(PRONASE), which frames Mexico’s energy efficiency objectives and actions. The PRONASE 2014–18
includes the design of programmes for optimal energy use across sectors; regulations and standards forequipment and appliances made or marketed in Mexico; and a strengthened governance of energy efficiency

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APEC ENERGY OVERVIEW 2017

MEXICOsystems. Finally, SENER stablished Mexico’s energy intensity goals: 1.9% annual reduction from 2016 to 2030
and 3.7% annual rate from 2031 to 2050 (SENER, 2017f).
RENEWABLE ENERGY

Owing to its favourable geophysical conditions, Mexico has outstanding potential for renewable energy
development (SENER, 2017d). In 2008, laws, policies and regulatory instruments included for the first time
the promotion of renewable energy, biofuels and associated research activities. A maximum share of fossil
energy in Mexico’s total electricity generation was mandated at 65% by 2024, 60% by 2035 and 50% by 2050.
The 2015 Energy Transition Law overrode this law, but preserved the goals passed on December 2015.
Nevertheless, the goals were largely preserved, mandating the minimum share of economy-wide electricity
generation, based on clean energy (renewables, nuclear energy and others), and divided them into the following
sub-goals: 25% by 2018, 30% by 2021 and 35% by 2024.
SENER calculates Mexico’s renewable energy potential to be approximately about 1,380 GW in aconservative scenario, with more than 80% being solar or wind power. From 2006 to 2016, renewable power
generation capacity grew every year an average 4.3%, solar PV increased by 34% and wind by 110%. SENER
expects, from 2017 and 2031, renewable energies will grow at an annual average rate of 7.4%, reaching 41 GW
of installed capacity, of which wind is expected to lead with 17 GW by 2031 (SENER, 2017d).
ENVIRONMENTAL SUSTAINABILITY

Mexico’s Greenhouse gas (GHG) emissions represent 1.4% of the worldwide total (UNFCC, 2015). Mexico
issued its first specific strategy in 2000. It was the first developing economy to have a law dedicated exclusively
to this subject, issued in 2012. Mexico promotes actions that protect the environment through lower carbon
intensity in its domestic energy consumption and supply, as well as the reduction of polluting emissions fromthe electricity industry.
In agreement with the energy reform and its precepts to minimise the negative impact on theenvironment, SENER coordinated a cross-institutional effort towards the development of the Special
Programme for Climate Change 2014–18. According to the programme, the energy sector’s impact on climatechange is considerable, accounting for 61% of the established mitigation commitments. The programme
includes the goal of reducing a quarter of its power-generation emissions. The energy sector in Mexico is
responsible for reducing methane emissions by 11% and 37% of black carbon mitigation efforts.
Since 2015, the ASEA oversees and sanctions operators across the oil and gas value chain (upstream,
midstream and downstream) in their compliance to industrial and operational safety measures; plugging andabandonment of wells and facilities; and control of polluting emissions and waste.
RESEARCH AND DEVELOPMENTSENER, through its Vice-Ministry for Planning and Energy Transition, is responsible for fostering researchand development (R&D) policies. As explained in Figure 1, the Mexican Petroleum Institute (IMP) supports
the hydrocarbons sector; the National Institute for Electricity and Clean Energy (INEEL) supports researchand innovation on electricity and clean energies and the National Institute for Nuclear Research (ININ)
supports research and development on nuclear-based technology for power generation purposes.
Energy-related R&D in strategic areas has been enhanced by the creation of two trust funds, managed
jointly by SENER and the National Technology Council (Conacyt): the Trust Fund for Hydrocarbons and theTrust Fund for Energy Sustainability. These funds are financed by fee payments collected from PEMEX.
These funds have provided more than 5 000 scholarships for graduate studies in the energy sector.
In addition, the Centre for Training in Development Processes and the Centre for Deep Water
Technologies stem from the Trust Fund for Hydrocarbons. Likewise, the Trust Fund for Energy Sustainability
has provided about USD 160 million for the creation of five Mexican Centres for Energy Innovation,
specialising in bioenergy, wind energy, geothermal energy, wave energy and solar energy. Finally, the TrustFund for Energy Transition and Sustainable Use, financed through the federal budget, aims to promote theuse of renewable energy and energy efficiency.

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MEXICONO TA B L E E N E RG Y D E VE L O P M E N T S
OIL AND GAS

As previously noted, ‘Round Zero’ resulted in PEMEX retaining 83% of the proven and probable reserves in
Mexico and 21% of the prospective oil and gas resources.
During 2015 and 2016, a subsequent ‘Round One’ offered oil and gas resources in four consecutive
tenders, in which 38 contracts were awarded for exploration and extraction in deposits located in shallow anddeep waters of the Gulf of Mexico and onshore. In total, the awarded contracts represent an estimatedinvestment of USD 41 billion (CNH, 2018). For the first time, Pemex made an association for exploration andproduction in deep water via farm-out with BHP Billiton for the Trion Block.
‘Round Two’ consisted of additional four consecutive tenders. In June 2017, the 12 winning bidders of
the 10 contracts for exploration and extraction of hydrocarbons of the first tender were declared. Pemex wasamong the winning bidders. The assigned contracts have an associated investment of approximately USD 8.2
billion over the next 30–40 years. In July, 21 license contracts for the second and third tenders were awarded
with an investment of up to USD 2 050 million expected during the life of the contracts. Finally, in January
2018, 19 contracts to 18 different companies were awarded for exploration and production of deep-waterhydrocarbons in the fourth tender of ‘Round Two.’
In summary, the first two ‘Rounds’ have concluded with promising results for the Mexican oil and gas
industry. Out of the eight tenders concluded by CNH, 89 contracts for the exploration and extraction ofhydrocarbons were awarded to more than 70 companies from 21 countries. As of September 2017, Mexico’s
net revenue from these contracts was more than USD 145 million (CNH, 2018). Moreover, some companies
have already started production. Finally, the CNH already announced the first tender of ‘Round Three’ forshallow water scheduled for April, whereas the second tender, including for first-time unconventional
resources, was scheduled for July.
In 2017, the CRE granted more permits for importing oil products as a part of the market liberalisation
policy. For instance, in June 2017, private imports of diesel represented 7% of total imports of this product.
However, midstream and downstream infrastructure development remains a challenge because most of it isstill owned by Pemex. Consequently, Pemex still dominates the oil products market.
In September 2016, the CRE conducted the first open season for gas transport capacity in the gas
network operated by the CENAGAS. In June 2017, the CRE abolished the ‘first-hand fee’ (Venta de Primera
Mano or VPM) for natural gas. VPM was a price control on the first sale of natural gas that Pemex made to athird party for delivery in Mexican territory. The elimination of VPM allows suppliers other than PEMEX tooffer gas volumes on a free-market basis, while creating incentives to increase domestic production.
Similarly, the CRE also started the Contract Assignment Programme, an asymmetric regulation
instrument applicable to Pemex that seeks to facilitate the entry of new participants in the gas industry by
gradually offering 70% of its gas supply contracts to other companies.
From 2012 to 2017, 11 new gas pipelines and around 2 400 km have been added to the national gas
pipeline network, which is an increase of 21%. The expansion of the network has increased the number ofstated access to natural gas. Currently, nine pipelines are still under construction; however, at least six of them
face delays in their construction processes. It is estimated that by 2019 the total increase will be up to 7 444
km (SENER, 2017a).
Finally, SENER published the Second Review of the CENAGAS Five-Year Plan, in which it assessed
the challenges on optimising existing gas transport infrastructure through physical interconnections between
pipelines under construction and the CENAGAS managed gas pipeline network. This is particularly relevantin regards to the increasing gas imports coming from the United States, highlighting the following gas pipelines
under construction, which could alleviate these requirements if they are effectively connected to the
CENAGAS grid: (i) South of Texas–Tuxpan (ii) New Era and (iii) Ojinaga–El Encino (SENER, 2017e).

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MEXICOELECTRICITY

The electricity sector in Mexico continues under transformation from monopoly to competitive market. As
part of this changed, in March 2016, the vertical unbundling process of CFE, the state-owned electricity utility,
officially started. CFE was divided into 13 subsidiaries and affiliate companies: six generation subsidiarycompanies, CFE Transmisión, CFE Distribución, CFE Suministro Básico, CFE Generador de Intermediación,
CFE Calificados, CFEnergía and CFE Internacional. In 2017, all 13 CFE companies operated for the first time
fully independently from each other (SENER, 2017a).
Since January 2016, the Wholesale Electricity Market operated with the start of operations of the shortterm energy market. In February 2017, the balance of power market began its operations. In the Wholesale
Electricity Market, 48 different participants have signed contracts with the CENACE under different figures,
including 24 generators and 17 qualified suppliers. The opening of the electricity sector has meant that 83% of
the 48 Wholesale Electricity Market participants are companies other than CFE (SENER, 2017a).
In addition, since March 2016, three long-term auctions have been carried out to purchase energy,
capacity and clean energy certificates. Because of the first two auctions, more than 7.55 GW new clean
generation capacity will be added by around 35 companies carrying out an investment of USD 9 billion. Windand Solar PV are by far the preferred technologies, and more than 90% of the projects have adopted thesetechnologies. The degree of participation and competition allowed the prices obtained in both auctions to beamong the best in the world: USD 20.57 per megawatt-hour in the last auction held in November 2017
(CENACE, 2018).
Finally, as of June 2017, non-fossil fuel power generation capacity increased by almost 1 GW, around
6%, whereas clean power generation increased by 9% compared to the previous year’s levels. The biggest
growth was in wind capacity, which increased by 800 MW compared to that in the previous year (SENER.,
2017b).
ENERGY EFFICIENCY

Mexico saved more than 3 200 GWh of energy during the first half of 2017 owing to several efficiency
programmes, many of which had been implemented for a long time. Some of the programmes include norms
and standards in the energy end-use sectors (e.g. industrial, residential and commercial), savings on facilities
owned by the federal government, public lighting and daylight savings (SENER, 2017a).
In 2017, the revision and update of PRONASE 2014–2018 was published. CONUEE has developed 30
energy efficiency standards (NOMs) and a compliance evaluation system, which includes eight certification
bodies, 71 testing laboratories and 205 verification units. The National Programme for Energy Management
Systems (PRONASGEn), through the integration of five learning networks, is designed to strengthen
managerial and technical capacities to implement Energy Management Systems in large energy consumer’sfacilities such as factories, office buildings and governments’ headquarters (SENER, 2017a).
RENEWABLE ENERGY

As mentioned above, the Energy Transition Law, the operations of the Wholesale Market, the clean energy
certificates and the transformation of the electricity sector in Mexico has brought an impressive growth on
renewable energy in the past years. As of June 2017, renewable power generation capacity increased by almost
1 GW compared to that in 2016, representing around 6% of Mexico’s total generation capacity. The fastestgrowing renewable energy as a share of total generation capacity was solar PV with a 71% rate, whereas windincreased at 23%. (SENER, 2017b). As mentioned, the three long-term auctions will play a key role on
renewable energy growth with a further increase of 7 GW already underway.
In additionally, SENER granted 21 exploration permits for geothermal resources; 13 of them wereawarded to CFE in July 2015, and the remaining eight will be assigned to four private companies. It is expectedthat these permits will allow a 50% increase to the current installed capacity of geothermal energy in theeconomy (SENER, 2017a).

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MEXICOENVIRONMENTAL SUSTAINABILITY

SENER issued the requirements for acquiring clean energy certificates, which fundamentally mandate users
with an intensive use of electric power to prove that at least 5% of their consumption comes from clean energy
sources starting in 2018. In September 2016, Mexico ratified its Intended Nationally Determined Contribution(INDC), committing to an unconditional reduction of 22% of its GHG emissions by 2030 in comparison withits business-as-usual 2013 baseline. On a conditional basis, this share might increase to 40% if certain global
measures to address climate change are put into place (UNFCC, 2015). Non-fossil fuel power generation andenergy intensity goals mandated in the Energy Transition Law, if achieved, will impact positively on emission
reduction by phasing out fossil fuels.
An oil-to-gas switch is already underway in power generation. In 2002, oil-fuelled power generation led
the total share with 47%, whereas gas was only 25%. Conversely, in 2016, oil represented 16% of total power
generation, whereas gas grew to 54%. Moreover, SENER expects to completely phase-out oil-fuelled power
generation by 2025. Although natural gas still produces emissions, oil-fuelled power plants produce around
70% of the pollutant emissions (SENER, 2017c).
INTERNATIONAL COOPERATION

The most relevant international cooperation event in the Mexico’s energy sector was its accession as the 30th
member of the International Energy Agency (IEA), becoming its first member from Latin America. Mexico
expressed its initial willingness to join the organisation in November 2015. In the last IEA Ministerial Meeting,held in Paris in November 2017, ministers representing the IEA’s members unanimously endorsed Mexico’s
accession and recognised that Mexico had taken all necessary steps in record time. The Mexican Senate ratified
in December 2017 the accession agreement and Mexico became an official member on 17 February 2018.
SENER promoted bilateral strategic cooperation initiatives with several economies across diverse energy
topics. These economies were Canada, Cuba, the Dominican Republic, Guatemala, the United States andVenezuela in the Americas; Austria, Denmark, Finland, Germany, Italy, the Netherlands, Norway and theUnited Kingdom in Europe; China, India, Japan, Saudi Arabia and the United Araba Emirates in Asia.
On a multilateral level, Mexico participated in and led several dialogues, mainly through SENER. This
collaboration included several multilateral organisations such as the United Nations, the IEA, the International
Atomic Energy Agency (IAEA), the Nuclear Energy Agency (NEA), the International Renewable Energy
Agency (IRENA), the International Energy Forum (IEF), the Organisation of the Petroleum ExportingCountries (OPEC), the Latin-American Organisation (OLADE), the Clean Energy Ministerial, the G20 andAsia Pacific Economic Cooperation Forum (APEC) (SENER, 2017a).
.

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MEXICORE F E R E N C E S

Banxico (Banco de México) (2018), Estadísticas,
http://www.banxico.org.mx/SieInternet/consultarDirectorioInternetAction.do?sector=9&accion=consultarCuadro&idCuadro=CG8&locale=es.
BP (British Petroleum) (2017), Statistical Review of World Energy,
http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html.
CENACE (2018), Subastas de largo plazo,
http://www.cenace.gob.mx/paginas/publicas/MercadoOperacion/SubastasLP.aspx.
CNH (2018), Rondas Mexico, https://rondasmexico.gob.mx/?.
CONEVAL (Consejo Nacional de Evaluación de la Política de Desarrollo Social) (2016), Medición de laPobreza, https://www.coneval.org.mx/Medicion/MP/Paginas/Pobreza_2016.aspx.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
EIA (Energy Information Administration) (2018), U.S. Imports by Country of Origin,www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_ep00_im0_mbblpd_a.htm.
IEA (2016), Mexico Energy Outlook – World Energy Outlook 2016 Special Report.
https://www.iea.org/publications/freepublications/publication/mexico-energy-outlook.html
INEGI (Instituto Nacional de Estadística y Geografía) (2013), Cuaderno Estadístico y Geográfico de la Zona
Metropolitana del Valle de México,
www3.inegi.org.mx/sistemas/productos/default.aspx?c=265&s=inegi&upc=702825056117&pf=Prod&ef=&f=2&cl=0&tg=80&pg=0&ct=106020000/.
NEA (Nuclear Energy Agency) (2016), Uranium 2016: Resources, Production and Demand, https://www.oecdnea.org/ndd/pubs/2016/7301-uranium-2016.pdf.
OECD (Organisation for Economic Co-operation and Development) (2018), OECD.STAT,
https://stats.oecd.org/Index.aspx?DataSetCode=REV.
PEMEX (Petróleos Mexicanos) (2017), Informe Anual 2016www.pemex.com/acerca/informes_publicaciones/Documents/InformeAnual/Informe_Anual_2016.pdf.
SENER (Secretaría de Energía) (2017a), Quinto Informe de Labores 2016-2017,https://www.gob.mx/cms/uploads/attachment/file/255394/5_Informe_SENER.compressed2.pdf.
–– (2017b), Reporte de Avance de Energías Limpias Primer Semestre 2017,https://www.gob.mx/cms/uploads/attachment/file/279723/Informe_Renovables_2017_11122017.p
df.
–– (2017c), Prospectiva del Sector Eléctrico 2016-2031, https://www.gob.mx/sener/acciones-yprogramas/programa-de-desarrollo-del-sistema-electrico-nacional-33462.
–– (2017d), Prospectiva de Energías Renovables 2016-2031
https://www.gob.mx/cms/uploads/attachment/file/284342/Prospectiva_de_Energ_as_Renovables_
2017.pdf.
–– (2017e), Segunda Revisión Anual, Plan Quinquenal de Expansión del Sistema de Transporte y Almacenamiento
Nacional Integrado de Gas Natural 2015-2019, https://www.gob.mx/sener/articulos/segunda-revisionanual-del-plan-quinquenal-de-expansion-del-sistema-de-transporte-y-almacenamiento-nacionalintegrado-de-gas-natural-2015-2019?idiom=es.

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MEXICO–– (2017f), Estrategia de Transición para Promover el Uso de Tecnologías y Combustibles más Limpios,
https://www.gob.mx/cms/uploads/attachment/file/182202/20161110_1300h_Estrategia_CCTE1.pdf.
–– (2017g), Prospectiva de Gas Natural 2017-2031,
https://www.gob.mx/cms/uploads/attachment/file/302380/PGN_17_FF1.pdf.
SIE (Sistema de Información Energética) (2018), http://sie.energia.gob.mx.
World Bank (2018), Population Total, http://data.worldbank.org/indicator/SP.POP.TOTL.
http://www4.unfccc.int/ndcregistry/PublishedDocuments/Mexico%20First/MEXICO%20INDC%2003.3
0.2015.pdf

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MEXICOUSEFUL LINKS

Banco de México (Banxico)—www.banxico.org.mx
Centro Nacional de Control de Energía (CENACE)—www.cenace.gob.mx
Centro Nacional de Control del Gas Natural (CENAGAS)—www.cenagas.gob.mx
Comisión Federal de Electricidad (CFE)—www.cfe.gob.mx
Comisión Nacional para el Uso Eficiente de la Energía (CONUEE)—www.conuee.gob.mx
Comisión Nacional de Hidrocarburos (CNH)—www.cnh.gob.mx
Comisión Regulatoria de Energía (CRE)—www.cre.gob.mx
Comisión Nacional de Seguridad Nuclear y Salvaguardias (CNSS)—www.cnsns.gob.mx
Instituto Mexicano del Petróleo (IMP)—www.imp.mx
Instituto de Investigaciones Eléctricas (IIE)—www.iie.org.mx
Instituto Nacional de Investigaciones Nucleares—www.inin.gob.mx
Instituto Nacional de Estadística y Geografía (INEGI)—www.inegi.org.mx
Petróleos Mexicanos (PEMEX)—www.pemex.com
Presidencia de la República—www.gob.mx/presidencia
Rondas México— https://rondasmexico.gob.mx/
Secretaría de Energía (SENER)—www.gob.mx/sener
Secretaría de Hacienda y Crédito Público (SHCP)—www.gob.mx/hacienda
Secretaría del Medio Ambiente y Recursos Naturales (SEMARNAT)— https://www.gob.mx/semarnat
Sistema de Información Energética (SIE)—http://sie.energia.gob.mx

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NEW ZEALA NDNEW ZEALANDI N T ROD U C T I ON

New Zealand is an island economy in the South Pacific comprising two main islands, the North Island andSouth Island, and numerous outer islands. While its land area is between that of Japan and the United
Kingdom, its low population of about 4.6 million is comparable to that of a medium-sized Asian city. Dueto its remote location, New Zealand has no electricity or pipeline connections to other economies. The
economy has a mature economy with a per capita gross domestic product (GDP) of about USD 33 584(2010 USD purchasing power parity [PPP]) in 2015.
New Zealand is self-sufficient in all energy forms except oil. It has a vast renewable energy potential,
which in 2015 accounted for 80% of electricity generation, largely from hydro, but with increasing support
from geothermal and wind. Fossil energy proven and probable (2P) reserves are more modest, including
510 petajoules (PJ) of oil and liquefied petroleum gas (LPG), 50 billion cubic meters (bcm) of natural gas,
and the BP Statistical Review (2017) estimated coal reserves at 7.6 billion tonnes at the end of 2016 (BP,2017; MBIE, 2017a).
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesc, dArea (km2)

269 652

Oil (PJ)

510

Population (million)

4.6

Gas (billion cubic metres)

50

GDP (2010 USD billion PPP)

154

Coal (billion tonnes)

7.6

GDP (2010 USD PPP per capita)

33 584

Uranium (kilotonnes U)–

Sources: a World Bank (2017); b EGEDA (2017); c MBIE (2017); d BP (2017).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

In 2015, New Zealand’s total primary energy supply (TPES) was 20 589 kilotonnes of oil equivalent (ktoe),a 0.7% increase from the previous year. Renewable energy (geothermal, wind, solar and others) was the
major contributor to TPES (41%), followed by oil (33%), gas (20%) and coal (7%). The slow growth is theresult of the increase in oil and renewables (3.9% and 2.6%) being balanced by decreases in gas and coal
(6.9% and 2.1%). As geothermal electricity generation only has an efficiency of 13% in New Zealand (MBIE,
2016), the geothermal share of total final energy consumption is significantly smaller than TPES share. New
Zealand’s energy self-sufficiency (indigenous production/primary energy supply) in 2015 was 80%,
continuing a decreasing trend from the 2010 peak (91%) due to decreasing domestic oil and gas production
and increasing demand for transport fuels in recent years. Since 2000, growth in New Zealand’s TPES has
been modest, increasing at an average annual rate of 1.3% (EGEDA, 2017).
Coal is New Zealand’s most abundant fossil energy resource, predominantly available in the form of
low-value lignite. However, almost all coal production comprises sub-bituminous and bituminous coals. In
2015, coal production dropped by 17% after the 15% decrease in 2014 on an energy-equivalent basis
compared to 2013 as domestic producers struggle to compete with low coal prices (MBIE, 2017a).
Oil is sourced from 19 fields in the Taranaki region in the North Island (MBIE, 2016). The productionof crude oil, natural gas liquids and condensate increased by 3.8% on an energy-equivalent basis in 2015
compared to 2014 as the Maari field redevelopment increased production. However, the longer-term trend
is for a continuous decrease characteristic of the depleting fields, and will continue unless new fields are
discovered and brought on stream (MBIE, 2017). Oil production peaked in 2008, underpinned by thedevelopment of the newest fields Pohokura, Kupe, Tui and Maari, and from onshore fields such as Cheal
and Sidewinder (MBIE, 2015). Most of New Zealand’s oil is exported due to its high quality (it is ‘sweet’
and ‘light’). The vast majority of domestic oil demand is met by importing heavier crudes and refining it at181

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New Zealand’s only refinery at Marsden Point and importing refined oil products. Indigenous production
accounted for around 32% of the domestic oil consumption in 2015.
Natural gas is sourced from 17 fields currently in production, although 86% of production comesfrom just four (MBIE, 2016). In 2015, natural gas production decreased by 8%, compared to 2014, as
improved recovery techniques were applied to the ageing Maui gas field and a major expansion of theMangahewa field (MBIE, 2015). The largest uses for gas are industrial heat, electricity generation and inmethanol and urea production. All the gas produced in New Zealand is domestically consumed since there
are no liquefied natural gas terminals. In 2012, Methanex, which produces methanol with natural gas as
feedstock, signed a 10-year gas supply agreement with the Mangahewa field operator, ensuring that increases
in supply will have a secure buyer.
New Zealand has a large renewable energy potential primarily in the form of hydro, geothermal andwind energy. The use of this potential is largely for electricity generation, but geothermal heat is used directly
in industry and biomass is used in the residential and industrial sectors as a source of heat. The biomass
potential for advanced biofuel production is being examined as this technology advances. Finally, solar
energy photovoltaic and thermal applications are areas of future development as technology advances makethese technologies cheaper for deployment and more effective for grid integration.
In 2015, New Zealand generated 44 148 GWh of electricity, a 1.5% increase from 2014 (EGEDA,
2017). Hydro is the major source of electricity generation, accounting for 56% of total generation in 2015.
Geothermal generation accounted for 18% (EGEDA, 2017). More than two-thirds of New Zealand’shydroelectricity is generated in the South Island, while all the geothermal electricity is generated in the North
Island. While most hydro generation occurs in the South Island, the main sources of load are in the North
Island, requiring significant investment in the inter-island link.
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

16 503

Industry sector

4 341

Net imports and others

4 872

Transport sector

4 815

Thermal

8 748

Total primary energy supply

20 589Other sectors

3 511

Hydro

24 535

Coal

1 367

Non-energy

1 415

Nuclear

0

Oil

6 767

Final energy consumption*

12 666

Others10 865

Gas

4 088

Coal

607

Renewables

8 366

Oil

5 876

1

Gas

1 614

Renewables

1 204

Electricity and others

3 365

OthersPower generation (GWh)
Total power generation

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type, do not include non-energy uses. This isdifferent from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid
waste used in power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

In 2015, New Zealand’s total final consumption was 14 082 ktoe, a 0.8% reduction from 2014. This decreaseis due to a reduction in gas demand (both for energy and non-energy uses) from the methanol manufacturingindustry due to an increased number of shutdowns during 2015 (MBIE, 2016). This reduction in theindustry sector, however, masks a significant increase in the transport sector (4.1%) and a modest increase
from other sectors (1.1%) (including residential, commercial and agricultural). The largest consumption
sector was transport with 34% of total demand, while the industry sector decreased to 31% and the othersector remained stable at 25%; the remaining 10% was used for non-energy purposes. Oil was the largest
component of final energy consumption with 5 876 ktoe (46%), followed by electricity and others at 3
365 ktoe (27%), gas at 1 614 ktoe (13%) and coal at 607 ktoe (5%) (EGEDA, 2017).
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Industry energy demand has been dominated by a few large consumers, including one aluminium
smelting plant, one steel mill, one oil refinery, two methanol plants, one cement plant, several pulp and paper
mills and a very large dairy company with several plants. Each of these consumers has a unique consumption
profile. In 2015, the aluminium smelter used 13% of all New Zealand electricity and the petrochemical
sector consumed 28% of natural gas supply as a feedstock (MBIE, 2016). The pulp and paper industry
meets up to half of its energy needs from wood and wood waste.
Transport energy consumption increased by 4% in 2015. This is a significant development following
several years of a relatively flat trend. Transport energy consumption is dominated by the light passenger
vehicle fleet with significant contributions from heavy freight transport and air transport, while rail andwater transport have small shares of consumption.
The transport sector is the main consumer of petroleum products, accounting for 82% of domestic
oil consumption in 2015. Consumption of oil products in the other sectors was shared among the residential,commercial and agricultural sectors (11%) and the industrial sector (7%). Besides transport, the residential
sector’s main oil use is LPG for home heating purposes, while the commercial and agricultural sectors use
diesel for machinery, backup electricity generators and motors.
ENERGY INTENSITY ANALYSISNew Zealand’s energy intensity of primary energy in 2015 was 133 tonnes of oil equivalent per million
USD (toe/million USD), a decrease of 1.7% from 136 toe/million USD in 2014. This is largely due to the
reduction in gas for non-energy use discussed earlier and offsets the intensity growth posed by the increasein the transport sector. Similarly, the final energy consumption intensity decreased by 3.1% to 91 toe/million
USD.
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

136

133

-1.7

Total final consumption

94

91

-3.1

Final energy consumption excl. non-energy

83

82

-1.6

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSISNew Zealand has been making extensive use of its renewable energy sources for many years, largely throughthe generation of renewable electricity from hydro. This means that the total share of renewable energy canvary depending on the climate, especially rainfall. In 2015, the total share of renewable energy increased to29.6%, an increase of 1.6% over the 2014 share (29.1%). This is largely due to an increase in renewableelectricity generation and all other modern renewables of 2.4% in 2015 from 2014.
Table 4: Renewable energy share analysis, 2014 vs 2015

12 566

12 666

Change (%)
2014 vs 2015
0.8

8 751

8 764

0.1

Traditional biomass*

153

153

0.0

Modern renewables*

3 662

3 749

2.4

Share of modern renewables to final energy
consumption (%)

29

30

1.6

2014
Final energy consumption (ktoe)
Non-renewables (Fossils and others)

2015

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,

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including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal and so on.) including biogas and wood pellets are
considered modern renewables, although data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKThe Ministry of Business, Innovation and Employment (MBIE) was established in July 2012 through themerger of four government ministries: the Ministry of Science and Innovation, the Ministry of Economic
Development (formerly responsible for energy policy), the Department of Labour and the Department of
Building and Housing. The merger was part of a broader effort to simplify government departments,
enhance performance and reduce government spending. MBIE is responsible for developing New Zealand’s
energy policies and strategies with assistance from several agencies, and reports to the Minister of Energy
and Resources.
New Zealand’s oil and gas exploration and production activities are privately owned and open tocompetition. In April 2018, the Government announced that there would be no new offshore oil and gas
exploration permits issued, but that the 31 oil and gas exploration permits that are currently active (22 ofwhich are offshore) would be honoured. Oil and gas development shows a mixed international ownership,including New Zealand companies, major international oil companies and Japanese industrial/energy
concerns.
Electricity generation and retailing are also open to competition and there are over 30 retail brands
that consumers can buy electricity from. While five large retailers still have the majority of market share,small and medium-sized retailers are gaining market share. Three of the five large generator-retail companies
have some state-ownership, which were fully state-owned prior to the government privatising 49% of themin 2013 and 2014 to stimulate private investment in the sector.
Transpower, a state-owned enterprise, is the transmission grid owner and operator. Distribution is
managed by 29 regulated natural monopolies that are each in charge of a specific region. The New ZealandElectricity Authority oversees the management of the electricity market through the development,
administration and enforcement of the Electricity Industry Participation Code, which covers all aspects ofthe electricity market (EA, 2018). The authority however does not regulate electricity prices.
The New Zealand coal industry was dominated by Solid Energy, a State-owned Enterprise (SOE).
However, the company failed due low coal prices and was put into receivership in 2015 and its assets soldto pay creditors. The assets were sold to private sector interests, effectively ending the direct involvement ofgovernment in the industry (Otago Daily Times, 2017).
The New Zealand Energy Efficiency and Conservation Strategy 2017–22 (NZEECS) was released in2017, and is a companion to the New Zealand Energy Strategy (NZES) 2011–21: Developing Our Energy
Potential (the Energy Strategy) (MBIE, 2012). The NZEECS, titled “Unlocking our energy productivity
and renewable potential” has the goal of New Zealand having an energy productive and low emissions
economy. It sets the overarching policy direction for government support and intervention and guides thework programme of the Energy Efficiency and Conservation Authority (EECA).
The NZEECS identifies three priority areas: renewable and efficient use of process heat, efficient andlow-emissions transport, and innovative and efficient use of electricity.
In October 2017, following the surprising general election result, a new government came into powerwith more ambitious climate change policies, such as setting a target of net zero carbon emissions by 2050,
establishing an independent Climate Commission to recommend targets and actions and strengthening theemissions trading scheme. This will have some impact on energy markets policy.
ENERGY MARKETSNew Zealand’s energy sector has been subject to major reforms since the mid-1980s, coinciding with theintroduction of broader economic reforms. The broader reforms are aimed at improving economic growththrough improved economic efficiency, driven by clear price signals, and where possible, competitive markets.
The greatest change occurred in the electricity and gas markets, where the vertically integrated utilities wereseparated into natural monopoly and competitive elements; the formerly government-owned and operated

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electricity and gas monopolies were either corporatized or privatised and the electricity market wasderegulated.
In April 2009, responding to concerns about rising electricity prices, especially for residential
customers and governance arrangements in the electricity sector, the government initiated a Ministerial
Review. The review made several recommendations that were included in the Electricity Industry Act 2010
(MED, 2009) and resulted in important changes in the market. A key change resulting from this Act was
replacing the Electricity Commission with the Electricity Authority, which has more independence fromgovernment and streamlines its activities to focus on developing a healthy competitive market.
Responsibilities of the Electricity Commission that overlapped with those of other agencies weretransferred to these agencies, for example, the promotion of electricity-related energy efficiency, approvalof grid upgrades and management of supply emergencies.
The Electricity Industry Act 2010 includes several stipulations for promoting competition. These
include provisions for swapping assets between the three state-owned electricity-generating companies toimprove competition in both wholesale and retail markets, and to make improvements in security of supply,
a fund to encourage customers to switch electricity providers and better electricity market hedging
arrangements. The Act also has provisions to improve the security of supply. These include rule changes toensure that electricity retailers do not make profit from supply emergencies, and the requirement that a stateowned reserve power station, criticised for distorting market incentives, be privatised so that it can be
operated on a commercial basis (NZG, 2010a). This plant was sold to Contact Energy in 2011.
Since 2004, New Zealand’s gas sector has been co-regulated by the government and the Gas Industry
Company, an industry body established under the Gas Act 1992. The Gas Industry Company pursues thegovernment’s objectives and outcomes, as outlined in the Gas Act 1992 and the Government Policy
Statement on Gas Governance. Its work is driven by ministerial requests and its own engagement with thegas sector (MED, 2014).
FISCAL REGIME AND INVESTMENTIn New Zealand, the ownership of all petroleum resources, including natural gas, rests with the Crown,
regardless of the ownership of the land. However, some coal resources are privately owned (Rob Harris,
2004). The New Zealand Petroleum & Minerals (NZP&M) business unit within the MBIE manages thegovernment’s oil, gas, mineral and coal resources, known as the Crown Mineral Estate.
NZP&M was formed in May 2011 to maximise the gains to New Zealand from the development of
its oil, gas, coal and mineral resources, consistent with the government’s objectives for energy and economic
growth. Its role is to efficiently allocate rights to prospect, explore and mine Crown-owned minerals. It isalso responsible for effectively managing and regulating these rights and ensuring a fair financial return to
the Crown for its minerals. NZP&M is instrumental in promoting investments in the mineral estate. It
replaces the former Crown Minerals Group. The Resource Markets Policy team of the Energy and Resource
Markets Branch of MBIE advises the New Zealand Government on policy and operational regulation in
the mineral estate.
Corporations earning income in New Zealand were previously taxed at a flat rate of 30% (Inland
Revenue, 2012). The tax rate has dropped to 28%, effective 1 April 2011 (Inland Revenue, 2012).
Corporations are also required to pay other indirect taxes such as payroll and fringe benefit taxes.
For petroleum production, companies must pay an ad valorem royalty of 5% (5% of the net revenues
obtained from the sale of petroleum) or an accounting profit royalty of 20% (20% of the accounting profitof petroleum production), whichever is greater in any given year. For discoveries made between 30 June
2004 and 31 December 2009, an ad valorem royalty of 1% is applied to natural gas, or an accounting profits
royalty of 15% on the first NZD 750 million for offshore projects, or 15% on the first ANZD 250 million
for onshore projects (NZP&M, 2014).
For the production of Crown-owned coal, the royalty payable depends on when the initial permit wasawarded. For initial permits awarded between 1991 and 2008, an ad valorem royalty of 1% of the net sales
revenue is payable between NZD 100 000 and NZD one million. For producers with net sales exceeding
NZD one million, the royalty payable is either 1% of the net sales revenue or 5% of the accounting profits,
whichever is higher (NZP&M, 2014). For initial permits awarded between 1 February 2008 and 23 May 2014,a unit-based royalty of NZD 1.4 per tonne is payable for hard and semi-hard coking coal, NZD 0.8 per
tonne for thermal and semi-soft coking coal and NZD 0.3 per tonne for lignite. For initial permits awarded
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since 24 May 2014, an ad valorem royalty of 2% of the net sales revenue or 10% of the accounting profits
is payable, whichever is higher.
New Zealand has good oil and gas resource potential but the economy is considered underexplored(Ralph Samuelson, 2008). Responding to this challenge, the government has developed an action plan forrealising the potential of New Zealand’s petroleum resources. The Action Plan for the Development ofPetroleum Resources, released in November 2009 and updated periodically, aims to ensure that New Zealandis considered an attractive destination for investment in petroleum exploration and production. The plan
has several work streams, including


Reviewing the fiscal and royalty framework to ensure that the government receives a fair returnfrom petroleum resources while providing sufficient incentives for investors;

Investing in data acquisition to improve resource knowledge and foster more investment,
particularly in frontier resources andDeveloping a fit-for-purpose legislative framework for the petroleum sector (MBIE, 2012; NZG,
2010b).

In August 2011, the government announced a new approach for allocating petroleum exploration rights.
Previously, New Zealand primarily used a ‘first-in, first-served’ priority-in-time allocation scheme. Under the
new scheme, the government will announce ‘block offers’ for specific acreage and invite competitive bids todevelop them. The goal of this change is to attract significant additional investment to New Zealand whileproviding the government with more control over where, when and to whom exploration rights are granted(NZP&M, 2014).
New Zealand’s environmental permitting process, known as ‘resource consent’, is governed by the
Resource Management Act 1991 (RMA) and its subsequent amendments. A resource consent is required forany project that might affect the environment, which includes essentially all energy development projects.
Resource consents are generally obtained from regional, district or city councils, depending on the natureof the resources affected. RMA specifies that the guiding principle of decision-making is sustainable
management (MFE, 2015).
In December 2008, in response to concerns about the slow and costly consenting process under RMA,
the government reviewed the RMA process to address some of the major criticisms. One of the main
criticisms was that decision-making was with the local governments, where local interests can takeprecedence over economy-wide interests or where insufficient expertise and resources are available,
especially for major, complex projects. The RMA amendment in 2009 addressed this criticism by establishing
an Environmental Protection Authority (EPA) to receive resource consent applications for proposals ofnational significance and to support the boards of inquiry (or the Environment Court) in making decisions
regarding these proposals (MFE, 2015).
The Resource Management (Simplification and Streamlining) Amendment Act 2009 also includes
provisions to streamline the consenting process. These specifications make it more difficult for competitors
to challenge a resource consent application, impose stricter deadlines for decisions by local governments
and make procedural changes.
In 2017, the Phase 2 Review of RMA was completed. This phase of RMA has taken over 5 years tocomplete as it was looking comprehensively at its relations with other legislations related to environmental
management, such as the Conservation Act (1987) and the Exclusive Economic Zone Act (2012). The key
change is the refocusing of the decision-making at local government level to follow the established ‘national
direction’ handed down by central government in National Policy Statements when considering RMA
applications. Other changes include streamlining the RMA relation with other legislation, as mentioned
above; improvements to procedural requirements and streamlining legal processes around the Act (2017a).
ENERGY EFFICIENCYNew Zealand has promoted energy efficiency for over 20 years, and in 2000, it passed the Energy Efficiency
and Conservation Act 2000, which led to the economy’s first energy efficiency strategy and the establishmentof the Energy Efficiency and Conservation Authority (EECA) to spearhead the strategy’s implementation(EECA, 2012a).

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In August 2017, the government released the latest New Zealand Energy Efficiency and Conservation
Strategy 2017–22 (NZEECS) to replace the 2011 document. The overall goal of the new strategy is for New
Zealand to continue to increase energy productivity and reduce carbon emissions, in accordance with New
Zealand’s international commitments such as the Paris Agreements, and the APEC intensity target.
NZEECS also makes strong mentions of renewable energy and the productivity value it can generate. The
strategy focuses on three key areas, each having a specific target:
1.

Area 1: Renewable and efficient use of process heat. Target 1: Decrease industrial emission
intensity of at least 1% per year on average between 2017 and 2022.

2.

Area 2: Efficient and low carbon transport. Target 2: Electric vehicles make up 2% of thevehicle fleet by the end of 2021.

3.

Area 3: Innovative and efficient use of electricity. Target 3: 90% of the electricity will comefrom renewable sources by 2025 (MBIE, 2017b).

Some of New Zealand’s major policies for promoting energy efficiency are as follows:

In May 2016, an electric vehicle support program was announced, which involved road user tax
exemptions, government/private bulk purchasing programs and information campaigns. Of
specific interest is a contestable fund to match private funding for projects aimed at increasing EV
deployment in New Zealand (MT, 2017). More information can be found in the governmentsponsored website electricvehicles.govt.nz.



There is also fuel economy labelling for light vehicles.



There is no blanket policy for businesses; rather, an individual approach is prevalent to support
innovative and replicable projects that demonstrate efficiency opportunities, support energy
auditing in larger business and promote awareness of energy efficiency in business by recognisingenergy efficiency excellence through a highly publicised awards event.



In relation to residential buildings, a subsidy program called Warm Up New Zealand has delivered
insulation retrofits for more than 300,000 homes since 2009. As per the Labour Party’s election
manifesto, the Government intends to introduce a new grant scheme for subsidised insulation andheating retrofits. In addition the Government has made amendments to the Residential Tenancies
Act 1986 to include a requirement for rental properties to meet a minimum standard of insulation
by July 2019.



In commercial buildings in 2014, a rating tool for the buildings’ energy and water efficiency waslaunched to promote efficiency.

For appliances and equipment, New Zealand has in place an extensive Minimum Energy
Performance Standards (MEPS) and labelling program. This initiative is coordinated with Australia
to have a robust mechanism for both economies (EECA, 2017).
RENEWABLE ENERGYNew Zealand is well endowed with hydro, geothermal, wind, biomass and potentially ocean energy, so muchso that all current wind and geothermal capacity was developed without subsidies. Although the state-owned
electricity generating companies have played a major role in developing these resources, they are required tooperate as commercial businesses and must compete with private generators (The Treasury, 2011). As partof the Energy Strategy, the New Zealand Government set a target of generating 90% of its electricity fromrenewable sources by 2025, provided that a security of supply is maintained. The New Zealand Governmentis also in the process of setting up the independent Climate Change Commission, whose work will include
how we transition towards 100 per cent renewable electricity by 2035. One of the existing instruments that
help ongoing development of renewable energy in New Zealand is the Emissions Trading Scheme, discussed
in the ‘Climate Change’ section (MBIE, 2012).
Hydro power has historically been New Zealand’s major source of renewable energy. However, themajority of favourable hydro sites have already been developed, and there is a strong social opposition tofurther hydro development; thus, New Zealand has been focusing on geothermal and wind energy. Several
major renewable generation capacity projects have been consented by government in recent years but havenot been developed due to lower than expected electricity demand growth. In effect, the next 20 years of
the new demand have already been approved and will be mostly wind and geothermal electricity.
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Biomass has also been long used in New Zealand for residential heating and for industrial process heatin the wood product and pulp and paper manufacturing industries. However, this is largely the productive
use of a waste product from the primary industrial activity. Due to lower energy density and cumbersome
gathering process, its use has remained limited. In recent years, EECA has been promoting the conversionof medium-scale industrial or commercial boilers to biomass through the use of denser, and relatively
inexpensive, wood pellets. To promote biofuels, the government is now supporting research, development
and demonstration for advanced biofuel projects (i.e. from woody biomass).
Another tool employed by the government was the issuing of a National Policy Statement for Renewable
Electricity Generation in April 2011. This policy statement requires decision makers at all levels ofgovernment, especially the local level, to recognise the economy-wide significance and make provisions forrenewable electricity generation in their plans and policy statements (MFE, 2011).
The government has also considered electric and plug-in hybrid electric light vehicles (EVs and PHEVs)
as an option to increase renewables in transport, not just as a form of demand but also as a source ofelectricity storage from intermittent renewable electricity generation, enabling further integration of windand solar to the electricity grid.
NUCLEAR ENERGYNew Zealand law prohibits the development and use of nuclear energy and there are no plans to revisit thisstance in the foreseeable future.
CLIMATE CHANGE

The New Zealand Government is committed to taking action on climate change. It has announcedplans to introduce a new Zero Carbon Bill later in 2018 which will seek to set a new emissions reduction
target by 2050 and establish an independent Climate Change Commission. In the meantime, an Interim
Climate Change Committee will be set up early in 2018 to progress key issues for climate change policy New
Zealand, such as agriculture and renewable electricity. The Climate Change Commission will further advise
the Government on these matters once the Bill passes into law.
The Government has stated that its goal is for New Zealand to be a net zero emissions economy by2050. Under the Paris Agreement, New Zealand has an existing target to reduce greenhouse gas emissions
by 11 percent below 1990 levels by 2030.
The key climate change intervention is the Climate Change Response (Emissions Trading)Amendment Act of 2008, which established New Zealand’s emissions trading scheme (ETS). The ETS
places a price on greenhouse gas emissions to provide an incentive to reduce emissions. The scheme camein effect in 2008 and was amended in 2009, 2012, and 2016.
For energy, the point of obligation under the scheme generally lies with energy suppliers, not with theend users. This means that only energy suppliers and a few large industrial facilities are directly involved in
the scheme. The government is providing free units to energy-intensive trade-exposed industries to protect
them from international competition that does not face a carbon cost (FL, 2012).
The Government has signalled that it will strengthen the ETS by including all sectors, removing (orreducing) grandfathering and removing the two-for-one deal. This expected result is higher carbon prices
advantaging renewable energy deployment and promoting energy efficiency (especially in industry andtransport) and electric transportation.
The Government is progressing with work to strengthen and improve the operation of the ETS witha focus on (MFE, 2017b):


how best to implement the in-principle decisions made by the Government in July 2017 (such as
introducing auctioning and developing a different price ceiling), and

a package of forestry accounting and operational improvements, any future phase-out of freeallocation and other operational and technical matters.

188

APEC ENERGY OVERVIEW 2017

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N OTA B L E E N E RG Y D E V E L O P M E N T S
ELECTRICITY MARKETIn 2014, the New Zealand Government completed the partial privatisation of the three large state-owned
energy utilities by selling 49% of each company. This raised NZD 4.7 billion, lower than expected bygovernment. The funds raised from this were promised to be reinvested in education and infrastructure but
so far this promised has yet to be realized (RadioNZ, 2015)
The electricity sector is grappling with uncertainty on both the demand side from large industrial
electric consumers and supply side through the possible closure of Huntly power station (the only coalplant) and the recent unexpected closure of gas generation. New Zealand’s second-largest electricity
consumer, a paper mill, reduced the output by half and there are concerns about the profitability of the
Tiwai Point Aluminium Smelter (TPAS), which accounted for 12% of New Zealand’s total electricity
demand in 2014 (MBIE, 2015). The New Zealand Government supplied a short-term NZD 30 million oneoff subsidy to ensure that the plant continues to operate for the next few years (NZAS, 2013). However, its
long-term future is uncertain as is the capacity at which TPAS will be able to operate over the medium term.
On the supply side, the 2015 closure of nearly 600 MW of natural gas generation due to a stagnant
market and the slated retirement of 500 MW of coal generation by 2018 are putting pressure on the gridand market operators to ensure security of supply during dry climate periods when hydro generation will be
constrained (NBR, 2015). These closures are partly covered by the completion of the Te Mihi geothermal
plant of 166 MW and the Mill Creek wind farm of 60 MW, which were both completed in 2014.
Another development includes the deployment of smart metering devices throughout the market. By
the end of 2015, over 70% of all households had smart meters installed (EA, 2016). The key driver resides
in operational savings for electricity retailers in terms of not having to employ meter readers and control ofcertain processes remotely. The Smart Grid Forum formed in 2014, however, believes that there is potential
to expand benefits into streamlining the market, energy efficiency technology adoption and greater adoptionof renewables, etc. (MBIE, 2014).
NEW PROJECTS

Since the 2014 project mentioned above, no new generation projects have undergone construction. There
are, however, several large-scale wind, geothermal and hydro projects that have regulatory and environmental
consent to proceed, but utility companies have stated that they are unlikely to develop any new large-scale
project for the next several years owing to the current market’s oversupply of capacity and tepid electricity
demand growth. With continued improvement in the energy intensity demand, growth may be much slower
in the medium to long term than seen historically.
In the past few years, the New Zealand grid system operator Transpower completed several essential
major upgrade projects to maintain grid security and keep up with the demand. These include the
NZD 417 million North Auckland and Northland Grid Upgrade Project (completed in 2013); the North
Island grid upgrade project (completed in 2012); the NZD 100–300 million Wairakei to Whakamaru
Replacement Transmission Line Project, completed in 2013, and the NZD 672 million high voltage direct
current (HVDC) Inter-island Link Project, completed in 2014 (Transpower, 2015). Other grid maintenanceand upgrade projects worth around NZD 400 million are currently underway. Transpower is also managing
a demand response project aiming to develop a market within the New Zealand electricity system.
In April 2018, the Government announced that there would be no new offshore oil and gas exploration
permits issued, but that the 31 oil and gas exploration permits that are currently active (22 of which are
offshore) would be honoured. The government will continue to offer blocks for onshore exploration in the
Taranaki region and the industry is spending around NZD 300 million in multiple sites to explore further
resources. However, at present, no significant funds are being developed for production.
In transport, Z Energy is in the process of commissioning New Zealand’s largest biofuel plant with aproduction capacity of 20 million Litres per year.

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APEC ENERGY OVERVIEW 2017

NEW ZEALA NDREFERENCES

BP (2017), Statistical Review of World Energy 2017,https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review2017/bp-statistical-review-of-world-energy-2017-full-report.pdf
CCINZ (Climate Change Information New Zealand) (2012), Emissions Trading Scheme Basics,
www.climatechange.govt.nz/emissions-trading-scheme/basics.html/.
EA (Electricity Authority) (2016), Electricity Market Information website ʻRetail Dashboardsʼ page,https://www.ea.govt.nz/consumers/what-are-electricity-meters/ .
–– (2018) What does the Electricity Authority do? https://www.ea.govt.nz/consumers/what-does-theelectricity-authority-do/.
EECA (Energy Efficiency and Conservation Authority) (2012a), Legislation, www.eeca.govt.nz/abouteeca/eecas-role/legislation/.
–– (2012b), Biodiesel Grants Scheme, www.eeca.govt.nz/biodiesel-grants/.
–– (2017), Energy labels, https://www.energywise.govt.nz/energy-labels/.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
FL (Frazer Lindstrom) (2012), New Zealand Emissions Trading Scheme (NZETS),
www.frazerlindstrom.com/nzets.htm.
Inland Revenue (2012), Business Income Tax, www.ird.govt.nz/business-income-tax/imputation/.
MBIE (Ministry of Business Innovation and Employment) (2012), New Zealand Energy Strategy 2011–2021:
Developing Our Energy Potential, www.med.govt.nz/sectors-industries/energy/pdf-docs-library/energystrategies/nz-energy-strategy-lr.pdf/view/.
–– (2013), Energy in New Zealand 2013, www.med.govt.nz/sectors-industries/energy/energymodelling/publications/energy-in-new-zealand/Energy-in-New-Zealand-2013-print.pdf/.
–– (2014), New Zealand Smart Grid Forum—Terms of Reference, www.med.govt.nz/sectorsindustries/energy/electricity/new-zealand-smart-grid-forum/meeting-1/final-tor-scopedefinition.pdf/at_download/file.
–– (2015), Energy in New Zealand 2015, http://www.mbie.govt.nz/info-services/sectorsindustries/energy/energy-data-modelling/publications/energy-in-new-zealand/previouseditions/Energy%20-in-New-Zealand-2015.pdf/view–– (2016), Energy in New Zealand 2016, http://www.mbie.govt.nz/info-services/sectorsindustries/energy/energy-data-modelling/publications/energy-in-new-zealand/.
–– (2017a), Energy in New Zealand 2017, http://www.mbie.govt.nz/info-services/sectorsindustries/energy/energy-data-modelling/publications/energy-in-new-zealand/documentsimages/energy-in-nz-2017.pdf.
–– (2017b), Unlocking our energy productivity and renewable potential: New Zealand Energy Efficiency and Conservation
Strategy 2017 – 2022, http://www.mbie.govt.nz/info-services/sectors-industries/energy/documentsimage-library/NZEECS-2017-2022.pdf.
MED (Ministry of Economic Development) (2009), Improving Electricity Market Performance Discussion
Document, http://www.mbie.govt.nz/info-services/sectors-industries/energy/previous-reviewsconsultations/review-of-the-electricity-market-2009/documents-imagelibrary/Improving%20Electricity%20Market%20Performance%20-%20Volume%20One.pdf.
–– (2014), Gas Governance, http://www.mbie.govt.nz/info-services/sectors-industries/energy/gasmarket/regulations-governance-gas-market.
MFE (Ministry for the Environment) (2011), National Policy Statement for Renewable Electricity Generation 2011,www.mfe.govt.nz/publications/rma/nps-renewable-electricity-generation-2011.
–– (2015), An everyday guide: Getting in on the Act, http://www.mfe.govt.nz/node/16380

190

APEC ENERGY OVERVIEW 2017

NEW ZEALA ND–– (2017a), About the Resource Legislation Amendment Act 2017, http://www.mfe.govt.nz/rma/reforms-andamendments/about-resource-legislation-amendment-act-2017–– (2017b), In-principle decisions: further information. http://www.mfe.govt.nz/climate-change/reducinggreenhouse-gas-emissions/new-zealand-emissions-trading-scheme/in-principle-decisions
MT (Ministry of Transport) (2017), Electric Vehicles,
http://www.transport.govt.nz/ourwork/climatechange/electric-vehicles/.
NBR (National Business Review) (2015), ʻNZ Electricity Supply Security Unclear from 2019, Transpowersaysʼ, 9 December 2015, Retrieved December 2015 from: http://www.nbr.co.nz/article/nzelectricity-supply-security-unclear-2019-transpower-says-b-182736.
NZAS (New Zealand Aluminium Smelters) (2013), NZAS Signs New Electricity Agreement for the Tiwai Point
Smelter, http://nzas.co.nz/files/20130812142532-1376274332-0.pdf/.
NZG (New Zealand Government) (2010a), Electricity Industry Bill Passes,
www.beehive.govt.nz/release/electricity+industry+bill+passes/.
–– (2010b), Gerry Brownlee Opening Address to the New Zealand Petroleum Conference,www.beehive.govt.nz/speech/opening+address+new+zealand+petroleum+conference/.
–– (2011a), Environmental Protection Laws for Oceans Introduced, www.beehive.govt.nz/release/environmentalprotection-laws-oceans-introduced/.
–– (2011b), Nick Smith Speech to the New Zealand Climate Change Research Institute Forum: Climate Futures—
Pathways for Society, www.beehive.govt.nz/speech/speech-new-zealand-climate-change-researchinstitute-forum-climate-futures-%E2%80%93-pathways-society/.
NZP&M (New Zealand Petroleum & Minerals) (2014), Rules and Regulations,
https://www.nzpam.govt.nz/our-industry/rules-regulations/.
Otago Daily Times (2017), State coal patronage end in March with Solid Energy liquidation,
https://www.odt.co.nz/business/state-coal-patronage-ends-march-solid-energy-liquidation
RadioNZ (2015), Have asset sale funds gone where promised?,https://www.radionz.co.nz/news/political/285835/have-asset-sale-funds-gone-where-promised
Ralph Samuelson (2008), Oil: An Introduction for New Zealanders, Ministry of Economic Development.
http://www.mbie.govt.nz/info-services/sectors-industries/energy/energy-datamodelling/publications/oil-an-introduction-for-new-zealanders/oil%20an%20introduction.pdf
Rob Harris (2004), Handbook of Environmental Law, Royal Forest and Bird Protection Society of New
Zealand, Wellington.
Solid Energy (2016) Annual Report 2016 http://www.solidenergy.co.nz/wpcontent/uploads/2014/05/solid-energy-annual-report-2016.pdf
The Treasury (2011), State-Owned Enterprises, http://www.treasury.govt.nz/statesector/commercial.
Transpower (2015), Major Projects, www.gridnewzealand.co.nz/projects/.
Z Energy (2017), Z Bio D Biodiesel, http://z.co.nz/keeping-business-on-the-move/fuels/z-biodiesel/.

191

APEC ENERGY OVERVIEW 2017

NEW ZEALA ND

USEFUL LINKS

Climate Change Information, Ministry for the Environment—www.climatechange.govt.nz
Electricity Authority—www.ea.govt.nz/
Energy Efficiency and Conservation Authority (EECA)—www.eeca.govt.nz
Environmental Protection Authority—www.epa.govt.nz/Pages/default.aspx
Ministry of Business Innovation and Employment (MBIE)—http://www.mbie.govt.nz/infoservices/sectors-industries/energyNew Zealand Government (portal for access to New Zealandgovernment agencies and government-funded websites)—www.newzealand.govt.nz
New Zealand Government (news and speeches from government ministers)—www.beehive.govt.nz
New Zealand Parliament—www.parliament.govt.nz
New Zealand Petroleum & Minerals (formerly Crown Minerals)—www.nzpam.govt.nz/cms
Transpower—www.transpower.co.nz

192

APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEAP A P UA N E W G U I N E A
I N T ROD U C T I ON

Papua New Guinea (PNG) is an island-economy located in the south-western Pacific Ocean. It stretches fromsouth of the Equator to the Torres Strait, which separates New Guinea from Cape York Peninsula to thesouth, the northernmost extension of Australia. PNG has a total land area of 462 840 square kilometres (km²)
and is the largest of the Pacific Island countries, including the large islands of New Britain, New Ireland andBougainville and around 600 smaller islands. The economy’s capital, Port Moresby, is located in south-eastern
New Guinea on the Coral Sea. PNG became totally independent in September 1975 and has since struggled
to address one of its principal challenges of governing hundreds of diverse, once-isolated local ethnic groups
into a viable single economy (Standish and Jackson, 2017).
PNG sits along the ‘Ring of Fire’ that frequently faces earthquakes, volcanic eruptions and even tsunamis.
In fact, on 5 January 2018, a volcano on the remote island of Kadovar, located about 24 kilometres (km) northof the Papuan mainland, began erupting. Amidst the mountainous terrains, tropical rainforests and scatteredsmall islands lie the economy’s rich natural resources dominated by gold, copper, oil, gas, and also timber andagricultural exports (coffee, cocoa, tea, palm oil and copra). High temperatures and humidity throughout theyear and wet and dry seasons are characteristics of its climate.
PNG’s population is relatively young. Of the 7.92 million-strong population in 2015 (EGEDA, 2017),
almost 40% was below 15. PNG is one of the most culturally diverse countries in the world with arepresentation of ‘thousands of different tribes, dances, adventures, and traditions and over 800 indigenous
languages spoken, more than anywhere else in the world’. PNG’s population lives mostly in the rural areas;
only about 18% of the population lives in urban centres. The population density is also low, at about 18 people
per km² (World Bank, 2017a).
PNG’s economy is characterised by two main sectors: the labour-intensive sector (agricultural, forestry
and fishing) and the export-earning sector (minerals and energy extraction). The economy experienced strong
economic growth between 2010 and 2015, posting an annual average gross domestic product (GDP) growthrate of 7.8% (at 2010 prices and 2010 purchasing power parity [PPP]) (EGEDA, 2017). This was because of asignificant resources boom, mainly in the extractive minerals and hydrocarbon sector, due to construction ofa major liquefied natural gas pipeline (PNG LNG) from the Southern Highlands in 2014. In 2015, PNGʼs real
GDP was estimated at USD 21.18 billion (2010 USD PPP), an increase of 6.3% from 2014. The receipts frommining, together with those from petroleum, constitute the bulk of PNG’s export earnings (>70%) andconstitute over 20% of the economy’s GDP. Despite the strong revenue growth experienced by PNG for the
past five years, its GDP per capita in 2015 was the lowest among the Asia-Pacific Economic Cooperation(APEC) member economies, at USD 2 674 (2010 USD PPP) (Table 1) and the provision of basic services
continues to be a challenge.
PNG became a member of APEC in 1993. Additionally, the economy is a member of the African,
Caribbean and Pacific Group of States, the Non-Aligned Movement, the Pacific Community, the PacificIslands Forum, the United Nations and the World Trade Organization (The Commonwealth, 2017).
Table 1: Key data and economic profile, 2015
Energy reserves (end 2015) b

Key data a
Area (km2)

462 840

Oil (million barrels)

159.4 (2017 est)
141.5 (2017 est)

Population (million)

7.9

Gas (billion cubic metres)

GDP (2010 USD billion [PPP])

21.2

Coal (million tonnes)－

GDP (2010 USD PPP per capita)

2 674

Uranium (kilotonnes U)－

Sources: a EGEDA (2017); b CIA (2016)193

APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEAE N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY2015 saw a remarkable increase in PNG’s primary energy supply. From the 2014 levels of 2 615 million tonnesof oil equivalent (Mtoe), primary energy supply surged by almost 50% to reach 3 833 Mtoe in 2015. This was
mainly because of the more than fivefold increase in the gas supply of 283 Mtoe in 2014. Of the total supply,
crude oil and petroleum products maintained the largest share in 2015 (49%), although this was more than a
30% reduction from the 2014 level (72%). Gas was the second-largest fuel source and its share increased to
39% in 2015 from just 10% in 2014. The remaining share (12%) was attributed to other energy sources suchas hydro and renewables (EGEDA, 2017). Information on coal and uranium reserves have not been recorded
as the economy is not rich in nor has it touched upon these resources. There are investigations though
indicating that the Sepik Coal Basin has the potential to host economically viable coal resources given its
geological and structurally complex setting. However, the full potential can be understood only after extensive
exploration work and drilling programs have been concluded to firm up the coal resources (MRA, 2016).
Oil was discovered in PNG in 1987 and the first commercial production of crude oil started only in 1992.
It peaked at over 150 000 barrels per day (bbl/d) the following year. In 2016, oil production was estimated at
55 990 bbl/d (CIA, 2016). As there no reports of new oil discoveries, the existing oil reserves are depleting
rapidly and are expected to dry up in the 2020s (APERC, 2016). The economy has been importing a fluctuating,but unknown, amount of crude oil annually to feed its only refinery, the Napa Napa refinery (operated byPuma Energy, which acquired InterOil’s operations in 2014) with 506 000 cubic metres (m3) of storage capacity(Puma, 2017).
According to Oil Search, PNG’s pioneer partner in exploration, at present, there are approximately 10
trillion cubic feet (Tcf) of gas undeveloped 2C contingent resource within the Elk-Antelope fields in PRL 15
and the P’nyang field in PRL 3. The gas resources are sufficient to support two additional 4 million tonnes perannum (MTPA) LNG trains. In addition, subject to its successful appraisal, the recent Muruk discovery, locatedalong the Hides field, approximately 21 km from the nearest PNG LNG infrastructure, could increase theoptions for development and economic expansion (Oil Search, 2017).
The PNG LNG Project began commercial operations in 2014. This project is an integrated developmentthat includes gas production and processing facilities in the Southern Highlands, Hela, Western, Gulf andCentral Provinces of PNG. It will provide long-term supply of LNG to four major customers in the Asia
region. There are more than 700 km of pipelines connecting the facilities, which include a gas conditioning
plant in Hides and liquefaction and storage facilities near Port Moresby, with a capacity of 6.9 MTPA. Overthe life of the PNG LNG, over nine Tcf of gas is expected to be produced (PNG LNG, 2014).
In 2015, PNG generated 4 324 gigawatt-hours (GWh) of electricity, a 3.6% increase from 2014, which isalso the compounded annual growth rate (CAGR) since 2010. Thermal generation, sourced mainly from diesel,
contributed the largest share (67%), followed by hydro (23%) and others (10%) (Table 2, EGEDA, 2017).
Power generation from renewables, sourced mainly from hydro and geothermal, accounted for 33% of total
power generation in 2015. The electricity system of PNG is characterised by numerous small regional- or townlevel generation and distribution network systems without a central transmission network connecting
generation and consumption. The majority of these are thermal generation systems, except for three hydrolocations and two hybrid micro-hydro and diesel systems.
The economy's geothermal resources are known to be of high quality since PNG lies in the proximity of
the Pacific Rim of Fire. Geothermal wells are scattered all over the northern part of the economy. The
economy’s first geothermal plant was established at the Lihir Gold Mine with 56 megawatt (MW) capacity. It
was developed and owned by the Lihir mining company and the electricity generated from that plant was
mainly for their own use. As this plant is on the island and thus not connected to the grid, the company sells
the excess electricity to the nearby community. There is a plan to first develop a 5 MW pilot project and thena 40 MW one in West New Britain Province, followed by a 50 MW plant in East New Britain Province. The
economy’s possible proven reserves might be 4 000 MW, as indicated by the Icelander group (APERC, 2017).
In 2010, the International Renewable Energy Agency (IRENA) estimated that traditional biomass accounted
for more than half of PNG’s energy consumption and one-third of the energy supply (IRENA, 2013). However,194

APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEA

since there are no recent surveys to track biomass use and it is not commercial in nature, its use is largely
undocumented and therefore not well reflected in the statistics below.
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

10 098Industry sector

711

Net imports and others–6 249Transport sector

637

Thermal

2 890

Total primary energy supply

3 833

Other sectors

239

Hydro

1 012

Coal

0

Non-energy0

Nuclear

－

Oil

1 894

1 587

Others

422

Gas

1 489

Coal

0

450

Oil

1 253

0

Gas

0

Renewables

0

Renewables
OthersFinal energy consumption*

Electricity and others

Power generation (GWh)
Total power generation

4 324

334

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This isdifferent from total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste
used in power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

Compared to 2014, total final energy consumption in PNG in 2015 increased by 5.2% to reach 1 587 kilotonnesof oil equivalent (ktoe). The industrial sector remained the largest energy user, accounting for 45% of the total,
followed by the transport sector with 40%. In terms of growth, however, transport consumption (8.4%) surged
faster than industry consumption (7.2%) in 2015. The other sectors, including agriculture andresidential/commercial, constituted 15% of the total and posted a negative change of 7.6% from the previous
year’s consumption levels. By energy source, petroleum products accounted for 79% of the final energy
consumption (excluding non-energy uses), while electricity and other sources accounted for 21%, which has
remained roughly the same for the past four years (EGEDA, 2017).
As electrification remains limited to the main urban areas, 85% of the population that lives in rural areas
relies largely on traditional biomass to meet its energy needs. The levels of ownership of electric domestic
appliances are, therefore, not high. For example, the coverage of air conditioners in the capital city Port
Moresby is only 7% (ADB, 2015a) and is likely to remain low until wealth from the resource sector is translated
into improved incomes for the population and infrastructure development. In 2016, the PNG government,with help from Columbia University of USA, prepared the National Electrification Rollout Plan whose target
is 70% household electrification access by 2030 (APERC, 2017). Electricity consumption will increasesignificantly as these projects develop.
The transport sector faces a similar infrastructure challenge with road services generally limited to themain centres while intercity roads are few and in disrepair. Many locations can only be accessed through coastal
or river barges. As such, transport fuel consumptions will be hampered once road saturation levels are reached.
In 2015, transport consumption grew by 8.4% from the 2014 level to reach 637 ktoe.
Petroleum products such as diesel, petrol and heavy fuel oil are used in the transport and electricity
generation sectors. PPL and the PNG Government, with assistance from the World Bank, are continuously
extending their rural distribution networks throughout the economy, especially to the outskirts of urban areas.
The significant increase in consumption in the industry sector from 2014 to 2015 may be mainly
attributed to the growth brought about by the commercial operations of the PNG LNG in 2014.

195

APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEAENERGY INTENSITY ANALYSIS

Given the small size of PNG’s economy, intensity patterns can be affected significantly by individual eventsor trends and can be volatile. Primary energy intensity in 2015 posted a huge increase of 37.8% over theprevious year’s intensity level of 131 tonnes of oil equivalent per million USD (toe/million USD). The increase
was probably because of increased energy consumption in the industry sector from the LNG developmentthat started in 2014.
As there are no data on non-energy consumption in PNG, the estimated energy intensity comes purely
from final energy consumption. The final energy intensity in 2015 was estimated at 75 toe/million USD. Thistranslated to a 1.1% improvement over the 2014 energy intensity level of 76 toe/million USD (see Table 3).
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

131

181

37.8

Total final consumption

76

75

–1.1

Final energy consumption excl. non-energy uses

76

75

–1.1

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

There are no data available on renewable consumption in PNG. However, the economy relies largely on
biomass for cooking and lighting in the residential sector as 87% of its population lacks access to electricity.
Nevertheless, a total of 111 ktoe of modern renewables were estimated to be consumed in 2015, which was
about 7% of the total final energy consumption. This share was 3.2% lower than the modern renewables
consumption in 2014, but in terms of absolute values, it had increased 1.8%.
Table 4: Renewable energy share analysis, 2014 vs 2015

1 509

1 587

Change (%)
2014 vs 2015
5.2

1 400

1 476

5.4

Traditional biomass*

0

0

0

Modern renewables*

109

111

1.8

Share of modern renewables in final energy
consumption (%)

7.2%

7.0%

–3.2%

2014
Final energy consumption (ktoe)
Non-renewables (Fossils and others)

2015

Source: EGEDA (2017)* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member
economies, including those that are members of the Organisation for Economic Cooperation and Development(OECD) and those that are not (Non-OECD). All other renewables (hydro, geothermal, and so on) including biogas
and wood pellets are considered modern renewables, although data on wood pellets are limited.
STAKEHOLDERS IN ENERGY SECTOR

Prime Minister Peter O’Neill was re-elected for a fourth term in Parliament in the July 2017 election. With his
re-election, he committed to revitalise PNG’s economy, focusing on generating more revenue while
simultaneously managing debt levels, slashing unnecessary public expenditure and delivering key projects andservices to the people. Among other things, he committed to develop and maintain key productive
infrastructure assets including energy. The Department of Petroleum and Energy (DPE), a ministerial

196

APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEA

regulatory body in charge of all energy-related issues, especially policy, will undergo a massive restructuring
and follow the Mineral Resources Authority (MRA) structure. The MRA is another governmental agency
specialising in administration of mining activities, executed on behalf of the government under the Ministry of
Mining. The availability of official information related to the departments is moderate because of limited accessto their websites, except the MRA (recorded until January 2017). Besides the ministries, the PNG Chamber ofMines and Petroleum is an active non-profit organisation that offers a wide range of programs and projects
aimed at nurturing PNG’s full resource potential.
According to the Chamber, the main players in the petroleum market include Talisman and its joint
venture partners (active in the south-west region of the economy), ExxonMobil, Oil Search (focused on the
Fold Belt and the Hides, Angore and Juha gas fields), InterOil (Gulf region), Sasol, Mitsubishi and more than
15 other stakeholders. The large mining projects in 22 current mines include Barrick Gold’s Porgera gold mine,
Ok Tedi copper mine, Newcrest’s Lihir gold mine, Newcrest-Harmony’s Hidden Valley gold mine and MCC’s
Ramu nickel-cobalt project (MRA, 2016). Regarding the electricity industry, most thermal and hydropower
stations are owned and operated by the corporatised state-owned enterprise PNG Power Limited (PPL),
formerly the PNG Electricity Commission. Details of the functions of some of the energy stakeholders of PNG
will be discussed in the ‘Policy Overview’ section.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

Re-elected Prime Minister Peter O’Neill will lead the reorganisation of the DPE. Simultaneously, thegovernment will review the Mining and Petroleum Act in full consultation with PNG’s stakeholders, such as
the Foreign Investors and Resource Owners. This is to ensure that the benefits prescribed in Project
Agreements with regard to royalties and infrastructure grants are fully realised.
As mentioned above, the DPE structure will follow that of the Mineral Resources Authority. Part of thisreview will lead to the decentralisation of the functions responsible for managing resource owner funds, suchas the royalties and infrastructure funds. With regard to energy, the government will fund and implement the
Rural Electrification Policy. This will entail the promotion of green energy systems, including solar, wind,hydro, bio-fuel and geothermal energy. In this regard, the government will introduce a zero-tax policy for these
items (Government of PNG, 2018a)
The government’s long-term vision is outlined in the national development framework called Vision
2050. While this vision aims to create institutions that will equitably distribute resources and opportunities by
2050, it will be less reliant on the mining and energy sectors but will help create new income-earning
opportunities and improvements in human development outcomes. The plan has seven pillars encompassing
all areas of development with energy under the Environmental Sustainability and Climate Change pillar. The
Wealth Creation, Natural Resources and Growth Nodes may also influence energy development as
infrastructure develops and consumption grows. The key energy-related objectives include the following
points:100% electricity generation from renewable and sustainable sources by 2050

Reducing greenhouse gas (GHG) emissions by 90% from the 1990 levels

In March 2010, the government launched the Development Strategic Plan (DSP) 2010–2030, which will
provide a strategic planning framework focusing on extending economic growth benefits to the mostdisadvantaged regions and communities. In 2014, an addendum to the DSP was launched called the National
Strategy for Responsible Sustainable Development (StaRS) 2010–2030. This addendum emphasises thegovernment’s desire to reduce the economy’s reliance on non-renewable resource extraction and encourages
the development of environmentally sustainable industries and low-carbon technologies in pursuing a more
inclusive economic growth path (ADB, 2015a). This will be discussed further in the section on Renewable
Energy (Since 2011, the DPE together with other stakeholders has authored several draft energy policies pursuant
to the strategies and objectives mentioned above. The key draft policies included the National Energy Policy

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APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEA(NEP), Rural Electrification Policy and Strategy, Geothermal Energy Policy, Renewable Energy Policy and theElectricity Industry Policy (IRENA, 2013), although not all of them have been finalised and passed by thegovernment, such as the policy for geothermal power. However, significantly, the NEP with its accompanying
plan launched in 2015 was the first governmental document to properly coordinate all energy development
issues, in alignment with Vision 2050.
The NEP has been reviewed by all stakeholders and is being revised for submission to the National
Executive Council (NEC, the cabinet). This will be deliberated by the NEC and Parliament, before being
passed by the end of 2017. The NEP focuses on four aspects of sustainable development—social, economic,
environment and energy security—and incorporates the following nine principles:Strengthening institutional capacity and recruiting the right human capital to manage the energy
sector;

Developing an integrated planning process for sustainable energy supply and utilisation;

Developing all energy resources through the State for the betterment of all citizens;Promoting a conducive environment for long-term sustainable economic solutions in the supply of
all energy sources;

Encouraging the involvement of the private sector in the development and provision of energy
services;Ensuring that energy resources are developed and delivered in an environmentally sustainable
manner;

Promoting efficient systems and safety in energy supply in all sectors (transport, residential,commercial, industrial and agriculture); andDiversifying the development and utilisation of energy resources for the economy’s well-being andeconomic prosperity.

In October 2010, the PNG Government announced its Medium-Term Development Plan (MTDP)
2011–15. This plan focused on increasing access to electricity for all households in the economy. New
investments from the private sector in solar technology were also expected during the period of the first MTDP.
The succeeding MTDP 2016–2017, published in 2015, closely follows the National Strategy for Responsible
Sustainable Development and PNG Vision 2050. It is expected to place PNG in a better economic positionin the long term. Cleaner energy or electricity is highlighted to ensure less impact on the environment, while
mineral and gas industries will continue to play an important role in benefiting development. The MTDP3 will
cover the years 2018 to 2022.
In 2014, PPL published its Fifteen-Year Power Development Plan 2014–28 with projected areas ofgrowth. It is worth noting that according to this report, to achieve the targets indicated in the strategy
documents, the government will need a coordinated effort with the private sector to develop infrastructure,generate consumption, and source funding.
In 2016, the PNG government, with the help from Columbia University of USA, prepared the National
Electrification Rollout Plan (NEROP) which targets 70% household electrification access (). It details the
program to achieve this target (75% by grid and 25% off-grid) by 2030 (APERC, 2017).
ENERGY MARKETSPPL is PNG’s state-owned vertically integrated company created under the PNG Power Act 2002, to act as
the economy’s main utility providing electricity to all consumers. It has been granted the following licences by
the Independent Consumer and Competition Commission (ICCC): (1) Generation, (2) Transmission, (3)Distribution and (4) Retailing of electricity. PPL operates three separate urban grids (isolated) and 14 otherindependent provincial systems. In addition, there are a number of small rural electricity systems (C-Centres)
and privately owned facilities in rural areas. The three separate urban grids operated by PPL are 1) Port Moresby
System (POM), 2) Ramu System and 3) Gazelle Peninsula System. PPL’s 14 independent provincial systems(stand-alone systems) can be developed and expanded into separate small grid systems. These mini grids can

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be made ready to integrate into the larger grids, such as the POM, Gazelle and Ramu, in the near future(APERC, 2017).
The Act also authorised ICCC as the technical regulator of the electricity and petroleum sector and put
it in charge of determining standards, conducting inspections and controlling applications for all mattersrelating to the operations of electricity supply. The ICCC was established in 2002 to oversee and regulate priceand service-standard issues relating to utilities, such as PPL and selected corporatised government statutory
entities. This made it responsible for setting prices or tariffs for electricity and petroleum products. PPL wasalso corporatised under the Electricity Commission (Privatisation) Act 2002.
Lacking the technical capacity to perform this regulatory role, the ICCC outsourced this role to PPL on
a contractual basis for an initial period of two years, ending in 2005. PPL has an exclusive licence until 31
December 2017 to sell electricity within 10 km of its existing networks and sell individual customer loads of
up to 10 MW within its network areas (PPL, 2014). This may have been the first step towards retail competition
because the maximum size of loads can be decreased over time as retail competition is extended (Lawrence
Craig, 2017). The government continues to play an important role in the regulation of retail competition,
including issues of price control and market ownership in the Electricity Supply Industry and allowing for alower tariff for rural electricity users based on long run marginal cost. Any control mechanisms in ICCC shallbe gradually transferred, maybe to an energy regulatory commission when it is established.
FISCAL REGIME AND INVESTMENT

Following the 2017 election, the O’Neill–Abel Government announced the 100-Day Economic Stimulus Plan
to reinforce macroeconomic resilience and support inclusive growth. It establishes an ambitious set of 25priority objectives, aimed at strengthening confidence in the medium-term sustainability of the economy andpublic finances. Key elements include limiting the budget deficit to 2.5% of GDP in 2017, strengthening payroll
management and identifying 18 priority capital projects. The plan serves as a strong signal of the incoming
administration’s likely policy orientation over the coming years. It does not include any changes to tax rates,
removal of exemptions or other revenue-raising measures. One of the priorities of the plan states that USD
100 million will be released by the Bank of Papua New Guinea, presumably running down international
reserves by the same amount, and mentions a deal to settle purchases of crude oil for the Napa Napa refinery
in Kina, which could mean freeing up around USD 20 million a month (World Bank, 2017b).
Kumul Consolidated Holdings, (KCH, formerly IPBC) was formed by the Government of Papua New
Guinea under an Act of Parliament (2002, amended in 2012) for the benefit of the State, to act as the trustee,owner and all-encompassing authority for State-owned assets and enterprises. KCH, under its energy sector,
has embarked on delivering new major hydroelectric projects identified as critical to the long-term energy
security of the economy. The Ramu 2 Project (180 MW) launched in December 2016 is one such project.
Other projects, in various study and design stages, include the Naoro Brown Hydropower Project (60 MW),the Karimui Hydro Dam Study (1 800 MW) completed in January 2016, the POM IPP Project, the Port
Moresby Transmission Upgrade Project and the Purari Hydro Project (2 500 MW).
Kumul Petroleum Holdings Limited (KPHL) is PNG’s national oil and gas company (NOC). The NOC
was created by an Act Parliament through the Kumul Petroleum Holdings Limited Authorisation Act 2015.
KPHL is mandated to protect and maximise the value of the economy’s petroleum assets such that it cancontribute to the maximum wealth for its ultimate shareholders, the people of PNG. KPHL is currently
responsible for managing the State’s 16.57% equity in the US $19 billion PNG LNG Project through its
subsidiary Kumul Petroleum (PNG LNG) Limited.
The Konebada Petroleum Park Authority (KPPA) was set up by the government under the KPPA Act
2009 as a ‘free trade zone’. The role of KPPA is to facilitate, regulate and manage the park, which includes
planning and coordinating development by engaging the current and future stakeholders and bringing ininvestment. Land being declared as a free trade zone comes with tax incentives to lure investors and that land
ultimately acts as a one-stop shop for foreign and domestic investment purposes (APERC, 2017). Taxation of
the mining and petroleum sectors is generous compared with other resource-rich countries and has eroded
potential government revenues. An example of this is the discretionary 10-year tax exemption for the Ramu
Nickel mine and near-zero fiscal revenues from the new PNG LNG investment. The result is that the project
is not expected to generate significant tax revenues until the mid-2020s, largely because of a profit-based royalty

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regime and generous capital allowances cancelling out any tax liabilities. Discretionary exemptions granted to
specific firms or projects create precedents that in turn build pressure to grant further exemptions to newinvestors and existing firms, who feel they are disadvantaged because of the exemptions enjoyed by theircompetitors (World Bank, 2017b).
The International Monetary Fund provided technical assistance to the PNG Department of Treasury toreview the economy’s mining and petroleum taxation in 2013. The review’s purpose was to determine the‘appropriateness of the mining and petroleum taxation arrangement compared to similar resource-richcountries’ (CTR, 2014). In 2015, the government started a review of the electricity tariff methodologies toimprove the competitiveness of the electricity system, which was priced from USD 0.24 per kilowatt-hour(USD 0.24/kWh) to USD 0.47/kWh in 2012 (ADB, 2015b. Revenues to the government from energy project
originate from the following four principle sources (World Bank, 2017b):
1.

Royalties: 2% of the well-head value (payable to landowners and the affected provincial and local
governments);2.

Development levy: 2% of the well-head value (payable to the affected provincial and local
governments);

3.

Income tax: 30% tax on the profits of the project (payable to the central government);

4.

Dividends: Government’s share of profits from its 16.6% shareholding through Kumul Petroleum,and 2.8% shareholding by the Mineral Resources Development Company, held on behalf oflandowners.
ENERGY EFFICIENCYPNG does not submit data to EGEDA. As such, EGEDA estimated the economy’s energy data using various
reference sources such as JODI Oil and JODI Gas data, the annual report of Oil Search Limited (an oil
company based in the economy) and information from the economy’s privately operated geothermal power
plant. Specifically, EGEDA estimated the final energy consumption, electricity generation and inputs as wellas imports of petroleum products from these sources. PNG is also not known to have any existing policy onenergy efficiency (EE).
The NEP mentioned above, meanwhile, indicates some principles relating to the promotion of EE,
among others (APERC, 2017). These are as follows:
Principle 7 - Promote efficient systems and safety in energy supply in all sectors (transport, residential,commercial, industrial and agriculture).
(a)Ensure minimum energy performance standards for electrical equipment and adoption ofbuilding energy codes and other standards for safety.

(b)

Ensure safe transportation of energy products and wastes.

(c)

Promote solar power, solar thermal systems and LPG for residential, commercial and public
institutions.

Principle 9 - Promote EE and conservation measures and wise use of energy.
(a)Draft and enforce an EE Policy within one year of National Energy Authority’s creation(b)

Promote EE measures in all sectors (industrial, residential, agriculture and transport) of theeconomy in end-use of equipment and appliances.

(c)

Promote minimum energy performance standards and appliance labelling for all electricalequipment and appliances in collaboration with PNG Customs Services, National Instituteof Standards and Industrial Technology, ICCC and other relevant stakeholders.

(d)Promote the concept of energy-efficient buildings in accordance with the Building Act andRegulations.

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PAPUA NEW GUINEA

Promote energy audits in factories and industrial locations and demand-side management
programs in all sectors of the economy.

There have also been efforts made by other international agencies to gather information on EE indicators.
For example, in 2014, the Asian Development Bank (ADB) funded the Promoting Energy Efficiency in the
Pacific (phase 2) project conducted by International Institute for Energy Conservation. Through this project,
several activities were conducted in the Pacific to improve EE, including lighting, solar power generation, EE
in hotels and the commercial and public sectors, and data collection. Analysis revealed that in an aggressive
efficiency scenario, PNG could save more than 30% on the current level of consumption (ADB, 2015b). Whenthe potential growth of PNG is considered, this level of savings would improve the possibility of meeting its
targets as it would significantly reduce the generation and distribution requirements. The EE performance of
the appliances surveyed in the project were indicative of the manufacturer, as these were imported mostly froma neighbouring economy in APEC.
RENEWABLE ENERGY

In August 2017, PNG hosted the fourth phase of the APEC Peer Review on Low Carbon Energy Policy(PRLCE) project. In the background information provided by the economy for the peer review, several plansand programs relating to renewable energy (RE) were identified. These plans were already mentioned in thepreceding sections with PNG Vision 2050 as the economy’s guiding framework. Among these plans were the1) National Strategy for Responsible Sustainable Development for Papua New Guinea (StaRS under DSP
2010–2030)) and 2) Renewable Energy Plan (under the Electricity Industry Policy and National Electrification
Roll Out Plan) (APERC, 2017).
The StaRS seeks to increase the RE)-based power capacity of the economy to 100% by 2050. It indicatesseveral plans to achieve this target, including the following pointers (StaRS, 2014):
Inclusive Green Growth Policy Instruments to tap specific opportunities within spatial and resources
systems;Green Energy Investment Frameworks and Incentives, requiring significant government support for
renewable energy to establish an initial market share, to gain access to the national electricity grid andother energy infrastructure, and to attract investment.

Meanwhile, the RE Plan is initially focused on adding RE-based capacity for power generation.
Specifically, it intends to deliver the following pointers (APERC, 2017):


For geothermal, to extend the Gazelle grid and cover the West New Britain Province. An additional
95 MW should be added to the Gazelle grid by 2030 and another 110 MW to the Ramu Grid by 2050;

For hydropower, to increase capacity by 1 483 MW by 2030 and another 3680 MW by 2050 for the
POM and Ramu grids;

To deliver additional 62 MW biomass power to the Ramu grid by 2 030 and another 34 MW by 2050;



To add 30 MW wind power capacity to the POM and Ramu grids by 2030 and another 20 MW by
2050;



To have new 65 MW solar power capacities by 2030 and pursue the achievement of another 35 MW
by 2050; andTo develop the first 5 MW ocean energy facility for the economy by 2022 and connect this to thePOM grid.

The background information also covers a full range of potential energy resources for PNG including
the 15 000 MW hydropower and 4 000 MW geothermal possible proven reserves, among others. However,
the economy faces several challenges that hamper the development of these resources. Recent renewable
development is limited to privately developed hydro and geothermal generation in mining sites to support theirmining operations. For example, the peer review team visited an ongoing development of the 50 MWhydropower project, which will be added to the Port Moresby system by 2020.

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In 2016, PPL and the International Financing Corporation started to pursue rooftop solar projects to
produce electricity (PNGfacts, 2016), which was expected to reduce dependency on fossil fuels in the longterm.
NUCLEAR ENERGYPNG has no nuclear energy industry and there are no current plans to develop one.
CLIMATE CHANGE

PNG is a global leader in pushing climate change negotiations forward. It is a member of many Multilateral
Environmental Agreements including the Rio+20, the United Nations Convent to Combat Desertification and
the Convention on Biological Diversity. Over the past two decades, the PNG government has also
demonstrated good efforts to address global climate-change issues. For example, PNG ratified the United
Nations Framework Convention on Climate Change in 1993 and the Kyoto Protocol in 2002. It is also thefirst economy to respond to the Paris Agreement (COP 21), successfully submitting its Intended Nationally
Determined Contribution (INDC) in 2015. In 2016, it changed its INDC into a nationally determined
contribution. The PNG Vision 2050 is committed to reduce GHG emissions significantly with good forest
management and through the development of renewable energy resources. In 2015, PNG established the
Climate Change and Development Authority to implement the Climate Change (Management) Act, 2015. Allof these demonstrated the determination of the PNG government to reduce GHG emissions (APERC, 2017).
In October 2017, in cooperation with the United Nations Development Program (UNDP), PNG
launched the National REDD+ Strategy 2017–2027, which is a key part of the StaRS mentioned above. Its
implementation will strengthen the sustainability of PNG’s forest industries, support agricultural development
and improve land-use planning and management to ensure that the most important environments are protected.
The strategy will also help reduce emissions of GHGs and the vulnerability of rural communities to climatechange (UNDP PNG, 2017).
N OTA B L E E N E RG Y D E V E L O P M E N T S
LNG PROJECTSAs mentioned above, the PNG LNG Project began commercial operation in 2014, providing a long-term
supply of LNG to four major customers in the Asia region. LNG output from the project reached 8.6 million
tons (Mt) in 2016, which is 32% higher than the planned 6.5 Mt nameplate capacity (World Bank, 2017b). A
second LNG project (Elk-Antelope) is in the final review stage (Government of PNG, 2015). PNG is now innegotiations for a USD 10 billion expansion of ExxonMobil’s LNG project (Reuters, 2016). The project has
secured long-term supply contracts for LNG with China Petroleum and Chemical Corporation (Sinopec),
Osaka Gas, Tokyo Electric Power Company and CPC Corporation (WEC, 2016).
ENERGY WORKING GROUP (EWG) MATTERS

There was no PNG representative in the EWG 54 Meeting held in November 2017, but Ms Kiage from the
Department of Public Enterprises reported via phone patch the following current developments in PNG:

PNG wishes to include energy access as one of the priority agendas of APEC EWG;



Preparations are underway for PNG to host the APEC Ministerial Meeting in November 2018; and

PNG acknowledges the recommendations made by the peer review team during the conduct of
PRLCE) in August 2017.
RENEWABLE ENERGY DEVELOPMENT AND RURAL ELECTRIFICATIONPNG Power Ltd is the main agency responsible for rural electrification in PNG. The O’Neill Government willfund and implement the Rural Electrification Policy that entails promoting the use of green energy systems
including solar, wind, hydro, biofuel and geothermal energy. Accordingly, the Government will introduce azero-tax policy for these items.

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As mentioned above, to help realise the targets set in DSP 2010–2030, the NEROP was formulated withthe support of the World Bank. One of the strategies set out in the plan was conducting geospatial accessanalysis to determine the extent of lack of access to electricity to understand how to best approachelectrification in an efficient and cost-effective manner. The following strategies were indicated in the plan
(APERC, 2017):


75% of the population will be electrified by grid, while the remaining 25% will be electrified via offgrid electrification by 2030;



USD 150 million will be required to electrify 70% of the households by 2030; the cost of gridconnection will vary from USD 40 million to USD 115 million;

Funding for this program could come from connection charges of USD 15 million per year,
government commitment of USD 23 million per year, development partners’ grants and concessionalloans of USD 91 million per year;The institutional framework for the project will have PPL responsible for the grid extension. The
private sector may participate to provide off-grid or mini-grid solutions through a new entity that willbe established to manage implementation of NEROP. The DPE will be responsible for policies,
planning and monitoring of both grid and off-grid operations. The treasury will be responsible foradministering donor funds to the appropriate implementing agencies via a transparent process.

With implementation of NEROP, a total of 300 MW will be needed by 2030, which excludes
additional commercial, mining and industrial projects. A tariff of USD 0.10–12/ kWh is projected. A
separate parallel exercise will be undertaken to analyse the additional investments needed ingeneration and transmission.

Several partners are already active in the sector and are eager to support the NEROP implementation.
Aside from the World Bank, several partners are supporting PPL, namely, ADB, JICA, the AustralianGovernment and the New Zealand Government, in the areas of planning, grid reinforcement and extension,and financing of connections to households (World Bank, 2017c). For example, the ADB, together with DPE,
formulated the PNG National Distribution Grid Expansion Plan to boost the government’s efforts to connect
the people living in rural areas to the electricity grid. In partnership with the private sector, the project includes
the following pointers (SMEC, 2016):
Upgrading and rehabilitating two hydropower plants (Rouna 1 and Sirinumu Toe-of-dam);

Developing the 11 kilovolts (KV) distribution mesh network to extend the grid to approximately 3000 additional households;

Strengthening the distribution network;Constructing a new substation (Kilakila) with interconnecting 66 KV transmission lines; andUpgrading the existing substations.
INTERNATIONAL COOPERATION AND COMMITMENTPNG will be hosting the Asia Pacific Forum for the first time in November 2018. PNG stands to benefit frombeing in the global spotlight when it hosts this forum, with an anticipated boost in investment, tourism andtrade.
In preparation for this, the Australian High Commission and the Papua New Guinea APEC Secretariat
hosted a forum through the Pacific Leadership and Governance Precinct. This forum aims to raise awarenessof the opportunities that APEC would present in 2018, following the APEC Policy Development Dialogue
between PNG, Australia and senior APEC officials from across the region.
Australia is supporting PNG in its policy preparations for APEC by providing training for officials todevelop, advocate and implement policies and establishing the APEC Study Centre at the National ResearchInstitute (Australian High Commission, 2018), among other things.

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APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEATOWARDS SUSTAINABLE DEVELOPMENT

After his re-election, Prime Minister Peter O’Neill together with other key PNG leaders signed the Alotau
Accord II, with the theme ‘Strongim wok na Sindaun bilong ol Pipol’, which embodies the commitments of the
O’Neill government from 2017 to 2022. It will continue to uphold the directive principles reflected in the PNG
Vision 2050 and StaRS. To further ensure that the government continues to develop the economy, their plans
are spelled out in the current MTDP plan, 2016–17, which will be updated for 2018–2022. These documents
and all other strategies formulated under Vision 2050 are geared towards achieving sustainable development of
PNG (Government of PNG, 2018b).

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APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEAREFERENCES

ADB (Asian Development Bank) (2015a), Country Partnership Strategies: Papua New Guinea,
https://www.adb.org/sites/default/files/linked-documents/cps-png-2016-2020-ea.pdf― (2015b)). Promoting Energy Efficiency in the Pacific, Phase 2, Final Report prepared by International
Institute for Energy Conservation (IIEC) for ADB.
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APERC (2016), APEC Energy Demand and Supply Outlook 6 th Edition.
http://aperc.ieej.or.jp/file/2016/5/10/APEC_Outlook6th_VolumeII_EconomyReviews.pdf― (2017), Peer Review on Low Carbon Energy Policies (PRLCE) in PNG Report.
http://aperc.ieej.or.jp/file/2017/12/13/PRLCE_Report_in_PNG.pdf.
Australian High Commission (2018), APEC to put Papua New Guinea in the global spotlight.
http://png.embassy.gov.au/pmsb/821.html. Accessed February 2018.
CIA (Central Intelligence Agency) (2016), The World Fact Book: Papua New Guinea, Accessed January 2018,https://www.cia.gov/library/publications/the-world-factbook/geos/pp.html.
CTR (Committee of Taxation Review) (2014), Issues Paper Number 1: Mining and Petroleum Taxation.
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EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database_info/annual_data.html.
Government of PNG (2015), Medium Term Development Plan 2 2016-2017 submitted by Department of
National Planning and Monitoring.
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IRENA (The International Renewable Energy Agency) (2013), Renewable Energy Opportunities and Challenges in
the Pacific Islands Region: Papua New Guinea,
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Lawrence Craig (2017), Lowy Institute, Infrastructure Challenges for Papua New Guinea’s Future,
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MRA (Mineral Resources Authority) (2016), Mineral and Exploration Bulletin January-December 2016,
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National Strategy for Responsible Sustainable Development for Papua New Guinea (StaRS) (2014).
http://www.planning.gov.pg/index.php/publications/item/13-stars. Accessed February 2018.
Oil Search (2017), http://www.oilsearch.com/what-we-do/gas-growth. Accessed January 2018.
PNGfacts (2016), Rooftop solar power project to benefit private sector,
http://www.pngfacts.com/12/post/2016/08/rooftop-solar-power-project-to-benefit-privatesector.html#ixzz4cDYKuvee.
PNG LNG (2014), The PNG LNG Story. https://www.pnglng.com/. Retrieved January 2018.
PPL (PNG Power Ltd) (2014), PPL Energy Emergency Response Presentation at the 48th APEC Energy Working
Group Meeting, Port Moresby, p. 10．
Puma (2017), https://www.pumaenergy.com/en/where-we-operate/middle-east-asia-pacific/papua-newguinea/. Accessed January 2018.

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Reuters (2016), https://www.reuters.com/article/papua-lng-minister/minister-plays-down-landownerthreats-to-png-lng-operations-idUSL4N1E1218.
SMEC (2016), http://www.smec.com/en_au/what-we-do/projects/Port-Moresby-National-GridExpansion-Plan. Accessed February 2018.
The Commonwealth (2017), http://thecommonwealth.org/our-member-countries/papua-new-guinea.
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06/png-launches-national-redd-strategy.html
Standish and Jackson (2017), Papua New Guinea, Encyclopædia Britannica.
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Accessed January 2018.
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206

APEC ENERGY OVERVIEW 2017PAPUA NEW GUINEAUSEFUL LINKS

Papua New Guinea, Development Strategic Plan 2010–30—
www.treasury.gov.pg/html/publications/files/pub_files/2011/png-development-strategic-plan.20102030.pdf/
Papua New Guinea, Medium Term Development Plan 2016-2017—
http://www.planning.gov.pg/images/dnpm/pdf/MTDP2.pdf
Papua New Guinea Mineral Resources Authority. Government Links and Other Links—
www.mra.gov.pg/Help/UsefulLinks.aspx/
Papua New Guinea Chamber of Mines and Petroleum—http://pngchamberminpet.com.pg/
Peter O’Neill: Prime Minster of Papua New Guinea—http://www.pm.gov.pg/
The World Bank, http://www.worldbank.org/en/country/png

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PERU

PERU
I N T ROD U C T I ON

Peru is a constitutional republic located on the west-central coast of South America, bordered by the Pacific
Ocean, with Chile to the south, Ecuador and Colombia to the north and Brazil and Bolivia to the east. With aland area of 1.3 million square kilometres (km2), Peru is divided into three main geographical regions: the coastto the west, the mountain region (Andes Mountains) and the Amazonian region (Selva). Peru is divided into
25 political departments (administrative regions).
In 2015, Peru had a total population of about 31
million, an increase of 1.3% from the previous year Figure 1-Map of Peru
(EGEDA, 2017). In 2015, approximately 22% of
Peru’s population was considered poor and 4.1%
extremely poor (INEI, 2015a). The major population
centre of Peru is Lima, with 9 million people, which isnearly one-third of the total population (INEI,
2015b). The urbanisation rate of Peru is 76% (INEI,2011).
Between 2000 and 2015, Peruvian economy
grew fast with an average annual rate of 5.3%. Thisrate was higher than the level reached in 2015 (3.3%),
owing to the deceleration of emerging economies andglobal uncertainty. This resulted in negative growth
rates in private and public investments (−4.4% and−7.5%, respectively) and a reduction in the private
consumption growth rate from 4.1% in 2014 to 3.4% in 2015 (BCRP, 2015). In 2015, Peru’s gross domestic
product (GDP) was USD 362 billion (2010 USD purchasing power parity [PPP]), whereas its GDP per capita
grew by 2%, reaching USD 11 529 (EGEDA, 2017). In addition, foreign reserves reached a record USD 61
billion, whereas the fiscal balance was 2.1% of the GDP (BCRP, 2015).
Since 1990, Peru’s economy has been driven by its internal consumption, mainly private investments,
exports and domestic consumption. Peru has a market-oriented economy, and in 2015, its key segments wereservices (49%), manufacturing and construction (18%) and mining and energy (12%) (BCRP, 2015).
Mining is especially important for the economy because Peru is a major global producer of several metallic
and non-metallic minerals, ranking third in silver, zinc, copper and tin; fourth in lead; and sixth in gold
production (USGS, 2016). Consequently, mineral exports have consistently accounted for a significant shareof the export revenues, contributing as much as 55% in 2015 (BCRP, 2015). During 2015, around 20% of the
USD 24 billion of foreign direct investments was dedicated to the energy, oil and transport sectors(Proinversion, 2015).
Table 1: Key data and economic profile, 2015
Key dataa

Energy reservesb, c, dArea (million km2)

1.3

Oil (billion barrels)

1. 2Population (million)

31

Gas (trillion cubic metres)

0.4

GDP (2010 USD billion PPP)

362

Coal (million tonnes)

9

GDP (2010 USD PPP per capita)

11 530Uranium (kilotonnes U)

42

Sources: a EGEDA (2017); b BP (2017); c MEM (2014); d NEA (2016).

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E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Peru’s total primary energy supply (TPES) in 2015 was 22 614 kilotonnes of oil equivalent (ktoe), increasing
5.6% from 2014. This was because of an increase in oil supply, driven by an increase in the import of both
crude and oil products, which was more than proportional to decreases in oil, coal and natural gas domestic
production. Per energy source, in 2015, around 47% (11 341 ktoe) of the TPES was from oil, 30% from naturalgas (7 100 ktoe) and 3% from coal (810 ktoe). Other energy sources, including hydro, wood, bioenergy, windand others constituted the remaining 20% (4 823 ktoe) (EGEDA, 2017).
Owing to its scarce oil resources, Peru is a net oil importer, because domestic production is insufficient
to meet consumption. However, because most crude oil produced is of extra-heavy quality and domestic
refineries are unable to process it, a substantial share of the domestic production is exported.
The proven gas reserves of the economy were 0.4 trillion cubic metres (tcm) in 2016 and are expected toincrease to 0.8 tcm by 2025, based on the information from the Ministry of Energy and Mines (MEM) (MEM,2014). The Camisea gas field, the largest in Peru, is located 500 km from Lima, in the region of Cusco.
Production at the field has allowed Peru not only to meet growing domestic consumption but also to become
a liquefied natural gas (LNG) exporter. Since 2012, more than 95% of Peru’s total gas production comes fromthe Camisea field.
The Camisea field was initially aimed at satisfying the domestic consumption for natural gas. However,
because production levels have increased at an average annual rate of 63% since 2004, excess supply was
directed to exports with the construction of the Peru LNG Melchorita liquefaction plant. Peru’s LNG exports
amounted to 8.1 billion cubic metres (bcm) (BCRP, 2015).
Peru’s proven coal reserves are around 9.9 million tonnes (Mt) with about 95% consisting of anthracite
and the remainder of bituminous coal. Most the reserves are located in the La Libertad, Ancash and Lima
departments. Peru is a net importer of coal, with 80% of its coal consumption in 2014 being met by imports
and 20% by domestic production (MEM, 2014).
The other energy sources category, which represents 20% of Peru’s TPES, includes different types ofbiomass, such as firewood, vegetable coal, dung and yareta (a moss-type plant dried and then burned) and areused mostly for heating and cooking. In 2015, renewable sources used for energy supply included firewood(38%) and hydropower (48%), but the remainder was from other biomass sources (MEM, 2015).
In 2015, Peru’s electricity generation totalled 48 066 gigawatt-hours (GWh), a 5.6% increase from 2014.
Hydropower and thermal generation contributed almost by halves, with 48.9% and 48.5%, respectively. The
remainder 2.6% power generation share came from solar PV, biomass and wind (EGEDA, 2017).

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Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe) Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

22 614

Industry sector

5 217

Net imports and others

368Transport sector

7 942

Thermal

23 52424 069Other sectors

5 176

Hydro

23 301

Coal

810

Non-energy

305

Nuclear0

Oil

11 34118 335

Others

1 242

Gas

7 100

Coal

726

Renewables

4 823

Oil

10 058

−5

Gas

1 730

Renewables

2 183

Electricity and others

3,638

Total primary energy supply

OthersFinal energy consumption*

Total power generation

48 066

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

Peru’s total final consumption increased by 6% in 2015, reaching 18 640 ktoe. Transportation represented 43%of the total final consumption in 2015, increasing rapidly by 5.9% on an average from 2000 to 2015, reaching
7 942 ktoe. The industrial sector share was 28%, whereas the ‘other’ sector, including residential, commercial
and agricultural energy consumption was also 28%. The remaining 1.6% share was attributed to non-energy
consumption. Final energy consumption, excluding non-energy consumption, was 18 335. Oil products
dominated the final energy consumption in 2015 with 55% of the total share, most of which was consumed as
diesel, gasoline and liquefied petroleum gas (LPG) (MEM, 2015). Electricity constituted 20% of final energy
consumption, whereas gas and coal accounted for the remaining 9.4% and 4.0%, respectively (EGEDA, 2017).
ENERGY INTENSITY ANALYSIS

Peru’s energy intensity had been decreasing since 2011. However, this trend was reversed in 2015. From 2014
to 2015, primary energy supply intensity increased by 2.3%. Following the same trend, total final consumption
intensity increased even faster, by 2.8% compared to that in 2014. Final energy intensity (excluding non-energy
consumption) increased by 2.6% compared to that in 2014. Peru’s energy intensity increase could be explainedby the very rapid growth on oil consumption in the transportation sector.
Table 3: Energy intensity analysis, 2014
EnergyEnergy intensity (toe/million USD)
2015

2014

Change (%)
2014 vs 2015

Total primary energy supply

65

67

2.3

Total final consumption

50

52

2.8

Final energy consumption excl. non-energy

49

51

2.6

Source: EGEDA (2017).

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RENEWABLE ENERGY SHARE ANALYSIS

Modern renewables consumption increased by 13% from 2014 to 2015, driven predominantly by hydropower
generation. Its share to final energy also increased at a slower pace, by 6.3%. Traditional biomass consumption
decreased by 1.6% in 2015. However, it remains an important fuel for the residential sector.

Table 4: Renewable energy share analysis, 2014 vs 2015
2014
Final energy consumption (ktoe)

2015

2014 vs 201517 27918 335

6.1

Non-renewables (Fossils and others)

13 43314 295

6.4

Traditional biomass*

2 063

2 031

−1.6

Modern renewables*

1 782

2 010

13

Share of modern renewables to final energy
consumption (%)

10%

11%

6.3%

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial) using inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (e.g. hydro and geothermal energy), including biogas and wood pellets,
are considered modern renewables, but data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

Peru’s Ministry of Energy and Mines (MEM) is responsible for the formulation and evaluation of energy andmining policy as well as for environmental issues concerning energy and mining activities. The MEM is divided
into two parts: the Vice-Ministry of Energy and the Vice-Ministry of Mines. Through its general directorates(i.e. electricity, rural electrification, hydrocarbons, energy efficiency, mining, energy-environmental issues andmining-environmental issues), the Vice-ministry of Energy covers the major areas of influence in the sector,
overseeing activities and promoting investments to achieve sustainable development.
In addition to the MEM, the Supervisory Agency for Investments in Energy and Mining(OSINERGMIN) is Peru’s autonomous regulatory agency, created in 1996. OSINERGMIN is responsible forsetting electricity tariffs and gas transportation rates. Its goal is to promote efficiency in the power and gas
sectors at the lowest possible cost for the customer by designing and implementing effective regulations.
The government published the National Energy Plan 2014–25 (MEM, 2014) detailing the policies andobjectives to guide energy policy of the economy. According to the plan, Peru’s overarching goal is to have areliable, continuous and sufficient energy system that can support sustainable development, in part bypromoting investments in infrastructure (e.g. transport, refinery and production) and exploration. The National
Energy Plan’s main goals (MEM, 2014) are to provide energy security and universal access to energy supply
and to develop energy resources under a social and environmental perspective. Under the same plan, thegovernment also set energy efficiency goals, focusing on the following:

Establishing new labelling rules for electrical appliances, water heaters, lighting, electric engines andboilers;Promoting an energy efficiency culture;Establishing an exclusive means for the public transportation system;211

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

Maximising the use of natural gas in power generation;

Promoting the substitution of LPG and diesel to natural gas; andStriving to maintain energy prices in real terms, avoiding price distortions.

Simultaneously, the Energy Plan considers the expansion of gas pipelines to cover the entire coastal
region. By 2025, this is expected to increase natural gas consumption up to the goal of 35% of final energy
consumption.
One of the aspirational goals under this plan is to improve the electrification rate to 99% by 2025, throughthe implementation of the Social Energy Inclusion Programme. The programme intends to increase electricity
coverage for 2.2 million people living in isolated regions by expanding the grid and providing access to nonconventional energy sources (Table 1). Furthermore, the Social Energy Inclusion Fund aims to provide 1.2
million low-income families access to LPG through discount coupons. Finally, the distribution of improved
cook-stoves aims to encourage a more efficient use of traditional biomass among low-income families. These
improved cook-stoves are 50% more efficient in the consumption of traditional biomass, reducing CO2
emissions and respiratory diseases (APERC, 2017).
Table 5: Energy social inclusion indicators of Peru, Energy Plan 2014–25
2013

2016

2025

Electricity Access (% population)

90

96

99

LPG Discount Coupons (Families)

645 000

1 200 000

1 200 000

Improved Cooking Kits (Families)

72 000144 000

500 000

Source: MEM (2014).

Peru is seeking to become an energy hub in the South American region by encouraging energy integration
projects with Ecuador, Colombia and Chile in electricity, Brazil in hydropower and Bolivia in gas. Peru has
electricity interconnections with Ecuador via two transmission lines (500 kilovolts [kV] and 220 kV).
Agreements with Bolivia intend to support transportation of its gas to the LNG terminal in Peru. In addition,
Peru and Bolivia are undertaking studies in electricity to assess the potential of interconnecting their powersystems to jointly supply electricity to Chile.
ENERGY MARKETSThe Peruvian economy became more market-oriented following structural reforms in the 1990s, resulting in
the privatisation of the mining, electricity, hydrocarbons and telecommunications industries. Several laws
established a regime under which domestic and foreign investments were subject to equal terms. This has
encouraged foreign companies to participate in almost all economic sectors. In 1999, Peru passed the Law for
Promotion of Natural Gas Industry Development (Law 27133), establishing specific conditions to promote
the development of the natural gas industry (El Peruano, 1999).
In recent years, Peru has expanded and streamlined the available investment schemes with a focus onareas involving exports, infrastructure and services to the population. Thus, investments in oil and gas
upstream activities are conducted under licences or service contracts granted by the government through the
MEM. Some of the conditions in upstream and downstream activities are summarised in Table 5.
Table 6: Investments required according to the Energy Plan 2014–25
Upstream Activities
Exploration
Exploitation

Authorisation up to seven years.
The Ministry of Energy and Mines can extend it up to three additional years.
Maximum 30 years for crude oil.
Maximum 40 years for non-associated natural gas and condensates.
Downstream Activities

Transportation

Conducted by ships or pipelines.

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Concession up to 60 years.
Authorised by the General Directorate of Hydrocarbons (Ministry of Energy and
Mines).
Liquid hydrocarbon and similar hydrocarbon by-products require authorisationfrom the Ministry of Energy and Mines.

RefineryDistribution
Source: E&Y (2014).

The increasing energy consumption and the abundance of natural gas will challenge the economy toincrease energy investments to meet future energy infrastructure requirements. Peru’s Energy Plan forecaststhat USD 50 billion investments will be required in the energy sector, given the expected rapid GDP growth
rates.
Table 7: Investments required according to the Energy Plan, 2014–25

Electricity

Gas

Oil

GDP 4.5%

GDP 6.5%

Generation

6 700

7 300

Transmission

1 700

1 700

Upstream

5 200

6 000

Gas pipelines

11 55011 680Petrochemicals

5 000

5 000

Upstream

16 00018 000Downstream refineries

3 500

3 500

49 65053 180Total *USD million
Source: MEM (2014).

ENERGY SECURITY

In 2012, the Peruvian Government published the Law to Ensure Energy Security and Promote theDevelopment of the Petrochemical Industry (Law 29970). It states that energy security becomes a matter ofnational interest and mandates the diversification of energy sources, the reduction of external dependence andan increase in the energy supply chain reliability. The law also mandates the construction of specificinfrastructure projects, such as parallel pipelines to the Camisea gas pipeline and the Camisea products pipeline
and an LNG imports regasification terminal.
ENERGY ACCESSThe National Plan for Rural Electrification 2016–25 was established to provide energy access to vulnerable
populations in remote rural areas. Peru has a diverse geography with almost 25% of the population living in
the Andes Mountain and the Amazon region. Approximately 75% of the rural population has access toelectricity. These regions gather the population with the lowest income levels and, accordingly, the highest
poverty rates. The plan expects to generate energy access to 3.3 million people until 2025, investing around
USD 1.2 billion in transmission and distributed generation systems.
Table 8: Investments according to the National Plan for Rural Electrification
Investment(USD MM)

Population(Thousand)

2016

346

1000

2017

230

606

2018

136

351

2019

173

538

2020

94

226

2021

41

160

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2022

60

230

2023

24

87

2024

24

87

2025

24

87

Total

1 152

3 372

Source: MEM (2015)
ENERGY EFFICIENCYIn 2000, the government passed the Law for the Promotion of the Efficient Use of Energy (Law 27345).
Consistent with this legislation, the Peruvian Government promoted energy-saving measures in the public
sector, such as by replacing less-efficient incandescent lamps with compact fluorescent lamps and acquiring
equipment with energy efficiency labels.
In 2009, the MEM presented the Benchmark Plan for Efficient Use of Energy from 2009 to 2018. The
plan aims to reduce energy consumption by 15% from the 2007 levels by 2018 through energy efficiency
measures. The plan includes an analysis of energy efficiency in Peru and identifies sector programmes that
could be implemented to achieve the proposed targets. Actions outlined in the plan include lighting systems,
replacement of boilers and engines as well as implementation of a labelling scheme for computers. To date,the implementation of the plan has been delayed owing to a shortage of audit firms and lack of incentives forthe main stakeholders.
In May 2010, the Peruvian Government created the General Directorate for Energy Efficiency (DGEE),
within the Vice-Ministry of Energy, as the technical regulatory body, proposing and assessing energy efficiency.
The DGEE also leads the energy planning of the economy and is responsible for developing the National
Energy Plan.
RENEWABLE ENERGY

Peru has established goals to increase renewable energy use and has developed a legislative and policy
programme to support their development. Around half of the power generation in Peru comes from renewablesources, of which almost entirely from hydropower.
In 2006, the Law to promote the use of renewable energy provided a tax reimbursement on electricity
sales coming from renewable sources. In 2008, Peru Congress passed another law (1058), giving tax benefits
to investing participants in electricity generation, based on renewable energy, including hydropower. Finally,
the Law on Promotion of Investment for Electricity Generation with Renewable Energies was enacted in 2008
with relevant regulations for implementing this law. Some of the incentives provided by the law are as follows(El Peruano, 2008a, 2008b):


The Ministry of Energy will impose every five years a minimum share of power generation coming fromrenewable sources. This definition excludes hydropower plants bigger than 20 MW; therefore, thisdefinition excludes most of the hydropower plants currently in operation.

However, during the first five years, the renewable power generation share could not be bigger than 5%of total power generation.



A firm price guaranteed for bidders who are awarded energy supply contracts for up to 20 years; and

Priority in dispatch and access to networks.

The drafting of a Peruvian Renewable Energy Plan.

To achieve these goals, the MEM established open auctions for renewable energy suppliers to ensurecompetitive conditions for the electricity generators and their customers. By 2015, the total generation capacity
and average cost by technology were as follows:

Wind: 232 MW at USD 78 per megawatt-hours (MWh).



Mini Hydro: 496 MW at USD 56 per MWh.

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PERU

Photovoltaic: 96 MW at USD 173 per MWh.

In September 2015, a legislative decree modified the regulation on electricity distribution, including thepossibility of a feed-in tariff system for those who generate their own electricity based on non-conventional
renewable technologies (El Peruano, 2015).
Table 9: Generation potential
Renewable energy source

Potential (MW)Installed capacity (MW)Photovoltaica

540

96

Windb

22 000232

Hydropowerb

69 000391

Biomassb

177

27

Geothermalb

3 000

-

Sources: a. IFC (2011) b. MEM (2014).
NUCLEAR

Although Peru does not use nuclear energy for electricity generation, a government-run nuclear energy
programme has been operational since 1975. This programme includes constructing a basic infrastructure,human resources training and the establishment of the Peruvian Institute of Nuclear Energy. Peru has been amember of the International Atomic Energy Agency since its creation in 1957.
CLIMATE CHANGE

As part of its environmental strategy policy, in October 2003, the Peruvian Government approved the National
Strategy on Climate Change (NSCC) for the mitigation of an adaptation to climate change (El Peruano, 2003).
The main objectives of the NSCC are to reduce climate change impacts through integrated studies onvulnerability and adaptation and to control both pollution and greenhouse gas (GHG) emissions by using
renewable energies and energy efficiency programmes in the production sectors.
Table 10: GHG emissions by activity
Activity

GHG emissions (%) by 2012

Industrial processes

51%

Energy26%

Agriculture

15%

Waste

5%

Land use, land use change and forestry(LULUCF)
Source: MINAM (2016)

3%

Peru accounts for 0.1% of the world’s GHG emissions (CAIT, 2012). Based on the Intended Nationally
Determined Contribution (INDC), Peru aims to reduce GHG emissions by 30% by 2030 compared with thebaseline. The absolute reduction is estimated at 90 million tonnes of CO2 equivalent, with 50% of thisreduction being in the forestry sector, including land use, land use change and forestry (LULUCF)(UNFCCC, 2015).
Table 11: INDC for reduction of GHG emissions

2010 (baseline year)

Emissions Mt CO2eq
including LULUCF
170

Emissions Mt CO2eq
excluding LULUCF
782030 (target year)

298

139

Source: MINAM (2016)

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In parallel to the national goals expressed in the Peruvian INDC, several sectors have presented
significant advances in regulations and programmes aimed to reduce carbon emissions and to foster sustainable
development.
Energy Sector: The National Energy Plan 2014–25 projects providing natural gas access to residential
sector across Peru, because it is currently concentrated in Lima and a handful of other cities. Thus, LPG
consumption is expected to diminish in urban areas while promoting it as a substitute of traditional
biomass in rural regions.



In addition, the Ministry of Energy and OSINERGMIN are promoting the use of non-conventional
renewable energies through annual auctions, giving priority to dispatching into the national electricity gridand ensuring price stability during the contract.



In the transport sector, in 2014, the construction of Line 2 of Lima’s Metro started with the goal ofconnecting 15 districts with an extension of 27 kilometres, projecting a daily consumption of 665 000
passengers by 2020.

Industrial and Fishing Sectors: The regulation establishes that, wherever natural gas connection ispossible, fishmeal factories must use it instead of oil products. The MEM estimates that currently around
one-third of national production is using natural gas in their industrial process because of the new
regulation.



Forestry Sector: Since 2010, the forestry sector has a new regulatory framework, which aims to reduce
deforestation and promote sustainable and efficient use of forestry resources.



Waste Management: The National Environmental Action Plan (PNAA) promotes the reuse, recycling
and appropriate handling of solid municipal waste. The PNAA was implemented in 210 municipalities,
recovering around 10 974 tons of solid waste per month.

Finally, Peru is designing eight nationally appropriated mitigation actions as part of the National Strategy
for Climate Change.
N OTA B L E E N E RG Y D E V E L O P M E N T S
OIL AND GAS

The government announced a plan to reorganise state-owned oil company Petroperú. The changes include
structural management changes and the involvement of independent professionals. The reorganisation also
allows Petroperú to participate in exploration and production contracts, celebrate associations or joint-ventureswith private companies.
Peru is expected to become more dependent on both crude oil and oil products imports as the rapid
growth of the transport sector increases the consumption. To address this challenge, the government isoverhauling the existing facilities of the Talara refinery so that heavy oil can be refined domestically. The
project, with a cost of around USD 3.5 billion, is expected to increase the refinery capacity from 65 to 95
thousand barrels per day (Mbbl/D).
The government is also encouraging state-owned companies to become more active in hydrocarbon
exploration and production projects. The government is reducing the time required to obtain exploration
permits and facilitating communication with local communities to help reduce protests against exploration andproduction of extractive activities.
As already stated, almost the totality of gas production in Peru is transported by a single pipeline, theCamisea Gas Pipeline. To diminish the vulnerability of depending on a single gas transport system and provide
other regions access to this fuel, the Peruvian government conceived the construction of an alternative gas
pipeline transporting the Camisea field’s gas to the South of Peru. The Peruvian Southern Gas Pipeline project
involves the transport of gas produced in the Cusco region to the southern coastal city of Ilo through a 1 000
km, 32-inch diameter pipeline system, divided into three sections. The project originally had thermal power
plants, a petrochemical complex, industry and residential users as potential clients.

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In 2014, the Peruvian Government awarded the contract to a consortium integrated by Brazilian
company Oderbrecht and Spaniard Enagas. The construction started in 2015. However, by January 2017, thePeruvian government ended the contract after the consortium failed to meet its financial deadline. The
consortium lost trust from banks financing the construction because of the ongoing investigation on alleged
corruption cases of Oderbrecht in Brazil, Colombia, Mexico, Peru and other countries.
The construction of the pipeline had, at that moment, a general progress of around 40%. Companies,
such as Sempra, showed initial interest in acquiring the gas pipeline and continuing its construction, but
withdrew from negotiations, based on the argument that the government is unable ‘to provide necessary
assurances that the concession would not be cancelled due to alleged legal violations by the seller’. The Peruvian
government will start a new bidding process and expects the contract to be awarded to a new consortium inearly 2019 and only after that will the construction works restart.
Finally, the reactivation of the electrification project in rural areas with photovoltaic energy in charge ofthe company Ergon Peru has completed 6 000 photovoltaic installations in the regions of Amazonas,
Huancavelica, Huánuco, Puno and San Martín, of the total of 150 000 committed. The project will supply
electric power to 15 000 rural isolated locations which are not connected to the main electricity grid.

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MEM (Ministerio de Energía y Minas) –– (2014), Plan Estratégico Nacional 2014–2025,
http://www.minem.gob.pe/minem/archivos/2ResEje-2014-2025%20Vf.pdf.
–– (2015), Plan Nacional de Electrificacion Rural Periodo 2016-2025,
http://extwprlegs1.fao.org/docs/pdf/per153304anx1.pdf.
MINAM (Ministerio de Ambiente) (2016), El Perú y el Cambio Climático. Tercera Comunicación Nacional del Perú.
http://www.minam.gob.pe/wp-content/uploads/2016/05/Tercera-Comunicaci%C3%B3n.pdf.
NEA (Nuclear Energy Agency) (2016), Uranium 2016: Resources, Production and Demand, https://www.oecdnea.org/ndd/pubs/2016/7301-uranium-2016.pdf.
USGS (United States Geological Survey) (2016), Minerals Information. http://minerals.usgs.gov/minerals/.
UNFCC (United Nations Framework Convention on Climate Change) (2015), INDCs as Communicated byParties [Online],
http://www4.unfccc.int/ndcregistry/PublishedDocuments/Peru%20First/iNDC%20Per%C3%BA%2
0english.pdf

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USEFUL LINKS

Agencia de Promoción de la Inversión Privada—www.proinversion.gob.pe
Banco Central de Reserva del Perú—www.bcrp.gob.pe
Comité de Operación Económica del Sistema Interconectado Nacional—www.coes.org.pe
Instituto Nacional de Estadística e Informática—www.inei.gob.pe
Instituto Peruano de Energía Nuclear—www.ipen.gob.pe
Ministerio del Ambiente—www.minam.gob.pe
Ministerio de Economía y Finanzas—www.mef.gob.pe
Ministerio de Energía y Minas—www.minem.gob.pe
Organismo Supervisor de la Inversión de la Energía y Minería—www2.osinerg.gob.pe
Perú Ahorra Energía—http://elcomercio.pe/noticias/ahorro-energia-156394
Perúpetro. La Agencia Nacional de los Hidrocarburos—www.perupetro.com.pe
Planta de licuefacción de GNL Peru LNG (2010). —http://portal.perulng.com/irj/go/km/docs/documents/PLNG%20Website/index.htm
Portal de Cambio Climático—http://cambioclimatico.minam.gob.pe
Presidencia de la República del Perú—www.peru.gob.pe
Programa de Adaptación de Cambio Climático—www.paccperu.org.pe
Proyecto Camisea—www.pluspetrol.net/camisea.html

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THE PHILIPPINESTHE PHILIPPINESI N T ROD U C T I ON

Owing to recent discoveries, the Philippines archipelago now comprises 7 641 islands (Primer, 2017), covers atotal land area of 343 448 square kilometres (km2) (Government of the Philippines, 2018) and has a coastlineof about 36 289 kilometres. The Philippines is located in the south-eastern part of Asia and is bordered by thePhilippine Sea to the east and west, the Luzon Strait to the north and the Celebes Sea to the south. It has threemajor geographical divisions: Luzon, Visayas and Mindanao islands. Manila City, located in Luzon, is the capitalof the Philippines. In 2015, the total population of the economy reached 101 million, an increase of 1.6% fromthe 2014 level (EGEDA, 2017). As per the 2016 World Population ranking, it is the twelfth-most populated
economy in the world (WB, 2016).
The Philippines maintained the 6.1% growth rate in its gross domestic product (GDP) from USD 646
billion in 2014 to USD 685 billion in 2015 (2010 USD purchasing power parity [PPP]) (EGEDA, 2017). The
service sector continued to drive the economy’s growth, followed by industry. While the economy’s growth
for the last two years was slower than 2012 and 2013, the 2015 rate was still faster in comparison to its middleincome ASEAN neighbours, such as Indonesia and Thailand. The current growth is accompanied by an
improved rate of capital formation. The government has also maintained a sound fiscal balance along asustainable debt path (Briones, 2016). Continued high economic growth in the past few years is necessary forthe fight against poverty. The GDP per capita also displayed a 4.4% growth, from USD 6 453 in 2014 to USD
6 736 in 2015 (EGEDA, 2017).
With a better economic outlook, the government faces a great challenge in ensuring energy supply
stability to meet growing domestic consumption. Central to the policy of the government is the aggressive
development and utilisation of indigenous energy resources for both fossil fuels and renewable energy (RE).
The government has continued the Philippine Energy Contract Round (PECR) to attract investments in oil,gas and coal exploration. The economy has modest proven reserves of around 76 million barrels of oil (includes
condensate), 24 billion cubic metres (834 billion cubic feet) of natural gas and 440 million tonnes (Mt) of coal
(DOE, 2015a).
Passing of the Renewable Energy Act of 2008 (RA 9513) offered fiscal and non-fiscal incentives topromote and encourage more investments in RE development and to expand its share in the energy mix.
Under the National Renewable Energy Programme (NREP), the government has set an aspirational target of
more than doubling the RE-based installed capacity in power generation by 2030 from the 2010 levels, orachieving 15 299 MW (2030 level) in comparison to 5 542 MW (2010 level). The government likewise intends
to increase RE contribution for non-power applications in the primary energy mix by 2030 (DOE, 2011).
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesc

Area (thousand km2)

343

Oil (million barrels)

76

Population (million)

101

Gas (billion cubic metres)24

GDP (2010 USD billion PPP)

685

Coal (million tonnes)

470

GDP (2010 USD PPP per capita)

6 736

Uranium (kilotonnes U)–

Sources: a Government of the Philippines (2018); b EGEDA (2017); c DOE (2016).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLYThe economy’s total primary energy supply (TPES) in 2015 increased significantly by 9.3% in comparison to
the 2014 level, from 48 460 ktoe to 52 962 kilotonnes of oil equivalent (ktoe). Approximately 53% of the220

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energy requirement was produced locally, largely from RE (39%) and oil (34%). The economy’s self-sufficiency
level decreased slightly from 57% in 2014 to 53% in 2015 (EGEDA, 2017).
Renewables─comprising hydro, geothermal, biomass and others─formed the bulk of TPES of theeconomy in 2015. The 2015 growth was 1.5% percentage point more than the compounded annual growthrate (CAGR) for the last five years of 2.6%. This increase can be attributed to the remarkable upsurges in solar(seven times) and wind (four times) primary supplies (EGEDA, 2017).
Oil remained the second dominant energy source, accounting for 33% of the TPES. The economy’s oil
supply requirement grew significantly by 19.1% in 2015, reaching 17 933 ktoe from 15 060 ktoe in 2014.
Coal provided the third-largest share to the TPES at 22%, which was an increase of 9.3% from the 2014
level to reach 11 634 in 2015. The recent upswing development in the coal industry, which spurred interest
even from the small-scale mining operators in the economy, may have contributed to the increase in coalsources in 2015 (DOE, 2016).
FOSSIL ENERGY

The economy relies heavily on fossil fuels imports, specifically oil and coal, to meet its energy consumption
requirement. The net imports in 2015 significantly grew (by 23.8%) from 21 094 ktoe in 2014 to reach 26 118
ktoe in 2015. Oil constituted nearly 70% of the total energy imports, whereas coal represented 31% andbioethanol 1%. The rise in energy imports was caused by a 3% increase in oil consumption for power
generation, resulting in an 18% increase in oil imports.
Coal exportation declined by 46% from the 2014 level, resulting in an equivalent net importation of 51%
in 2015. Relatedly, local coal production saw a decline of 2% in 2015 from the 2014 coal production level of
4 012 ktoe (EGEDA, 2016). Indonesia remained to be the primary source of coal imports in the Philippines,
which also increased by 10% from the 2014 coal import levels (DOE, 2015b).
RENEWABLE ENERGY

RE has long been a significant contributor to the economy’s energy supply requirement, providing 39% to the
TPES in 2015. Among the renewables, biomass was the largest contributor with 35%, followed by geothermal,
which, despite an increase in absolute terms, had supplied 34% of the total indigenous primary energy supply.
The residential sector is the primary user of biomass, specifically for cooking. The industry and power sectors
also utilised a portion of the biomass supply. Energy production from hydro continued to pose a decline from
786 ktoe in 2014 to 745 in 2015, owing to the El Nińo phenomenon from March 2015 (DOE, 2015c).
Solar and wind were smallest contributors, contributing less than 1% to the total indigenous primary
supply. The growth of solar and wind however was remarkable, increasing more than five times the 2014
supply levels to reach 76.3 ktoe in 2015 (EGEDA, 2017). The shares from these RE resources are expected to
expand soon with the growing number of awarded contracts issued to RE developers by the government. Asof the end of 2015, there were 55 and 124 new wind and solar projects awarded, respectively.
Commercialisation will bring an additional 571 Mw capacity (Wind: 427 Mw and Solar: 144 Mw) (DOE,
2015d).
ELECTRICITY GENERATION

In 2015, the economy’s total electricity generation was up 6.7% from 77 261 GWh in 2014 to 82 413 GWh.
Coal is still the dominant fuel for the economy’s baseload requirement, accounting for about 45% of the total
power supply in 2015. Natural gas also continued to provide a substantial share: 23%. Almost all the natural
gas power-generation capacities are located in Luzon Island, supplying around 31% of the Luzon grid
requirement (DOE, 2015c). Meanwhile, oil-based power plants had a modest share of 7% during the same
period.
Despite the commercial operation of additional capacities from solar, wind and even biomass, theaggregate share from renewables (including hydro and geothermal) in 2015 reduced by 1% from the last two
years’ share of 26%. Electricity output from hydro went down by 5.2% in 2015, from 9 137 GWh in 2014,
owing to El Nińo (EGEDA, 2017). The remarkable surge of power generation from solar, wind and biomass

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THE PHILIPPINES(244%) from 2014 to 2015 can be attributed to the feed-in-tariff (FiT) race brought by the economy’s RE Law(DOE, 2015c)
Table 2: Energy supply and consumption, 2015
Primary Energy Supply (ktoe)

Total Final Consumption (ktoe)

Power Generation (GWh)

Indigenous production

27 966 Industry sector

6 718 Total power generation

82 413

Net imports and others

26 118 Transport sector

10 194

Thermal

61 450Total primary energy supply

52 962 Other sectors

12 743

Hydro

8 665

Coal

11 634 Non-energy

1 179

Nuclear0

Oil

17 933 Final energy consumption*

29 655

Others12 298

Gas

2 877

Coal

2 218

Renewables

20 518Oil

14 0250

Gas

50

OthersRenewables

7 530

Electricity and others

5 831

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

The 6.1% growth of the Philippines economy in 2015 translated to an 8.5% increase in the total final
consumption (including non-energy), reaching 30 834 ktoe in 2015 from 28 430 ktoe in 2014 (EGEDA, 2017).
All economic sectors posted an increase in their fuel consumption during the same period. The non-energy
sector, although providing the least share of the total final consumption (TFC), displayed the largest growth at
95%, followed by the transport sector at nearly 16%. The other sectors, comprising the commercial, residential
and agricultural sectors, exhibited 2% growth. Energy consumption in the commercial sector, which showed
increases for the last five years, slightly contracted by 1.1% in 2015 from the 2014 demand level . Consumption
in the residential sector increased by 2.8% compared to the 2014 level, whereas the agriculture sector
rebounded with a 12% increase in 2015 (EGEDA, 2017).
The transport sector’s energy use accounted for 33% of the TFC in 2015. More than 50% of this 33%
was diesel oil, the primary fuel used for public transport. Industry consumed 22% of the TFC with coal being
the largest share (35%) of the sector’s fuel consumption (EGEDA, 2017). About 80% of the coal used in the
sector was for cement production (DOE, 2015b).
The other sectors’ aggregate energy consumption was 41% of the TFC in 2015 (EGEDA, 2017). The
residential sector required more than two-thirds of the other sectors’ consumption, representing 30% of theTFC. The bulk of the energy consumption of the sector was biomass. The commercial sector demanded 26%of the other sectors’ consumption, and the remaining was shared by agriculture and non-energy use (EGEDA,
2017).
In terms of fuel sources, oil products continued to be the major fuel for the economy, representing 47%
of final energy consumption, excluding non-energy. Oil consumption likewise grew the fastest among the fuels
at 12% to reach 14 025 ktoe in 2015. Electricity and other fuels expanded by 7%, contributing to an aggregate
share of 20% to the final energy consumption (EGEDA, 2017).

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ENERGY INTENSITY ANALYSIS

Given that GDP in the Philippines in 2015 grew by 6.1%, the energy requirements in both primary and final
consumption increased accordingly. This has also resulted in positive energy intensities between 2014 and 2015,
after posting energy intensity reductions for the last five years.
Specifically, primary energy intensity grew by 3% and final intensity (non-energy included) grew by 2.3%.
These increases can be attributed to the >10% increase in oil requirement in 2015. Change in energy intensity
between 2014 and 2015 in the final energy consumption (non-energy excluded), although minimal, was positiveat 0.5%. This may be attributed to the >15% expansion in the transport sector. As in most developing
economies in APEC, the increase in the Philippines’ purchasing power may have boosted the purchase ofprivate vehicles and consequently the consumption in the transport sector, thereby contributing to the 43
toe/million USD (in 2010 USD PPP) energy intensity in 2015 (EGEDA, 2017).
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

75

77

3.0

Total final consumption

44

45

2.3

Final energy consumption excl. non-energy

43

43

0.5

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

Owing to the RE Act of 2008, which aimed to triple the level of RE sources in the Philippines by 2030 incomparison to the 2010 level, renewables use in the economy has significantly accelerated. Between 2010 and2015, modern renewables posted an upward trend of 3% compounded annual growth rate. This has further
increased by 0.9 percentage point in 2015 to reach 2 616 ktoe. Considering the share of the total final energy
consumption, however, it contracted to 8.8% from the 2014 level of 9%. The upswing in the share of fossil
fuels to the final energy consumption may have offset the minimal expansion in the renewables share in 2015
(EGEDA, 2017).
Table 4: Renewable energy share analysis, 2014 vs 201527 82529 655

Change (%)
2014 vs 2015
6.6

Non-renewables (Fossils and others)

18 87520 641

9.4

Traditional biomass*

6 429

6 397

–0.5

Modern renewables*

2 521

2 616

3.9

Share of modern renewables to final energy
consumption (%)

9.1

8.8

–2.5

2014
Final energy consumption (ktoe)

2015

Source: EGEDA (2017)* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member
economies, including those that are members of the Organisation for Economic Cooperation and Development(OECD) and those that are not (Non-OECD). All other renewables (hydro, geothermal, and so on), including biogas
and wood pellets, are considered modern renewables, although data on wood pellets are limited.

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THE PHILIPPINESP OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKThe government recognises the importance of energy to boost the economy’s inclusive growth anddevelopment. The Department of Energy (DOE) has been at the forefront of formulating responsive energyplans and programs to address the many issues and challenges of ensuring energy supply security and expanding
access to energy for the greater public to improve local productivity and fuel rural development. The Philippine
Energy Plan 2012–2030 still serves as the guidepost for the economy, outlining several measures and targets
that the government and the energy stakeholders must jointly undertake to bring reliable and affordable energy
services to the populace and create a sustainable future with less carbon footprints. The energy plan espouses
the government policy thrusts and goals and includes the following pointers:a.

Ensuring energy security by expanding the share of renewables in the total power generation capacity
mix, promoting exploration and development of indigenous fossil fuels and providing reliable andefficient power supply;b.

Expanding energy access by increasing household electrification levels;c.

Promoting a low-carbon future by achieving 10% energy savings and increasing the share ofalternative fuels in public utility vehicles; andd.

Promoting more climate-change-resilient energy infrastructure.

The DOE studied the possible fuel mix policy for power generation to determine a reliable long-term
power generation mix model for the economy. Based on the results of the prepared fuel mix models withassistance from the Japan International Cooperation Agency (JICA) in August 2014, the proposed fuel mix
should comprise 30% renewables and 30% natural gas (DOE, 2015e). In July 2015, the DOE issued a
Department Circular (DC 2015-07-0014) prescribing a policy for maintaining the share of RE in the total
power installed at a minimum of 30% through FiT and other mechanisms, as stipulated in the Renewable
Energy Act (DOE, 2015f).
ENERGY MARKETSOIL AND GASIn order to promote and encourage investments in the exploration of the economy’s 16 sedimentary basins(with combined oil and gas reserves of 4 777 million barrels of oil equivalent, or 690 million tonnes of oil
equivalent [Mtoe]), the government has continuously implemented the PECR. The PECR is a transparent andcompetitive system of tending onshore and offshore oil and gas blocks for exploration that are offered to both
local and foreign investors. During the fifth PECR in 2014 covering 11 petroleum potential areas, thegovernment received three bids in 2015 and recommended awarding service contracts to add to the existing
25 petroleum service contracts already being monitored by the government (DOE, 2016).
The economy’s existing oil and gas fields produced 3.07 million barrels (Mbbl) in 2014, 63% higher thanthe 2013 output, owing to production from new wells in the Galoc field. In the same year, gas production grew
by 5.2%, reaching 130 351 million standard cubic feet, almost all (99%) coming from the Malampaya gas field.
Gas produced from Malampaya is mostly used to fuel three natural gas power plants (with an aggregate capacityof 2 861 MW) located in Luzon Island. Likewise, Malampaya produced 4.2 Mbbl of associated condensate(DOE, 2015e).
COAL

The economy has 13 coal basins with an estimated total resource potential of 2.4 billion metric tonnes. The
largest coal resources are found in Semirara, Antique with a total potential of 570 million metric tonnes (Mmt).
However, the economy’s coal resources are low-ranking coal. Therefore, there is a high dependency on
imported coal (high-ranking), which is used by the coal power plants. To reduce dependency on imported coal,
the government has been pursuing efforts to expand the utilisation of indigenous coal, as well as the adoptionof local coal quality upgrading technologies such as coal washing, preparation and blending to meet the224

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environmental standards. Further, the government is exploring alternative uses of local coal through assessing
the coalbed methane potential of selected coal fields. A significant portion of local coal production is exported,
mostly to China.
Like oil and gas, the government is also promoting PECR to encourage investors to explore the coalresource potential of the economy. During the fifth PECR, the government awarded seven coal exploration
contracts (COCs) to explore potential coal areas in Mindanao Island (DOE, 2016). These additional COCs
could boost the coal reserves of the economy. In terms of coal production from existing COCs, a total of 7.6
Mmt (at 10 000 BTU/lb) was produced in 2014. Of the total coal production, 97% came from Semirara,
Antique. The small-scale coal mines in Negros, Surigao del Sur, Zamboanga del Sur, Bicol and in Cebu
province contributed about 0.23 Mmt or 3% of the total domestic production.
MARKET REFORMSELECTRICITY

The government continuously oversees the implementation of power sector reforms, as mandated in theElectric Power Industry Reform Act (EPIRA) of 2001 (or Republic Act 9136). In accordance with Section 31of the EPIRA, the government successfully commenced the full commercial operation of Retail Competition
and Open Access (RCOA) in June 2013, with 275 participating competitive customers duly registered by theCentral Registration Body (DOE, 2015f). In 2015, the number of participants increased to 434 (DOE, 2016).
Under RCOA, the customers having an average load requirement of 1.0 MW over the last 12 months cansource their electricity supply from retail electricity suppliers by allowing the use of transmission anddistribution systems and from associated facilities subject to the payments of transmission and distribution
wheeling charges duly approved by the Energy Regulatory Commission (ERC).
The DOE has been supervising the operation of the Wholesale Electricity Spot Market (WESM) of thePhilippine Electricity Market Corporation (PEMC). As of 2014, the integrated Luzon–Visayas WESM
registered 229 participants comprising 54 generating companies and 175 customers (13 private distribution
utilities, 71 electric cooperatives (ECs), 79 bulk users, five contestable customers and seven wholesale
aggregators). To include ancillary service requirements of the power grid in WESM operation, the DOE issued,in December 2013, a Department Circular (DC 2013-02-0027), ‘Declaring the Commercial Launch for the
Trading of Ancillary Services (through the Establishment of a Reserve Market) in Luzon and Visayas under
the Philippine Wholesale Spot Market’.
DC 2013-02-0027 set the commercial operation of the reserve market in March 2014 after launching of
the trial operation plan (TOP). The PEMC commenced the TOP in February 2014 in two phases. The firstphase covered testing of protocols, procedures and interfaces for the Market Operator-System Operation andReserve Market Working Group, including addressing other operational issues. The second phase involved
demonstration of operations of the reserve market and familiarisation of trading participants in all processes(DOE, 2015e).
However, the DOE issued another Department Circular (DC 2014-03-0009) in March 2014, ‘Declaringa New Commercial Launch Date for the WESM Reserve Market and Directing PEMC to Develop a Protocol
for Central Scheduling and Dispatch of Energy and Contracted Reserves’, which subsequently reset thecommercial operation to May 2014. To have a detailed evaluation, the PEMC conducted a reserve market
forum to deliberate the results of the TOP, conducted from February to April 2016. Until June 2016, the
PEMC continued to undertake activities for the reserve market, such as market participants’ registration andtraining and testing of enhancement on market operator and system operator procedures (DOE, 2015f).
The reserve market will benefit the power market with co-optimisation of energy and reserves, as well as
promotion of greater competition among energy and reserve providers, leading to more transparent andcompetitive energy prices. Furthermore, the reserve market will facilitate the entry of RE in accordance with
the RE Act of 2008.
As part of the sustainable solutions for the Mindanao Island requiring additional power generation
capacities, an Interim Mindanao Electricity Market (IMEM) was established, which commenced full operationin November 2013. The IMEM is intended to encourage participation of the existing power-generating

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capacities and interruptible loads,1 and entry of new generating capacities in Mindanao. The IMEM rules wereamended in May 2014 to include ‘demand-side bidding and transitory arrangement’ (DOE, 2015e). In 2014,
IMEM market intervention was still in effect because of the continuing power-supply deficiency in the
Mindanao grid. The DOE held several discussions with stakeholders to resolve some issues on IMEM
operations and make amendments to the market rules. Once the IMEM rules are ready for implementation,
the government will lift the IMEM market intervention (DOE, 2015f).
The DOE assessed the possibility of implementing a ‘demand aggregation and supply auctioning policy’(DASAP) for the electric power industry. The objective of this policy is to achieve greater transparency andreasonableness in electricity tariffs and to encourage greater participation from the generation sector inproviding adequate power supply in each franchised area served by the distribution utility. In lieu of the nonissuance of the DASAP, the DOE issued a Department Circular (DC 2015-06-0008) in June 2015 entitled‘Mandating All Distribution Utilities to Undergo Competitive Selection Process (CSP) in Securing Power
Supply Agreements (PSA)’ (DOE, 2015g). The circular mandates all distribution utilities to undergo CSP,
through a third party duly recognised by the DOE and ERC. In ECs, the National Electrification
Administration (NEA) should recognise the third party (DOE, 2016).
OIL

As part of its mandate, the DOE ensures an adequate and stable oil supply in the economy by continuously
monitoring activities in the downstream oil industry, such as crude and product imports/exports and costs,
local production, industry consumption, inventory levels, distribution and marketing facilities, and oil pricemovements. The DOE still implements the minimum inventory requirement to have a steady oil supply,
specifically during emergencies such as natural disasters. The minimum inventory requirement covers oil
companies, bulk suppliers and liquefied petroleum gas (LPG) players operating in the economy. Refineries are
required to have in-country stocks equivalent to 30 days, whereas bulk marketers and LPG players must
maintain 15 days and 7 days’ stock, respectively. As of December 2014, the average inventory was equivalent
to a 46-day supply (DOE, 2015h).
The DOE entered a memorandum of agreement (MOA) in October 2014 to develop a framework thatwill enable a sustainable supply of petroleum products in the event of natural disasters or emergencies. Parties
to the MOA are the Metro Manila Development Authority, Office of the Civil Defense, Natural Risk
Reduction and Management Council, and the members of the Philippine Institute of Petroleum (DOE, 2015e).
Likewise, the Mutual Product Sharing Accommodation (MPSA), established through a Department Circular(DC 2011-03-003) issued by the DOE in 2011, is part of the emergency response measures of the economy.
The DOE implemented the MPSA when the economy was hit by super typhoon Haiyan in 2013. The MPSA
intends to provide and stabilise oil supplies in calamity-affected areas, as it permits oil companies to supply
petroleum products to the facilities of other oil companies to ensure a steady supply of petroleum products inthe affected areas.
DOWNSTREAM NATURAL GAS

With depleting domestic natural gas resources, the government is now looking at the possibility of importingliquefied natural gas (LNG). The Energy World Corporation (an Australian company based in Hong Kong,
China) is building an LNG terminal and a merchant gas-fired power in Pagbilao, Quezon province. The LNG
facility constitutes two storage tank units with a capacity of 130 000 cubic meters (Cm) each, a regasification
plant, and an on-site 600 MW merchant gas-fired power plant to serve as an anchor load for the project (DOE,
2015e). In 2015, the DOE granted the Energy World Corporation a 12-month extension upon expiration of
their five-year provisional permit for the completion of their LNG hub terminal facilities (DOE, 2016).

1 The interruptible load program (ILP) is another measure implemented in Mindanao where customers of a distribution

utility (DU) are compensated for voluntarily de-loading from the grid by using the generation facility for their own use
during peak demand hours. The DU will then charge and collect from the customers within its franchise area thecorresponding energy ‘freed up’ (in kilowatt-hours) by the ILP customers. This money will be used to pay these customers
based on the Energy Regulatory Commission-approved ILP rates.

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THE PHILIPPINESThe Philippine National Oil Company (PNOC) commissioned the Public–Private Partnership Center(PPPC) for the detailed feasibility study of the 105 km Batangas–Manila pipeline (BatMan 1) to supplement
the JICA study completed in June 2014 (DOE, 2015e). JICA performed a feasibility study for the entire natural
gas supply chain in the economy, which covered the LNG facility, regasification facility, pipeline and offtake
facilities, among others. The PNOC availed upon the Project Development and Monitoring Facility (PDMF)2
from the PPPC to source funds in engaging the expertise of the Rebel Group International as its transaction
advisor. The pipeline potential route corridors were identified by the transaction advisor. From the results of
the route analysis, the most appropriate route will be proposed to bring the natural gas from Batangas’
proposed LNG terminal to the nodal gas consumption located alongside the pipeline route through the Manila
metropolis (DOE, 2015e).
The final draft of the Natural Gas Quality Standard was published in February 2015 and was endorsedby the Bureau of Philippine Standards. This standard is necessary for more efficient supply acquisition anddistribution of natural gas in the economy. In November 2015, the DOE signed a memorandum of
understanding with other government agencies to establish the Inter-Agency Health, Safety, Security andEnvironment Inspection and Monitoring Team for natural gas facilities (DOE, 2016).
The economy has not yet promulgated a comprehensive policy and regulatory frameworks to govern thedevelopment of the downstream natural gas industry. The Natural Gas Bill is still pending in both Houses ofCongress.
ALTERNATIVE FUELSThe DOE drafted a MOA with the Development Academy of the Philippines to formulate the Alternative
Fuels Roadmap to serve as a blueprint for the government during the program’s implementation. The DOE
has been implementing policies and programs on alternative fuels as ways to diversify fuel and reduce
dependence on imported fuels and to promote a preference for cleaner fuels.
The enactment of the Biofuels Act in 2006 mandates the current 2% biodiesel blend (B2) and 10%
bioethanol blend (E10) in all diesel and gasoline fuels sold in the economy. The DOE in cooperation with
the University of the Philippines–Los Baños conducted a study entitled ‘Economic Impact in the Increased
Use of Biodiesel in the Philippines’ to evaluate the effect of increasing the utilisation of biodiesel and theimpact of the nationwide implementation of 5% biodiesel blend (B5) in the economy. The economy has alsoplanned to increase the biodiesel blend to 20% (B20) by 2025 and the bioethanol blend to 20% (E20) in
2020.
Under the government’s program Natural Gas Vehicle Programme for Public Transport (NGVPPT),the DOE is working closely with the Department of Transportation (DOTr) and the Land Transport
Franchise Regulatory Board to issue franchises for 169 CNG buses. In March 2015, the DOTr declared theavailability of these franchises under the NGVPPT. Likewise, the DOE is coordinating with the natural gas
suppliers for the supply of CNG fuel until 2023. The DOE also directed the PNOC-Exploration
Corporation (PNOC-EC) to take over the operation of the CNG refuelling station.
As for the Auto-LPG program, the DOE signed a MOA with two academic institutions in December
2014 to train proficient technicians who will be involved in migrating from gasoline-fed to auto-LPG vehicles,
including the repair and maintenance of such vehicles. The DOE has been coordinating with concerned
national government agencies for the promotion and mainstreaming of auto-LPG in the transport sector todiversify the economy’s utilized fuel sources.
ENERGY EFFICIENCY

The government has continuously implemented the National Energy Efficiency and Conservation Programme,
launched in 2004, as the banner program on the various initiatives on energy efficiency and conservation. This
program includes the following projects:
The Philippine government, with assistance from Asian Development Bank (ADB), has established a PDMF to fundtransaction advisory services for the development of PPP projects, which include energy and social projects, such as road
networks, school buildings, airports and hospitals, among others.
2

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THE PHILIPPINESEnergy Efficiency Standards and Labelling Programme;Government Energy Management Programme;Energy Management Services/Energy Audits;

Fuel Conservation and Efficiency in Road Transport; andPower Conservation and Demand Management (Power Patrol), among others.

The DOE approved the implementation of the Energy Efficiency and Conservation Roadmap in July
2014, which specifies a direction towards an energy-efficient economy by 2030. The roadmap identifies shortto medium-term action plans across key energy consuming sectors with the objective of achieving 40%
reduction in energy intensity by 2030 based on the 2010 level. The roadmap will provide more sustainable andlong-term policy directions on energy efficiency and conservation.
Fig 1: Energy Efficiency and Conservation Roadmap

The Energy Efficiency Roadmap for the Philippines

Source: DOE (2015c).
The DOE has pursued the accreditation of energy service companies (ESCOs) to promote emerging
business industries in the economy. As of 2105, the economy had 15 accredited ESCOs to help accelerate theimplementation of energy efficiency and conservation measures in the private sector. The DOE also offers
audit services to manufacturing plants, commercial buildings and other energy intensive companies to evaluate
the energy utilisation efficiencies of equipment, processes and operations and to recommend energyconservation measures for adoption by these companies.
The DOE has implemented the Philippine Industrial Energy Efficiency Project in partnership with theUnited Nations Industrial Development Organisation and the Department of Trade and Industry. The Global
Environmental Fund provided funding for this project. The project will introduce the application of ISO 50001
to selected industrial sectors, such as chemicals, food and beverage, iron and steel, and pulp and paper. The
project could save about 2 million megawatt-hours of energy (DOE, 2015e).
RENEWABLE ENERGY

Government efforts to promote and expand the use of RE as a clean and sustainable energy source for the
public became evident with the formulation and adoption of the NREP in 2011. The NREP outlines the228

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strategy and measures to facilitate greater private sector investment in RE development, including addressing
the challenges and gaps to effect wider application and utilisation of renewables. Other policy mechanisms as
stipulated in the RE Act of 2008 have been implemented or are in the process of on-going implementation,such as



FiT;



Renewable Portfolio Standards (RPS);Green Energy Option Programme; and

Net-Metering for RE

Upon recommendation of the DOE, the ERC promulgated the FiT rules and FiT rates based on the set
installation targets. The ERC approved the initial FiT rates in July 2012. FiT rates are subject for review andreadjustment after three years of implementation or once the DOE installation targets have been achieved. In
August 2014, the DOE issued a certification for an increase in the FiT installation target for solar energy from50 MW to 500 MW, including lower FiT rates for the additional capacity. The FiT installation target for wind
was also increased in April 2015 from 200 MW to 400 MW. The increases in solar and wind installation targets
brought the total targets to 1 410 MW, which are as follows:

250 MW Run-of-River Hydropower

250 MW Biomass

400 MW Wind



500 MW Solar

10 MW Ocean

The RPS is a market-based policy requiring mandated electric power industry participants to source a
portion of electricity supply from RE resources. In the RPS, the mandated industry participants are thegenerators, distribution utilities and electric suppliers. The Green Energy Option Programme enables endusers to choose RE resources as their primary source of energy. Net Metering is a consumer-based RE
incentive scheme wherein the electric power generated by an end-user from an eligible on-site RE generating
facility and delivered to the local distribution utility can be used to offset electricity provided by the distribution
utilities to the end-user during the applicable period.
In 2014, the DOE awarded 220 service contracts for different RE resources with potential capacity of 3
184 MW (DOE, 2015e), whereas the 133 service contracts awarded in 2015 have an aggregate potential capacityof 5 575 (DOE, 2016).
NUCLEARIt has long been a policy of the government to study all possible and potential energy resources to diversify
the economy’s energy supply mix and to provide high-quality, reliable, adequate, secure and reasonably priced
energy. As such, the present government administration is open to studying nuclear energy as an option for
power generation. In November 2016, Secretary Alfonso Cusi signed an order creating the Nuclear Energy
Programme Implementing Organisation (NEPIO). The NEPIO is headed by a steering committee with DOE
officials at the helm, whereas the DOE bureaus will create technical working groups to ensure effective andtimely implementation of its functions and responsibilities. Soon, NEPIO will come up with a roadmap for
nuclear power development in the economy. It will also study the possibility of reopening the Bataan Nuclear
Power Plant, which has been in ‘mothball’ status since 1986 (GMA News, 2016).
Advancements in nuclear energy technology and enhancements in safety and safeguard standards, basedon the lessons learned from the Fukushima incident in Japan, could encourage the economy to adopt a nuclear
energy policy in the future.

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CLIMATE CHANGE

In 2009, the government created the Climate Change Commission via the Philippine Climate Change Act of2009 (RA 9729). The Climate Change Commission serves as the policy-making body under the office of the
President and carries the status of national government agency. The Commission’s primary functions are tomonitor and evaluate programs and action plans related to climate change.
In the twenty-first session of the Conference of Parties (COP21) of the United Nations Framework on
Climate Change, the Philippines expressed an intention to reduce CO2 emissions by 70% by 2030 relative tothe level in 2000. This is relative to its BAU scenario of 2000–30, as indicated in the economy’s Individual
Nationally Determined Contributions. The abovementioned commitment is conditionally based on theavailability of financial resources, technology development and transfer, and capability building. Energy is one
source of CO2 reduction together with the transport, waste, forestry and industry sectors (UNFCCC, 2015).
N OTA B L E E N E RG Y D E V E L O P M E N T S
POWER AND RENEWABLE ENERGY

The Access to Sustainable Energy Programme (ASEP) aims to support the Philippine government in
implementing policies and programs that will generate more electricity from RE and implement innovative
approaches to increase access to electricity for the poor and unenergised households through reasonable anddisaster-resilient energy technologies. It involves capacity building and institutional support to key agencies,
such as DOE, ERC and NEA in implementing reforms in policies and programs for rural/household
electrification, RE development, and promotion of decentralised energy solutions for climate-vulnerable
communities, particularly in Visayas and Mindanao.
The PV mainstreaming is one of the projects of ASEP providing investments for rural electrification using
solar home systems for an estimated 40 500 households within the coverage areas of the participating electriccooperatives. Another project is Geographic Information System (GIS) for rural electrification and RE projects.
Some of the functions of this GIS platform are as follows:Preparing maps showing the existing electricity infrastructure and the locations of non-electrified
households in EC franchise areas;Preparing maps showing the RE potential for electricity production; andWill try to compute if possible, indicators for electrification planning (screening models).

Meanwhile, the Greening the Grid Project intends to conduct a grid integration study for variable RE to
identify the potential grid reliability concerns with the scaling of variable RE and the options for improving
system flexibility and power system balance.
In the last EWG 53 Meeting held in November 2017, in Wellington, New Zealand, the Philippines reported
their hosting of the ASEAN summit in August 2017. The Philippines also mentioned the recent executive orderissued by the President where energy projects are categorised as a national priority.
ENERGY EFFICIENCYThe DOE is the finalising the Philippine Energy Standards and Labelling Programme (PESLP), which will
significantly contribute towards achieving the target to reduce energy intensity by 40% in 2030 with 2005 asbase year. The PESLP will cover a wide range of appliances and lighting systems to include even light duty
motor vehicles. Currently, PESLP only covers room air-conditioners, split-type air-conditioners, refrigeratorswith 5–8 cubic feet storage capacity, three types of fluorescent lamps (compact fluorescent, linear and circular),and electronic ballasts. In April 2016, the DOE issued a Department Circular prescribing the guidelines forminimum energy, ‘Performance Standards and Strengthening the Philippine Energy Standards and Labelling
Programme (PESLP).’

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THE PHILIPPINESPENDING ACTIONSThe DOE has been pursuing several legislative agendas to enhance the economy’s energy policies andregulatory frameworks. The following energy bills have been filed or will be re-filed in both Houses ofCongress:Energy Efficiency and Conservation Act;

Downstream Natural Gas Industry Development Act;

Liquefied Petroleum Gas (LPG) Industry Regulation and Safety Act;Amendments to the Electric Power Industry Reform Act of 2001 or Republic Act No. 9136;



Amendments to the Petroleum Act of 1949 or Republic Act No. 387; andAmendments to Presidential Decree (PD) 87 or the Oil Exploration and Development Act of 1972.

Some of the energy bills are simply amendments to provide the existing framework and to provide
additional fiscal and non-fiscal incentives to encourage private investments.
GOOD GOVERNANCE AND TRANSPARENCY INITIATIVESIn June 205, the DOE, through technical support from the United States Agency for International
Development, established a web-based system called ‘Energy Virtual One Shared System’, a system for online
tracking of RE service contract applications and processing permits, which will eventually extend to othertechnology/resource applications in the future. The system could help facilitate and streamline businessprocesses, promote efficiency and transparency, and increase private investments.
Other government initiatives being implemented that provide data and information transparency to the
public include websites on ‘Kuryente’, ‘Wattmatters’ and ‘Langis’. The Kuryente website(www.kuryente.org.ph) offers consumers easy access to information on all distribution utilities in theirfranchise area pertaining to the components of electricity rates charged to customers, such as systems losses.
The Wattmatters website provides information on energy conservation and provides data on more efficient
appliances available in the market for the residential sector. The Langis website (www.langis.org.ph) gives
information on factors affecting pump prices of petroleum products and international price movements.

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APEC ENERGY OVERVIEW 2017

THE PHILIPPINESREFERENCES

Briones, Roehlano (2016). The Philippine economy in 2015 and prospects for 2016, Vol. XXXIV No. 1 January–
March 2016. Philippine Institute for Development Studies.
https://dirp4.pids.gov.ph/websitecms/CDN/PUBLICATIONS/pidsdrn16-1_rev.pdf. Retrieved
February 2018.
DOE (Department of Energy) (2011), National Renewable Energy Program (NREP),
https://www.doe.gov.ph/national-renewable-energy-program.
––(2015a), DOE-Energy Resource Development Bureau, Fossil Fuels Reserves.
https://www.doe.gov.ph/energy-resources.
––(2015b), https://www.doe.gov.ph/energy-resources?q=energy-resources/coal-statistics––(2015c), 2015 The Philippine Power Sector Situationer, https://www.doe.gov.ph/electric-power/powersituation-report-2015.
––(2015d). Summary of Projects as of December 2017. https://www.doe.gov.ph/renewableenergy/Summary-of-Projects?page=5.
––(2015e), 2014 Energy Sector Accomplishment Report (ESAR),
https://policy.asiapacificenergy.org/sites/default/files/Annual%20Report%20%20Energy%20Sector%20Accomplishment%20Report%202014.pdf––(2015f), 25th Electric Power Industry Reform Act (EPIRA), Implementation Status Report,
https://www.doe.gov.ph/sites/default/files/pdf/electric_power/power_industry_reforms/25th_epira_report_final.pdf.
––(2015g), Department Circular No.: 2015-06-0008 Mandating All Distribution Utilities to Undergo Competitive
Selection Process in Securing Power Supply Agreements, 19 June 2015,
https://www.doe.gov.ph/sites/default/files/pdf/issuances/dc_2015-06-0008.pdf.
––(2015h), Oil Supply/Demand Report FY 2014, https://www.doe.gov.ph/oil-supply-demand-fy-2014.
––(2016), 2016 Energy Sector Accomplishment Report.
https://www.doe.gov.ph/sites/default/files/pdf/transparency/annual_report_esar_2016.pdf.
Retrieved February 2018.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017),
http://www.egeda.ewg.apec.org/egeda/database_info/annual_data.html.
GMA News (2016), DOE to Study the Option to Use Nuclear Energy. Published 10 November 2016,
http://www.gmanetwork.com/news/story/588394/scitech/science/doe-to-study-option-to-usenuclear-energy.
Government of the Philippines (2018), https://www.gov.ph/about-the-philippines. Accessed February 2018.
Primer (2017) http://primer.com.ph/blog/2017/03/11/total-number-of-philippine-islands-is-now-7641/.
Accessed February 2018.
UNFCCC (United Nations Framework Convention on Climate Change) (2015), The Philippines Intended
Nationally Determined Contributions. Communicated to the UNFCCC on October 2015 for the 21 st
Session of Conference of Parties (COP21) in Paris in December 2015,
www4.unfccc.int/submissions/INDC/Published%20Documents/Philippines/1/Philippines%20%20Final%20INDC%20submission.pdf.
WB (World Bank) (2016), World Development Indicators, The World Bank
http://databank.worldbank.org/data/download/POP.pdf. Retrieved February 2018.

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THE PHILIPPINESUSEFUL LINKS

Asian Development Bank—www.adb.org
Climate Change Commission (CCC)—climate.gov.ph/Department of Energy, Republic of the Philippines (DOE)—www.doe.gov.ph
Department of Science and Technology (DOST)—www.dost.gov.ph/Department of Transportation and Communication (DOTC)/Land Transportation Franchising andRegulatory Board (LTFRB)—www.dotc.gov.phNational Power Corporation (NPC)—www.napocor.gov.ph/National Transmission Corporation (TransCO)—www.transco.ph/Philippine National Oil Company (PNOC)—www.pnoc.com.ph/Wholesale Electricity Spot Market (WESM)—www.wesm.ph/233

APEC ENERGY OVERVIEW 2017

RUSSIARUSSIAI N T R OD U C T I O N

Russia is the world’s largest economy, spanning over 17 million square kilometres (km2). It is the only
economy in the Asia-Pacific Economic Cooperation (APEC) region located in both Europe and Asia,
surrounded by the Arctic and the North Pacific oceans. Its territory is characterised by broad plains west of
the Urals, vast coniferous forests in Siberia, tundra along the Arctic seaboard and uplands and mountains inthe southern regions. Russia’s vast natural resources include major deposits of coal, natural gas, oil and otherminerals. Despite its land-area advantage, two-third of the economy is a zone of high-risk agriculture, owing
primarily to its continental climate, which is either too cold or too dry.
From 1993 to 2008, the Russian population declined from 148 million to 143 million: however, from2009 to 2015, the population increased to 144 million (EGEDA, 2017). The shares of urban and rural
population remained unchanged since 2009 at 74% and 26%, respectively. Russia’s average population
density is 8.4 people per km2, with most the population living in the European part of the economy (GKS,2017).
In 2009, the global financial crisis caused Russia’s gross domestic product (GDP) to decline by 7.8%
from the 2008 level. Since then, Russia’s economic growth declined from 4.5% in 2010 to -2.8% in 2015,
with an average growth rate of 3.7% for the period 2000–15. The key reasons for this economic slowdown
are structural issues with the economic system, sharp decline in the price of crude oil in international markets
and unavailable foreign capital owing to international sanctions imposed by the European Union and theUSA.
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesc, dArea (thousand km2)

17.1

Oil (million barrels)b

109.5

Population (million)

144

Gas (billion cubic metres)b32.3

GDP (2010 USD billion PPP)

3 133

Coal (million tonnes)c160

GDP (2010 USD PPP per capita)

21 743

Uranium (kilotonnes U)

342

Note: Data from Nuclear Energy Agency (NEA) is used for uranium reserves recoverable at a production cost of lessthan 260 USD per kg.
Sources: a GKS (2017); b EGEDA (2017); c BP (2017); d NEA (2016).

Russia’s major industries include oil and gas production, petroleum refining, mining, iron and steel,chemicals and machinery. The economy’s energy sector accounts for 27% of the GDP, 63% of the totalexports and 27% of the total capital investment.
In terms of proven reserves, as of 2016, Russia holds 17% of the world’s gas, 6.4% oil, 14% coal(BP, 2017) and about 5.8% of its reasonably assured resources of uranium (NEA, 2016).
The proven natural gas reserves in Russia, estimated at 32 trillion cubic metres, should be adequate tomeet both the domestic market and export demands for another 55 years.
As of 2017, Russia is estimated to have 36 years’ worth of oil supply at current production rates, and57 years’ worth if yet-to-be explored fields are included. Out of 3 030 known oil fields, 1 926 produce oil,
663 are under assessment and 441 remained to be auctioned for exploration (MNRE, 2017). In 2017, 75
new oil and gas fields were discovered with 550 million tonnes (Mt) of crude oil and 890 billion cubic metres(bcm) of natural gas reserves (MNRE, 2018).
At the current rates of domestic coal consumption, the reserves should be sufficient for over 800 years.

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RUSSIAThe refining industry in Russia includes about 30 major refineries with a total capacity for primaryprocessing of about 277 Mt of crude oil per year (ME, 2016).
Russia has the world’s largest and oldest district heating system with centralised heat production anddistribution networks in most major cities. The system has a high number of combined heat and power(CHP) installations. Due to the obsolescence of this heating infrastructure, 8.9% of heating energy is lost
during distribution, and this indicator is growing (ME, 2018b). However, according to expert estimates, aconsiderable amount of energy can be saved by adopting relatively accessible technologies and cost-effectiveenergy saving practices.
Russia’s energy sector is very important to global energy security. The economy is the world’s largest
exporter of energy overall, the largest exporter of natural gas and the second-largest exporter of crude oil(BP, 2017). Furthermore, Russian-labelled nuclear fuel is used at 75 commercial reactors (17% of the global
market) and provides 36% of the world’s uranium enrichment services (Rosatom, 2017).
In 2016, exports of coal, crude oil, petroleum products and natural gas accounted for 55.9% of thetotal exports of the economy by value. Russia holds 45% of world’s uranium enrichment capacity (NEA,
2015), and actively exports the product. Russia plays a significant role in the world’s energy markets. It
accounts for 19% of global natural gas trade, 13% of crude oil trade, 9% of petroleum products trade, and
12% of coal trade (BP, 2017).
E N E R G Y S U P P L Y A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Russia’s total primary energy supply in 2015 was 710 million tonnes of oil equivalent (Mtoe), comprising
natural gas (51%), crude oil and petroleum products (22%), coal (16%), and others, including nuclear andhydro (11%) (EGEDA, 2017).
By destination, most of Russia’s total energy exports are directed to Western and Eastern Europe,
including the Commonwealth of Independent States (CIS). Since 2008, Russia has been actively diversifying
its export routes towards the Asia-pacific region, aiming to deliver oil, natural gas and coal to China; Japan;
Korea and South-East Asia.
Russia produced 548 Mt of crude oil and gas condensate in 2016 (ME, 2017a). The oil heartland is the
Ural Federal district, which accounts for over half of the total oil production. In that year, refineries
consumed 281 Mt of crude oil as feedstock, producing 39 Mt of gasoline, 76 Mt of diesel, 75 Mt of fuel oiland 10 Mt of kerosene. Crude oil exports increased from 245 Mt in 2015 to 255 Mt in 2016 and exports ofpetroleum products reached 156 Mt in 2016 (GKS, 2017).
After three years of decline, natural gas production increased from 634 bcm in 2015 to 640 bcm in2016 (ME, 2017h). Exports of natural gas steadily increased from 174 bcm in 2014 to 199 bcm in 2016
(GKS, 2017) or 31% of the production, including 11 Mt of liquefied natural gas (LNG) exports (ME, 2017h).
In 2016, Russia produced 385 Mt of coal, an increase of 3.1% from 2015. In 2015, coal exports reached
151 Mt, declining by 0.4% from the 2014 level (ME, 2017i). From 2000 to 2015, the share of coal for export
increased from 17% to 39%, despite the fact that the main coal-producing areas (the Kuznetsky andKansko–Achinsky basins) are landlocked in the south of Siberia, some 4 000–6 000 km from the nearest
coal-shipping terminal for the Atlantic/Pacific markets.

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Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

1 334 184

Industry sector

124 166

Total power generation

Net imports and others–601 923

Transport sector

93 863

Thermal

698 401

Total primary energy supply

709 730

Other sectors

159 553

Hydro

167 993Coal

116 402

Non-energy

79 302

Nuclear195 470

Oil

156 736

Final energy consumption*

377 582

Others3 759

Gas

364 149

Coal

12 060

Renewables

17 414

Oil

88 481Others55 029Gas

108 291

Renewables
Electricity and others

1 065 623

2 045
166 705

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This isdifferent from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid
waste used in power plants is assumed to be comprising renewables.

Electricity production reached 1 066 terawatt-hours in 2015, of which 66% was from thermal power
plants, 16% from hydropower and 18% from nuclear energy. Russia has significant renewable energy
potential, such as hydro and biomass in Siberia, wind along its Arctic and Pacific shores and geothermal in
Kamchatka and the Kuril Islands.
FINAL ENERGY CONSUMPTION

In 2015, the total final consumption in Russia was 457 Mtoe, a decline of 0.4% compared to 2015. By sector,
industry, transport and others accounted for 27%, 21% and 35%, respectively. The share of non-energy was
17%. By energy source, coal accounted for 3.2% of the final energy consumption (excluding non-energy),
oil and petroleum products at 23%, natural gas at 29%, electricity and others (including heat) at 44% andrenewables at 0.5%.
The traditional energy-intensive industrial structure has been one of the major drivers of economic
development in Russia. State and regional energy efficiency programmes aim to reduce overall energy
intensity to 40% by 2020 compared to 2007. The government is implementing policies designed to attract
investment in energy efficiency and realise Russia’s large savings potential.
ENERGY INTENSITY ANALYSISThe 2.4% growth of Russia’s GDP in PPP in 2015 coincided with a 0.8% increase in the economy’s primaryenergy intensity at 227 tonnes of oil equivalent per million USD (toe/million USD). For the total final
consumption intensity, the indicator grew by 2.5% from the 2014 level of 142 toe/million USD to
146 toe/million USD in 2015. For final energy intensity excluding non-energy, the indicator grew by 1.7%
from 119 toe/million USD to 121 toe/million USD in the same period.

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Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)

Total primary energy supply

225

227

2014 vs 2015
0.8

Total final consumption

142

146

2.5

Final energy consumption excl. non-energy

119

121

1.7

Source: EGEDA (2017) (data collected in September 2017).
RENEWABLE ENERGY SHARE ANALYSIS

In 2015, energy consumption of modern renewables in Russia was 12 511 ktoe, or 2.7% of the economy’s
final energy consumption. This is lower than 2.9% noted in 2014, mainly caused by a decline in energy
generated using hydropower. Use of traditional biomass increased by 4.1% compared to 2014, mainly
attributed to the residential sector.
Table 4: Renewable energy share analysis, 2014 vs 2015

382 049377 582

Change (%)
2014 vs 2015
–1.2

368 938365 071–1.0

Traditional biomass*

2 053

2 137

4.1

Modern renewables*

11 05810 374–6.2

Share of modern renewables in final energy
consumption (%)

2.9%

2.7%

–5.1%

2014
Final energy consumption (ktoe)
Non-renewables (Fossils and others)

2015

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels
are typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member
economies, including those that are members of the Organisation for Economic Cooperation and Development(OECD) and those that are not (Non-OECD). All other renewables (hydro, geothermal, and so on) including biogas
and wood pellets are considered modern renewables, although data on wood pellets are limited.
P OL I C Y OV E R V I E W
ENERGY POLICY FRAMEWORK

Under Russia’s ‘Energy Strategy 2030’, adopted in 2009, its key objective is to use nature’s energy resourcesin the most efficient way and expand the energy sector’s potential for stable economic growth, improvementin the quality of people’s lives and strengthening of the economy’s foreign trade (IES, 2010). The strategy
sets a policy framework within which more detailed industry-oriented medium-term and short-term
programmes are developed.
As of early 2018, the government continued its work on the new ‘Energy Strategy 2035’, but thestrategic objective of Russia’s external energy policy is unlikely to change. The objectives will continue to be
the use of Russia’s energy potential to effectively maximise its integration into the world’s energy markets,
strengthen Russia’s position in these markets and maximise the benefits of energy resources to the economy(ME, 2017f).
To achieve these objectives, the government is planning to implement several measures to improve
the security of domestic energy supply and energy export obligations and to make efficiency improvements
along the entire energy supply chain. This includes the development of new hydrocarbon provinces inremote areas and offshore. It will also include the rehabilitation, modernisation and development of energy
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RUSSIA

infrastructure, including the construction of additional trunk oil and gas pipelines, to enhance the economy’senergy export capacity. Furthermore, diversification of export delivery markets will be the key to better
integrating Russia into the world energy markets.
Russia’s nuclear energy industry remains a priority for the economy’s development, despite the nuclear
accident at Fukushima, Japan in 2011. The share of domestic nuclear-power generation is expected tocontinue increasing, with many units being constructed abroad. Russia intends to remain a key player in thepractical implementation of improved nuclear fuel technology. Despite the existing programmes forrenewable energy development outlined in the Energy Strategy 2030, electricity generated from renewableenergy is too expensive to compete with traditional sources, i.e. fossil fuels (ME, 2018c).
Energy Strategy 2030 calls for a 40% reduction in the energy intensity of the economy by 2030 (IES,2010). Reducing Russia’s relatively high energy intensity needs to be one of the main objectives of theRussian energy policy in order to improve the competitiveness of the domestic industry in the global market
and stimulate Russia’s economic development.
One of the key measures in the Energy Strategy 2030 is the development of energy market institutions,such as fair pricing mechanisms and transparent trading principles, while ensuring the availability of a
sufficient energy transportation infrastructure. State participation in energy sector development will mainlycomprise supporting innovative developments in the energy sector as well as providing a stable institutional
environment for effective functioning of the sector (IES, 2010).
Under the general framework of the Energy Strategy 2030, medium- and long-term programmes andindustry-wide schemes are being developed. These include the Federal Programme for Development of the
Nuclear Industry up to 2015, approved in 2006, and the general scheme of electric infrastructuredevelopment—a scheme relating to electricity network infrastructure and electricity plant locations—up to2020, approved in 2008 and later extended to 2030.
In April 2011, a general scheme for development of the oil industry up to 2020 was approved. This
provides for the comprehensive development of the oil sector, which includes exploration and utilisation of
associated petroleum gas, crude oil and petroleum products, crude oil refining, and transportation
infrastructure.
The general scheme for the development of the gas industry up to 2030 was reviewed and approvedin October 2010. The document represents a complex project, which defines a path for Russian’s long-term
gas industry development. This strategic document covers all components of the gas industry: exploration,
drilling, production, storage and transportation to consumers of hydrocarbons, and refined products.
In 2007, the federal government approved the East Gas Programme to develop the natural gas fields
and build extensive trunk gas pipelines in Eastern Siberia and the Russian Far East up to 2030. The
programme also includes building export pipelines to the East Asian economies. Gazprom, the state gas
monopoly and the owner of the economy-wide gas pipeline system, is the coordinator for the programme
and is responsible for conducting long-term sales contracts for natural gas deliveries.
In 2011, the Ministry of Energy of the Russian Federation forwarded the second phase development
plan up to 2030 for the economy’s gas and petrochemical industry to the Russian Government. This includes
an updated general plan for the development of key oil and gas investment projects; an updated programme
for the division of petrochemical capacities into six clusters, including pipeline transportation projects;
projects to build new facilities and upgrade existing ones for the primary processing (pyrolysis) and further
processing of raw materials; and activities for the scientific and educational support of the industry.
In January 2012, the Government Presidium of Russia approved a long-term programme fordeveloping the coal industry up to 2030. This document specifies the basic provisions of the energy strategy
2030 relating to the coal industry. The main task of the programme is to realise potential competitive
advantages for Russian coal companies, while implementing the government’s long-term energy policy.
Additionally, the mid-term Scheme on the Unified Energy System Development is a tool to coordinate
federal, regional and local governments with private businesses and industry regulators. The Scheme is
updated annually and serves as a seven-year outlook for generation and transmission line projects (ME,2017g). It includes an outlook for electricity consumption by region, maximum loads, generation capacity
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reserves, power exchange, retirement of old facilities, maintenance, retrofitting and commissioning of new
generation and transmission facilities with more than 5 megawatts (MW) capacity/110 kilovolts (kV) andhigher voltage, respectively.
LAWS AND AUTHORITIESThe main federal legislation on specific energy-related industries include laws in the following areas: subsoils(1992), functioning of the power industry (2003), power industry (2003), natural monopolies (1995),
production sharing agreements (1995), energy conservation and energy efficiency increases (2009), gas
supplies (1999), nuclear energy (1995) and heat supply (2010). The latter is the logical extension of the powerindustry law, because of the large share of CHPs, where electricity and commercial heat are produced
simultaneously.
As a rule, the Ministry of Energy of the Russian Federation is responsible for issuing regulations,
instructions and so on to enforce smooth implementation of the basic energy laws and to coordinate current
economic development with the long-term energy policy, except for the nuclear power industry. Other
major government institutions actively participate in the development and implementation of the regulatory
framework regarding the production, supply, consumption, exports and imports of energy. These include
the Ministry of Natural Resources and Environment of the Russian Federation; Federal Environmental,
Industrial and Nuclear Supervision Service; Ministry of Industry and Trade of the Russian Federation;
Ministry of Economic Development of the Russian Federation; Federal Agency on Technical Regulatingand Metrology; Federal Antimonopoly Service; Federal Customs Service and Federal Tariff Service.
ENERGY SECURITY

Russia considers issues related to energy security a global phenomenon. Owing to increasing
interdependence between energy exporters, importers and transition economies, improving international
relations is considered an effective mechanism for improving international energy security. The key
approach is to coordinate the actions of energy exporters and importers in emergency and/or crisis
situations.
To facilitate international energy security cooperation, Russia has made a proposal to develop a
Convention on International Energy Security that would cover all aspects of global energy cooperation,
considering the balance of interests of all actors in the international market. The infrastructure projects,
including new oil and gas export trunk lines from Russia to its European and Asian markets, provide a solid
contribution in improving the global energy security. The development of an international infrastructure forreliable maintenance of the nuclear fuel cycle, under strict International Atomic Energy Agency (IAEA)
supervision, is another Russian contribution towards improving global energy security.
ENERGY MARKETSMARKET LIBERALISATION

One of the main issues in Russia is the gradual liberalisation of the natural gas and electricity markets. Coaland petroleum prices have already been fully liberalised. The government controls tariff-setting for natural
monopolies—power transmission lines and pipelines (gas, crude oil, petroleum products transportation
systems and heat supply for the residential and commercial sectors) as well as energy tariffs in remote andisolated areas. The authorities are authorised to set maximum regional tariffs for natural gas, electricity andcentralised heat supply. One of Russia’s objectives in the Energy Strategy 2030 is to complete the full
liberalisation of domestic energy markets, where at least 20% of the energy is expected to be traded oncommodity exchanges.
In 2006, the simultaneous liberalisation of natural gas and electricity prices by 2011 was approved;
however, the implementation was delayed and as of 2017, the electricity tariff for residential sector is still
regulated by the government. The Federal Antimonopoly Service is planning to launch the natural gas priceliberalisation programme, except for industry, in three pilot regions in 2017.
The oil market in Russia has been deregulated since the 1990s, but crude oil and petroleum trading are
not based on commodity exchanges. Most crude oil in the domestic market is traded on a term basis, inwhich prices are linked to international benchmarks. Petroleum is traded in irregular tenders, which allows
producers to control the market. Regional petroleum storage plays an important role in establishing fuel239

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markets. The government intends to make up to 25% of the compulsory purchases of the government’s
petroleum products supply through commodity exchanges, such as the St. Petersburg Oil Exchange
established in late 2006. The Federal Antimonopoly Service has an element of control over oil and gas prices
through its role in monitoring the market share of sellers, but it has no responsibility for regulating prices.
The government’s control over coal pricing was removed in the early 1990s, and the coal market has
since been liberalised, like the crude oil and petroleum product markets.
The transition to transparent, free-trading pricing mechanisms in domestic markets was originallyscheduled to be completed in 2011, but the transition period has since been extended. The government will
maintain control over the residential and commercial energy tariffs to eliminate cross-subsidies gradually.
OIL AND GAS

Russia’s oil and gas industry was privatised in the 1990s. However, the government retained control overmajor oil and gas companies and crude oil and petroleum trunk pipelines, and owns 73% of the shares of
Russia’s biggest gas company, Gazprom.
As of 2015, the oil industry in Russia comprised 10 vertically integrated companies (VICs) constituting
87% of the crude oil output and 182 small-scale independent enterprises, along with operators of three
production-sharing agreements. The refining sector comprises 28 large VICs, nine companies not owned by
VIC and 34 small refineries with the total refining capacity of 312 Mt of crude oil per year.
The shift towards Euro-V emission standards has encouraged significant investment into the refining
industry. Currently, only limited use of fuels non-compliant with this standard is allowed. Despite a small
year-on-year decline in crude oil throughput by –0.8%, the depth of refining has increased from 74% to
79% in the same period. New installations and modernisation of existing equipment are expected to help
increase the yield to 81%.
The federal government remains the key shareholder in the economy’s gas monopoly, Gazprom, whichin 2014 extracted 67% of the natural gas in Russia and is the owner of the economy-wide gas pipeline system.
The remainder of the Russian natural gas supply comes from independent producers (7.3%), NOVATEK(8.4%), joint operators (4.3%) and VICs (13%).
In 2017, the Ministry of Energy in cooperation with the Ministry of Finance, with active participationof the oil sector, introduced an oil excess profit tax. This new tax is designed to help sustain existing or
attract new investment in oil mining. This is especially important for Russia as the production of its main
oil-producing province, Western Siberia, is declining, from nearly 308 Mt per annum in 2010 to nearly 286
Mt oil per annum in 2016 (ME, 2017b).
COAL

The Russian coal sector was restructured in the 1990s, and foreign participation in the sector is practicallyabsent. Unlike the oil and gas sector, the coal industry has no large state-controlled companies.
Industry development is based two-thirds on equity and one-third on loans. In recent years, there has
been an active renewal of the fixed assets of the coal industry. There are no policy restrictions on coalexports; however, the high transportation cost of coal lowers its competitiveness in external markets. Coalis the single largest commodity transported by rail, accounting for nearly 30% of its total freight volume.
Steam coal accounts for 78% of total coal production.
In 2014, the government approved the coal industry development programme until 2030. Its primaryobjective is to ensure that domestic coal companies are reliable suppliers to the domestic market and develop
their exporting potential (ME, 2017d).
As of the end of 2016, 181 coal enterprises were operational in the Russian coal industry (66 minesand 115 open-pit mines), with a total annual production capacity of 425 Mt per annum. Coal processing is
performed by 65 processing plants and mechanical installations (ME, 2017c).
ELECTRICITY

Russia started restructuring its power industry in 2000. Federal laws and government decrees identified themain principles for the future functioning of the power industry under competitive conditions. All thermal
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generation and regional power distribution companies were privatised before July 2008. From July 2008, thegeneration and transmission assets in Russia were separated under binding regulations. Generation assets
were consolidated into interregional companies of two types: seven wholesale thermal power plant
generation companies (WGCs) and 14 territorial generation companies (TGCs). Six thermal WGCs wereconstructed according to extraterritorial principles along with one state-owned holding company, RusHydro,
which manages 53 hydropower plants. TGCs manage facilities in the neighbouring regions. The initial designof the WGCs provided them with roughly equal starting conditions in the market, with respect to installedcapacity, asset value and average equipment. Each WGC has power plants located in different regions of
Russia to prevent possible monopoly abuse.
Backbone transmission lines are assigned to the Federal Grid Company, whereas distribution grids are
owned and operated by 11 interregional distribution grid companies. The Federal Antimonopoly Service is
responsible for monitoring the long-distance power transportation market, whose threshold is less than 20%of the transmission line capacity per company. The wholesale power market infrastructure includes thefollowing organisations:

Non-profit Partnership Administrator of Trading System;



System Operator–Central Dispatch Administration of the Unified Energy System; andFederal Grid Company of the Unified Energy System.

The Non-Commercial Partnership, Administrator of Trading System of the Wholesale Power Market(NP ATS), was established in November 2001. The main objectives of NP ATS are to organise trade andarrange financial payments in the wholesale electricity and power markets, increase the efficiency of power
generation and consumption, and protect the interests of both buyers and suppliers. NP ATS provides
infrastructure services, which are related to organisation of trade, the wholesale power market, ensuring theexecution and closing of transactions, and the fulfilment of mutual obligations. The System Operator, with
100% state ownership, exercises technological control within the power grids and provides dispatching
services to wholesale market participants. The Federal Grid Company, established in 2002, with 78% state
control, owns and operates the transmission lines, provides consistent technological management and is
responsible for the reliability of power transmission services.
The free electricity trading market (one-day forward) was launched in November 2003, within theframework of the Federal Wholesale Electricity Market (FOREM). In September 2006, the regulated sectorof the wholesale market was replaced by a system of contracts to be concluded between the buyers andsellers of electricity and electric power. In the FOREM, power generators and importers sell electricity andpower to guarantor suppliers and distribution companies as well as to large consumers and exporters. In the
distribution market, guarantor suppliers and distribution companies sell electricity and power to end-use
consumers in the residential, commercial and industrial sectors.
Since 2008, the share of tariffs established by the regulatory asset base methodology for distribution
grids has been increasing and is expected to become the major method for calculating middle-term tariffs.
The methodology is transparent and provides incentives for investors to rehabilitate and improve theoperations of the energy service companies.
HEAT SUPPLY

Residential and commercial heat supplies have important social implications and are a major concern for
local governments in Russia. Historically, the heat-supply industry was subsidised by local budgets and thus
has scope for considerable efficiency improvements. The Law on Heat Supply introduced in 2010 was
designed to create investment opportunities, minimise energy losses and subsidies and provide businessincentives.
In July, 2017, the government adopted changes to the above law, now allowing regional and municipal
authorities to establish localised heat-supply markets. In these liberalised markets, however, the government
still regulates the maximum heat price for the final consumer, commonly referred to as ‘alternative boiler
house price’ (ME, 2017e).

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NUCLEAR

Russia’s nuclear industry restructuring started in 2001, when the state-owned company Rosatom took overall civil reactors, including those under construction, and their related infrastructure. In 2007, the new Law
on Nuclear Industry was adopted, which provided a legal framework for industry restructuring by separating
military and civil facilities and by introducing regulations for nuclear materials management. Russian
business entities are now allowed to hold civil-grade nuclear materials, but they still fall under state control.
In April 2007, a single, vertically integrated, state-owned nuclear energy company was established. The
operations of this new corporation, AtomEnergoProm (AEP), include uranium production, engineering,
design, reactor construction, power generation and research facilities. AEP holds a significant share of theworld’s enriched uranium and nuclear fuel supply, has 24 GW of existing Russian nuclear energy plants andmanages the construction of 14 reactors. There are seven reactors under construction in Russia, including
one floating-type unit to power remote areas and seven reactors in four Asian and European countries. AEP
provides the full production cycle of nuclear energy engineering, from uranium extraction to nuclear fuelservices to nuclear energy plant construction and electricity production. The company has up to 16% of theworld’s market for new nuclear energy plant construction and is affiliated with Tenex (40% share of theworld’s uranium enrichment services market), TVEL (17% share of the world’s nuclear fuel market) and
Atomredmetzoloto (9% share of the world’s uranium mining).
TRANSPORT

Russia’s economy faces challenges caused by underdevelopment of its transport infrastructure. The current
condition of Russian airports and air-transport facilities provides insufficient capacity and slows theperformance of air-transportation services. Further modernisation of air and rail transport is underway inconnection with Russia hosting the 2018 Football World Cup and the 2020 World Expo.
The total length of Russian public roads in 2015 was 1 480 817 km, 71% of which are paved (Rosstat,2017). The economy has just over 30 000 km of high-speed divided highways connecting big cities. Further
development of highways will be necessary to connect big cities.
Russia has a state railway system with a total length of 86 251 km, but only few cities have high-speed
rail service. Nevertheless, extensive urban and regional bus services are available throughout Russia, andsubway systems operate in seven cities. The recent key developments in rail freight and passenger
transportation are as follows:

Development of Ust–Luga freight rail terminal and associated shipping terminal; its throughput
exceeded 100 Mt in 2017 (Morport, 2017),



Freight rolling stock renovation plans announced by Russian Railways company (RZD, 2018),
this includes the construction of an LNG locomotive, specifically for mining operations in nonelectrified areas (RZD-expo, 2017),



Renovation of suburban and regional passenger trains, which includes upgrade of the current
rolling stock with new stock with high local content. A significant project is the launch of Moscow
Central Ring, a train service integrated with the city’s underground and surface transportation
systems.

Russia’s pipeline transport is underdeveloped relative to the potential oil and gas supply. The total
length of the pipeline system in the economy was 251 764 km in 2015, of which 71% is gas pipeline, 22%
oil pipeline and the remainder is petroleum products pipeline.
FISCAL REGIME AND INVESTMENT

In 2007, dozens of oil and gas fields were decreed as ‘strategic’ fields. The strategic status makes thehydrocarbon deposits inaccessible to foreign companies unless they establish joint project operations with
Russian companies. Under the current regulations, the strategic status has been applied to oilfields withreserves exceeding 70 Mt and gas fields with reserves exceeding 50 bcm. In March, 2009, regulations wereadopted to compensate costs associated with the discovery and exploration of deposits under exploration
licenses, the further development of which is prohibited because of their strategic status.

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Beginning in January 2009, tax holidays from the mineral extraction tax for crude oil production in
East Siberia were extended to areas north of the Arctic Circle, the Azov Sea, the Caspian Sea and the Nenetsk
and Yamal regions. In addition to the existing tax reductions for East Siberian oil, this enables thedevelopment of new capital-intensive projects in remote areas that lack energy infrastructure. From 1
January 2010, zero export duty was introduced for crude oil extracted from East Siberia oilfields to maintaina stable market for Russian crude exported eastward to the Asia-Pacific region.
A draft plan for a new tax regime was prepared in 2011 as a part of the development of the new Law
on Oil. On 1 October 2011, a new tax regime for the oil industry called the ‘60–66’ came into force in Russia.
Under these rules, the duty on oil exports decreased by 7.4% to USD 411 per tonne, and fees for light andheavy petroleum products were set at 66% duty on crude oil. For several fields in Eastern Siberia and theNorth Caspian, a preferential export duty was enacted, which, as of October 2011, was set at USD 204 per
tonne. A reduced duty on crude oil was achieved by changing the formula for calculating it. According to
the norms of the ‘60–66’, duty on crude oil was assessed at 65% and 60% of the difference between themarket price and standard price of oil at a rate of USD 182 per tonne.
The size of the duty on exports of gasoline is currently set at 90% of the duty on crude oil. Before May
2011, the duty on export of gasoline was 60% of the duty on oil, but because of the sharp rise in domestic
prices and gasoline shortages in some regions, it was increased to 90%. It is believed that such new fees willallow oil companies to obtain additional funds for exploring new fields and will thereby increase current oil
production. In addition, the unification of tariffs on export of petroleum products at 66% will make exports
less competitive for dark petroleum products and more profitable for light petroleum products; it will also
encourage companies to increase the refining depth at their existing plants.
To facilitate coal exports, rare subsidies to the coal industry are provided under the railway’s cargotariff regulations for some export routes.
ENERGY EFFICIENCY

The energy intensity of the Russian economy is considerably higher than those of most developed
economies. The introduction of energy efficiency (EE) measures is estimated to save over 300 Mtoe,
including more than 160 Mtoe from energy extraction, transformation and transportation.
EE has become a critical factor in the government’s energy policy since 2008, when a presidential
decree set a target to reduce the energy intensity of Russia’s GDP by 40% by 2020, compared with 2005.
Improving EE and energy savings has become a priority area of the Energy Strategy 2030.
On 23 November 2009, the federal government adopted the Law on Energy Conservation andIncrease of Energy Efficiency, which took effect on 1 August 2010. To supplement and make the new EE
law more effective, about 40 sub-laws amending some existing laws and technical regulations were drafted.
The federal law sets a legal framework and targets the use of energy resources in Russia by promoting therational use of energy resources and alternative fuel resources for electricity and heat generation. The law
introduces various measures to improve EE and energy conservation across all sectors of the economy. A
few of these measures are as follows:

EE standards for equipment and buildings, including mandatory energy passports;

EE labelling of goods and the compulsory commercial inventory of energy resources;

Improvements in EE monitoring, focusing on mandatory energy audits and the compulsory
installation of metering systems;

Creating a single and unified inter-agency information network and analytical EE system; and

Other measures to help achieve energy savings (promoting energy service contracts, prohibiting
incandescent light bulbs, introducing incentives and tax benefits for Russia’s heavy industries toreplace highly energy-inefficient machinery and equipment, and so on).

In accordance with the EE federal law and the programme, all regions are required to prepare theirown respective regional programmes on EE improvements. Regional governments and the federal
government will jointly finance the implementation of these programmes.

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RUSSIAOn 22 December 2009, the government established the Russian Energy Agency, which has 70 regional
branches, with the Ministry of Energy of the Russian Federation. Its key tasks focus on operating the federal
EE and energy-saving information system and on administering, monitoring and coordinating efforts for
effective implementation of the EE law, the Federal Programme and other measures for improving EE andenergy conservation efforts in the budgetary, power generation, industrial and residential sectors of Russia’s
economy. In addition to these measures and policies for strengthening the EE legal framework, the federal
government launched the following six pilot presidential energy efficient projects in several regions:

Metering (installing metering devices and automation);

EE in the government sector (piloting energy performance contracting in schools and publicbuildings);

Energy-efficient districts (targeting the residential sector);Energy-efficient lighting (replacing street lighting and other measures);

Small-scale cogeneration; andNew energy sources (renewable and other non-carbon energy resources).

Upon their successful completion, these projects are expected to be implemented across all regions.
In addition, the technical potential exists to save almost half of Russia’s primary energy consumption
through energy conservation (ME, 2015). However, a major impediment for businesses to improve their
EE is the absence of appropriate financial mechanisms.
RENEWABLE ENERGY

Russia’s technical potential for renewable energy (RE), excluding large hydro, is estimated at 4 400 Mtoe per
year, or almost eight times more than Russia’s current total final consumption. However, the economic
potential is much smaller (about 240 Mtoe per year, less than 1% of the total electricity production). In 2010,
the installed RE capacity totalled 2 200 MW, of which less than 25 MW was hydro.
The government’s policy goals and mechanisms to promote RE were introduced in January 2009
through the federal government order, ‘The Basic Directions of a State Policy of Renewable Energy
Utilisation up to 2020’. The major mechanisms to increase the share of renewables are feed-in tariffs andsubsidies for grid connection. The government is expected to develop regulations for feed-in tariffs and gridconnection subsidies for the compulsory share of RE in the wholesale market to be purchased by electricity
consumers and for bringing together RE generators, transmission lines and guarantor suppliers of energy.
By 2030, Russia is expected to generate from 80 to 100 billion kWh of RE, excluding large hydro, or roughly
4–6% of the economy’s total generation.
In October 2010, the government published a ruling on federal subsidies for connecting renewableenergy generators to the power grid that would encourage ‘green’ energy production in Russia. Conditionsof the ruling include that the nominal capacity of single RE generators should not exceed 25 MW, and thatowners should not be under bankruptcy proceedings. This ruling paves the way for financial mechanisms
for RE.
NUCLEAR ENERGY

Russia holds important stakes in the international nuclear fuel market. Tenex, the state company responsible
for the nuclear fuel cycle business, supplies all the Russian, Commonwealth Independent States and Eastern
European nuclear reactors. In addition, Tenex meets 40% of the nuclear fuel requirements of the UnitedStates, 23% of Western Europe and 16% of the Asia-Pacific region.
In the Global Nuclear Infrastructure Initiative, announced in early 2006, Russia proposed to hostseveral types of international nuclear fuel cycle service centres as joint ventures with other economies. The
centres will be strictly controlled by the IAEA. Their most important roles will be uranium enrichment,
reprocessing and storage of used nuclear fuel, along with standardisation, uniform safeguard practices,training and certification, and research and development.
In 2007, the International Uranium Enrichment Centre (IUEC) was established in Angarsk, Siberia, as
a joint venture between Russia and Kazakhstan, but open to other interested parties. Ukraine joined the244

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RUSSIAIUEC in 2010. The IUEC’s objective is to provide low-enriched uranium (LEU) to those economies
interested in nuclear energy development and ready to comply with the IAEA’s non-proliferation
regulations. The existing enrichment plant in Angarsk will be used to serve the IUEC.
In February 2007, the IUEC was certified by the IAEA for international operations. A programme for
the IUEC’s expansion at Angarsk by 2015 was developed. The programme includes three phases:Use part of the existing capacity in cooperation with Kazatomprom under the IAEA’s
supervision;

Expand capacity with funding from new partners; andInternationalise fully with the involvement of many customer economies under the IAEA’s
auspices.

Russia also created a fuel bank with guaranteed reserves of low-enriched uranium hexafluoride—
equivalent to two 1 000 MW reactor loads—at the IUEC available under the IAEA’s control. As of 2017,
the storage capacity is 120 tonnes of uranium metal as UF6, from precisely 2.00% to precisely 4.95%
enrichment (IUEC, 2017).
Nuclear safety is a major concern for world energy development, which has become a key agenda item
following the Fukushima accident in Japan. Russia has adopted a ‘closed’ fuel cycle, which includes spent
nuclear fuel processing and the mandatory return of fissionable nuclear materials to the fuel cycle. To
provide the legal framework for managing spent nuclear fuel and radioactive waste, the laws onenvironmental protection and the use of nuclear energy were amended in June 2010. The expired contracts
for depleted uranium hexafluoride enrichment/conversion have not been extended since 2007.
Rosatom’s long-term strategy up to 2050 involves moving to inherently safe nuclear energy plants,
using fast reactors with a closed fuel cycle and mixed oxide fuel. In the period 2020–25, fast neutron reactors
are expected to play an increasing role in Russia. The improved design will lead to an extended operating
life of up to 60 years, a shorter construction period of up to 46 months and operating costs at less thanRUB 1 per kilowatt-hour (kWh). After the successful commissioning of an 800 MW fast breeding reactor(UNIT 4, Beloyarskaya Nuclear Power Plant), Rosatom is planning to construct a 1 200 MW unit after 2020.
Further development of this technology is expected to broaden the range of acceptable fuels as well as
reduce the amount of toxic nuclear waste by establishing a closed nuclear fuel cycle (Rosatom, 2018).
The prospects for future international cooperation in the nuclear energy industry are promising; theconstruction of 35 reactors in 15 economies is in the pipeline, and contracts have been signed for 19 reactors
in seven economies.
Russia has chosen three core reactor technologies for nuclear energy development for the next 20 to
25 years:

Water–water energetic reactors (VVER) and their modification and advanced development;

Sodium fast neutron reactors; andHigh-temperature helium reactors.
CLIMATE CHANGE

Russia’s key environmental and climate policy has been outlined in the Climate Doctrine (Kremlin, 2009)
and Fundamentals of state policy in the field of environmental development of the Russian Federation forthe period until 2030 (Kremlin, 2012) and implemented in the State Environmental Protection Programme
for the period 2012–20201. In 2017, the Year of Ecology in Russia, the President signed the ‘Strategy for
Environmental Protection in Russia until 2025’. This document includes the assessment of the status of andthreats to the environment and highlights the key government targets, indicators and methods ofenvironmental monitoring (Pravo, 2017).

1 The State Environmental Protection Programme does not include the indicators related to GHG emission.

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Russia is considered the world’s largest potential host for ‘joint implementation’ projects under the
Kyoto Protocol. In May 2007, the economy adopted procedures for the approval and verification of Russiabased joint implementation GHG reduction projects. Responsibilities were assigned for establishing andmaintaining the Registry of Carbon Units, which paved way for the implementation of GHG mitigation
projects in Russia.
At the Conference of Parties 15 in December 2009, Russia pledged to reduce its GHG emissions by
25% from the 1990 level by 2020, a figure comparable to the targets of the European Union member states
and a 50% decrease from the 1990 level by 2050. These emission reductions are contingent on the following
conditions: appropriate 1) accounting of the contribution of emissions reductions from Russia’s forestry
activities will be introduced and 2) all major emitters will undertake legally binding obligations to reduce
GHG emissions caused by human activities.
In December 2012, Russia refused to endorse extended pollution limits under UN COP3 at the UN
climate change conference in Doha, because the biggest polluters, US; China; and India, have not joined it.
In April 2016, the Russian Government signed a directive approving the Paris Agreement of theConference of the Parties to the UNFCCC (UN Framework Convention on Climate Change) (RG, 2016)
also known as UN COP21. Russia’s INDC is ‘Limiting anthropogenic greenhouse gases in Russia to 70–
75% of 1990 levels by the year 2030 might be a long-term indicator, subject to the maximum possible
account of absorbing capacity of forests (UNFCCC, 2015).
NOTABLE ENERGY DEVEL OPMENTS
ENERGY POLICY

EnergyNET roadmap, adopted in late 2016, is a part of Russia’s Technological Initiative (NTI) and it
highlights a number of objectives for Russia’s energy industry until 2035. This includes target indicators for
Russia’s share of global markets, engineering and software solutions, educational facilities, pilot projects andtesting facilities for intelligent distribution networks.
POWER MARKET DEVELOPMENT

The Ministry of Energy of the Russian Federation presented concepts for a programme of power sector
modernisation up to 2020. The central theme of this modernisation is to introduce new technologies (bothdomestic and imported), increasing the reliability of electricity supply.
OIL AND GAS DEVELOPMENT

The Ministry of Energy highlights the positive results of an OPEC plus non-OPEC agreement (ME, 2018a).
This is aimed at reducing the oil market supply excess by voluntarily limiting the maximum levels of
production. The agreement has been further extended until the end of 2018.
RENEWABLE ENERGY DEVELOPMENT

Russia joined the International Renewable Energy Agency (IRENA) in 2015. The key objectives of thiscooperation are to develop Russia’s Renewables Roadmap until 2030 and provide better assessment ofdomestic Renewable Energy resources. In early 2017, Russia was elected as a member of IRENAs Council
to further facilitate consultations and cooperation among IRENA members (IRENA, 2018).
CLIMATE CHANGE

In accordance with the Decree of the President of the Russian Federation, the year 2017 was announced
the Year of Ecology in Russia. As a result of extensive work of academia, industry and government, the‘Strategy for Environmental Protection in Russia until 2025’ was signed as a presidential decree.

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–– (2017h), Gas industry. Background and key indicators, https://minenergo.gov.ru/node/1156.
–– (2017i), Coal industry. Russian coal supply, https://minenergo.gov.ru/node/437.
–– (2018a), Energy Minister’s report to the Federal Economic Committee, on 13 Feb 2018,https://minenergo.gov.ru/node/10553.
–– (2018b), Report on the Status of Heat Production and Distribution in Russian Federation in 2015-2016,
https://minenergo.gov.ru/node/10850.
–– (2018c), Deputy Minister Report at “Russian Energy” Conference, on 21 March 2018,https://minenergo.gov.ru/node/10849.
MNRE (Ministry of Natural Resources and Environment of the Russian Federation) (2017), Minister on oil
and gas industry perspectives,
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http://www.mnr.gov.ru/press/publication/o_perspektivakh_neftegazodobyvayushchey_otrasli_gos
udarstvennoy_geologorazvedke_osvoenii_arktiki_i_e/–– (2018), Minister on oil and gas exploration in 2017,
http://www.mnr.gov.ru/press/news/ministr_prirodnykh_resursov_i_ekologii_rf_sergey_donskoy_
dal_intervyu_zhurnalu_neftegazovaya_vertika/
Morport (Seaport trading association) (2017), Freight operations of seaports in 2017,
http://www.morport.com/rus/news/document1977.shtml.
NEA (Nuclear Energy Agency) (2016), Uranium 2016: Resources, Production and Demand, http://www.oecdnea.org/ndd/pubs/2016/7301-uranium-2016.pdf.
–– (2017), Uranium enrichment – Enrichment processes, http://world-nuclear.org/information-library/nuclearfuel-cycle/conversion-enrichment-and-fabrication/uranium-enrichment.aspx
Pravo (Official internet-portal of legal information of Russia) (2017). Presidential decree on the “Strategy on
Environmental Protection in the Russian Federation until 2025”,
http://publication.pravo.gov.ru/Document/View/0001201704200016.
RG (Rossijskaya Gazeta) (2016), The Government Has Approved the Paris Agreement on Climate Change (inRussian), http://rg.ru/2016/04/21/rg-rossiia-24-kabmin-odobril-soglashenie-ob-izmeneniiklimata.html.
Rosatom, (2017), State Corporation “Rosatom” Annual reports, http://rosatom.ru/about/publichnayaotchetnost/–– (2018), Rosatom is planning to build the first 1,200MW unit on fast breeding technology in 2020s,
http://rosatom.ru/journalist/news/rosatom-rasschityvaet-postroit-pervyy-reaktor-bn-1200-v-2020kh-godakh/.
RZD (Russian Railways, LLC) (2018), Investment activity,
http://ir.rzd.ru/static/public/ru?STRUCTURE_ID=35.
RZD-expo (Russian Railways news digest) (2017), Alternative fuels rolling stock, http://www.rzdexpo.ru/innovation/stock/locomotives_for_alternative_types_of_fuels/.
UNFCCC (United Nations Framework Convention on Climate Change) (2015). Russian Submission
INDC_eng_rev1.doc – UNFCCC, http://www4.unfccc.int/submissions/INDC/Published
Documents/Russia/1/Russian Submission INDC_eng_rev1.doc.

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RUSSIAUSEFUL LINKS
OFFICIAL BODIES OF RUSSIA

Structure of the Government of Russia—http://government.ru/en/
Ministry of Energy of the Russian Federation—http://minenergo.gov.ru/en
Ministry of Natural Resources and Environment of the Russian Federation—
https://www.mnr.gov.ru/english/
Federal Environmental, Industrial and Nuclear Supervision Service—http://en.gosnadzor.ru/
Ministry of Economic Development of the Russian Federation—http://economy.gov.ru/en/home/
Federal State Statistics Service—
http://www.gks.ru/wps/wcm/connect/rosstat_main/rosstat/en/main/
Ministry of Industry and Trade of the Russian Federation—http://minpromtorg.gov.ru/
Federal Agency on Technical Regulating and Metrology—http://www.gost.ru/wps/portal/en
Federal Antimonopoly Service—http://en.fas.gov.ru/
Federal Customs Service—http://eng.customs.ru/
Federal Tariff Service—http://www.fstrf.ru/eng
ENERGY-RELATED NON-PROFIT AND STATE-OWNED BUSINESS INSTITUTIONSAtomEnergoProm—http://atomenergoprom.ru/en/
Federal Grid Company—http://www.fsk-ees.ru/eng/
Association NP Market Council—http://www.en.np-sr.ru/index.htm
Gazprom—http://www.gazprom.com/
Rosneft—https://www.rosneft.com/
RusHydro—http://www.eng.rushydro.ru/
Transneft—http://www.en.transneft.ru/
Transnefteproduct, JSC—http://en.transnefteproduct.transneft.ru/
STATE ENERGY-POLICY-RELATED RESEARCH CENTRES

Russian Energy Agency—http://rosenergo.gov.ru/
Analytical Centre for the Government—http://ac.gov.ru/en/
Institute of Energy Strategy—www.energystrategy.ru/
Centre for Energy Policy—http://www.energy.ru/
Centre for Energy Efficiency—http://www.cenef.ru/art_11207_114.html
The Energy Research Institute of the Russian Academy of Sciences (RAS)—
https://www.eriras.ru/eng
Melentiev Energy Systems Institute (Siberian Branch of RAS) —http://isem.irk.ru/en/
MAJOR ENERGY-RELATED MEDIA IN RUSSIA

Official newspaper, Rossiyskaya Gazeta—https://rg.ru/
Central Dispatching Department of Fuel Energy Complex—http://www.cdu.ru/en/249

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SINGAPOREI N T ROD U C T I ON

Singapore is located in the south of the Malay Peninsula between the Strait of Malacca and the South China
Sea. This Southeast Asian economy’s land area was 719 square kilometres (km2) in 2015, with a population of
5.5 million.
Singapore is completely urbanised and highly industrialised, with a robust and growing diversified
economy despite its lack of domestic energy and mineral resources and small land size, a significant part ofwhich is reclaimed land. The economy’s impressive economic success is attributed to several factors, including
being a regional hub for tourism, financial activities, shipbuilding, petroleum and related equipment,
biotechnology, and its expanding role in international cargo and fuel shipping.
From 2014 to 2015, the economy’s gross domestic product (GDP) grew 1.9% to USD 439 billion. The
services industry accounted for the bulk of GDP share at 69%; goods-producing industries (manufacturing
and construction) accounted for 26%; and ownership of dwellings 1 accounted for the remaining 4.4%.
Manufacturing represented the largest sub-sector by percentage share of GDP (20%), followed by businessservices (16%) and wholesale and retail trade (15%) (SingStat, 2017).
Table 1: Key data and economic profile, 2015
Key data a; b

Energy reserves

Area (km2)719

Oil (million barrels)–

Population (million)

5.54

Gas (billion cubic metres)–

GDP (2010 USD billion [PPP])

439

Coal (million tonnes)–

GDP (2010 USD [PPP per capita])

79 256

Uranium (kilotonnes U)–

Source: a; b Department of Statistics Singapore (2017); EGEDA (2017).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Singapore has no natural resources and imports all its fossil fuel requirements. Its total energy imports (crudeoil, petroleum products, natural gas, coal and other energy products) in 2015 were 168 320 kilotonnes of oil
equivalent (ktoe). These were used to meet domestic energy requirements and serve the needs of its oil
refineries whose refined products are mainly exported to the Asia-Pacific Economic Cooperation (APEC)
region. More than half of these imports and refined products (91 222 ktoe) were exported in the same year
(EGEDA, 2017). Other than having a vibrant oil refining scene, Singapore also plays an important role ininternational shipping and aviation. This is evident from the share of international marine bunkers (26% ofimports, or 43 484 ktoe) and aviation bunkers (4.4% of imports, or 7 379 ktoe) in the economy’s total energy
imports (EGEDA, 2017).
The economy’s total primary energy supply (TPES) in 2015 was 25 612 ktoe, 1.7% lower than thepreceding year. Oil constituted the largest share of the TPES at about 60% (15 287 ktoe), followed by natural
gas at 36% (9 235 ktoe), coal at 1.6% (407 ktoe) and renewables at 1.5% (376 ktoe) (EGEDA, 2017).
In terms of power generation, the economy generated 50 415 gigawatt hours (GWh) of electricity in 2015,
an increase of 2.1% from that in 2014 (49 380 GWh) (EGEDA, 2017). Peak demand for electricity stood at 6960 megawatts (MW), slightly higher than that in 2014 (6 869 MW) (EMA, 2017a). There are six main power
1 Ownership of dwellings refers to housing services provided by owner-occupiers and individuals who let out theirresidential properties.

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producers in Singapore that contributed to the bulk of the total power generation (94%) in 2015 while autoproducers accounted for the remaining 6% (EMA, 2016a).
Total licensed generation capacity reached 13 349 MW in 2015. With the economy repowering steam
turbine plants into more efficient combined-cycle gas turbine (CCGT) power plants, the share of CCGT in
overall generation capacity significantly increased from 46% (4 534 MW) in 2005 to 78% (10 356 MW) in 2015.
Meanwhile, the share of steam turbine plants dropped from 48% (4 640 MW) in 2005 to 19% (2 557 MW) in
2015. Open-cycle gas turbine plants comprised 1.9% (180 MW) of the generation capacity in 2015 while wasteto-energy (WtE) plants accounted for the remaining 1.9% (257 MW) (EMA, 2017a).
With the shift away from steam turbine plants towards CCGTs, the share of natural gas in Singapore’sfuel mix for power generation substantially rose to 95% from 2014. In 2015, petroleum products accounted
for 0.7% and coal for 1.2% while other fuels accounted for 2.9% of the fuel mix (EMA, 2017a).
The adoption of solar photovoltaic (PV) systems in Singapore accelerated further in 2015, with installedcapacity of grid-connected solar PV systems (59.7 megawatt peak [MWp]) more than tripling from 2013 (15.3
MWp). The shares of Singapore’s residential and non-residential grid-connected solar PV system installationsin 2015 were 4 MWp and 55.7 MWp, respectively (EMA, 2017a).
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

620

Industry sector

5 586

Net imports and others

77 098Transport sector

2 411

Thermal

Total primary energy supply

25 612Other sectors

2 502

Hydro

–

Coal

407

Non-energy

6 626

Nuclear–Oil

15 287

Final energy consumption*

10 499Others

1 551

Gas

9 235

Coal

121

Renewables

376

Oil

5020

Others

307

Gas

1 241

Renewables

Total power generation

50 41548 8640Electricity and others

4 087

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

Singapore’s final energy consumption was 10 499 ktoe in 2015, a 1.6% decrease from that in 2014. Oil remained
the bulk of final energy consumption (5 020 ktoe), with a share of about 48%, followed by electricity and others(39%, 4 087 ktoe), natural gas (12%, 1 241 ktoe) and coal (1.4%, 151 ktoe). In terms of the total final
consumption, the most significant portion was attributed by non-energy uses (39%). By sector, the industrial
sector accounted for 33% of total final consumption, other sectors (including residential and commercial
sectors) accounted for 15% and the transport sector accounted for 14% (EGEDA, 2017).
ENERGY INTENSITY ANALYSIS

Singapore is fully committed to contribute to APEC’s objective of a 45% energy intensity reduction by 2035
(2005 as base year) as set by APEC leaders in 2011. The economy’s efforts to reduce energy intensity began in2009 when the economy set an ambitious target to reduce energy intensity by 35% by 2035. Subsequently,

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Singapore’s Inter-Ministerial Committee on Sustainable Development (IMCSD) formulated the Sustainable
Singapore Blueprint as a guiding strategy for the economy’s sustainable development (MEWR, 2014).
Various government initiatives have aimed at helping the economy achieve its commitment to APEC’s
2011 target. Recent examples include the Energy Conservation Act 2013 (ECA) which focuses on a range ofinterrelated energy issues including improving energy conservation, efficiency and intensity while reducing CO2
emissions (GBS, 2014). The Act aims to help Singapore achieve its intensity reduction target by improving theenergy performance of the economy’s companies. Other initiatives, including seeking improvements in energy
conservations and efficiencies, are discussed later in this chapter.
Compared with 2014, Singapore’s energy intensity in 2015 declined both in terms of primary energy as
well as final consumption. Primary energy intensity decreased to 58 tonnes of oil equivalent per million USD(toe/million USD) in 2015, 3.6% reduction from that in the previous year. Final energy intensity decreased to
39 toe/million USD, a 3.2% reduction from 2014. These reductions were mostly driven by decreasing energy
consumption in the industry and transport sectors.
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

61

58

-3.6

Total final consumption

40

39

-3.2

Final energy consumption excl. non-energy uses

25

24

-3.5

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSISLand scarcity and the absence of suitable geological conditions limit Singapore’s options for renewable energy.
Solar power and WtE are the main forms of viable renewable sources for the economy, which has made great
effort in pursuing these options. In 2014, Singapore set a target to increase the adoption of solar power to 350
MWp by 2020, equivalent to 5% of its projected power needs. This has helped accelerate the adoption of solar
PV systems in the economy. In 2015, the share of modern renewable energy in final energy consumption
increased by 14% compared with 2014.
Table 4: Renewable energy share analysis, 2014 vs 2015

10 66910 499Change (%)
2014 vs 2015
–1.6

10 603

10 425–1.7

Traditional biomass*

0

0

0

Modern renewables*

66

74

12

0.62%

0.71%

14%

2014
Final energy consumption (ktoe)
Non-renewables (Fossils and others)

Share of modern renewables in final energy
consumption (%)

2015

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal and so on) including biogas and wood pellets are
considered modern renewables although data on wood pellets are limited.

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P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKSingapore’s 2007 National Energy Report sets out the strategies2 to balance the objectives of energy security,
economic competitiveness and environmental sustainability. The economy has since sought to secure thisbalance through a range of measures.
To end total dependence on piped imports from Malaysia and Indonesia for gas requirements—which
accounted for 95% of its power mix in 2015 (EMA, 2015a)—Singapore began operating its first liquefied
natural gas (LNG) terminal in May 2013 (SLNG, 2014). This has enabled the economy to diversify its gas
supplies by importing LNG from Australia, Equatorial Guinea and Trinidad and Tobago (MTI, 2015) while
securing additional gas for its growing gas demand and adding LNG to the energy mix.
Singapore is exploring more ways to diversify its energy mix by scaling up deployment PV panels,
regarded as the ‘most economically and technically viable renewable energy option’ (MTI, 2015). It launched
the SolarNova programme to aggregate demand for solar energy ‘across government buildings and spaces, toyield savings from economies of scale’ while seeking to ‘demonstrate solar energy’s viability in Singapore [to]catalyse further adoption by the private sector’ (MTI, 2015).
Singapore is also intensifying its efforts to promote more efficient energy use and decrease CO 2
emissions. As part of its contribution to the post-2020 climate change agreement, Singapore intends to ‘reduce
its emissions intensity by 36% from 2005 levels by 2030 and to stabilise emissions with the aim of peaking
around 2030’ (MTI, 2015). This pledge builds on its existing commitment to reduce greenhouse gas (GHG)
emissions by 16% from the business-as-usual (BAU) level by 2020; the economy is on track to meet this. It isa remarkable objective as Singapore is already one of the least carbon-intensive economies in the world, ranking
123 out of 142 countries (NCCS, 2015).
More recently, in January 2016, the government formed the Committee on the Future Economy (CFE)to review and develop economic strategies for Singapore over the next decade. This review was conducted in
the face of a changing global environment, technological changes and a slower growth of the economy’s labour
force. The CFE was tasked to build on the 2010 Report by the Economic Strategies Committee andrecommend strategies to maintain sustainable economic growth for Singapore. Recommendations made by
the CFE, including energy-related strategies, will lay the foundation for Singapore’s policy development overthe next decade. In the Report of the CFE submitted in February 2017, the following recommendations
relevant to Singapore’s energy developments were made (CFE, 2016):
1.

Become a model city in sustainability. The report recommends more aggressive investment in
Research and Development (R&D), test-beds and commercialisation of new energy solutions. On the
supply side, Singapore should ramp up the deployment of solar PVs and invest in R&D for energy storage
solutions and solar forecasting. These could support cost-effective deployment of solar energy andenhance energy grid resilience. On the demand side, Singapore should continue to push for greater
efficiency in energy usage through more energy ‘smart meters’ to encourage energy-saving behaviour
through real-time feedback. Real-time information will also facilitate easier implementation of DemandSide Management (DSM) initiatives and will allow for the development of new business models.

2.

Strengthen competitiveness as a trading hub. Singapore is a successful regional trading hub for agricommodities, metal and minerals, and energy-related commodities. It should diversify trade flows anddeepen its ecosystem of supporting services and financing. These will help grow a liquid commodity
derivatives marketplace and strengthen commodity trade financing.

3.

Aggregate demand for sustainable technologies to help enterprises build a track record. Leaddemand has resulted in the development and adoption of smart and sustainable technologies. The

2 Diversify Energy Supplies; Enhance Infrastructure and Systems; Improve Energy Efficiency; Strengthen the Green

Economy; Price Energy Right.

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government should use lead demand to build expertise and track records of enterprises in areas such asenergy management and industrial water solutions.
4.

Raise ambitions in the adoption of sustainable urban solutions. To raise Singapore’s renewableenergy and urban mobility ambitions, the government should leverage the Green Mark standards toencourage solar PV adoption; explore large-scale floating PV deployment; develop standards to trackrenewable energy production/consumption and craft urban mobility adoption plans.
ENERGY MARKETSThe electricity and gas industries in Singapore were once vertically integrated and owned by the government,
under the responsibility of the Public Utilities Board (PUB). Singapore began restructuring its electricity
industry in 1995 to liberalise the market and promote competition. Major activities in this regard have included
corporate and industry structural reforms, the creation of an institutional regulatory framework and market
rules for the contestable parts of electricity generation and retail sales of electricity, separate from the natural
monopoly of electricity transmission at the ownership level. Later, in 2001, the gas market was also restructured
to support the parallel liberalisation of the electricity market.
ELECTRICITY

In October 1995, the SP Group (formerly known as Singapore Power Ltd) was created. Electricity activities
under the PUB (including electricity transmission and the distribution grid, market support services and powergeneration companies) were transferred to Temasek Holdings, a state-owned company. The Singapore
Electricity Pool was established in 1998 as a day-ahead electricity market to facilitate trading of electricity
between generation and retail companies in a competitive environment.
The Government of Singapore introduced additional reforms in 2000, separating the natural monopoly
or non-contestable part of the electricity market (the electricity transmission and distribution grid) and thecompetitive or contestable part (power generation and retail). As a result, three power-generation companies—
Senoko Power Ltd, PowerSeraya Ltd and Tuas Power—were divested as private companies in 2008 to competewith each other and other power-generation companies in Singapore. Additionally, the government founded
an independent power system operator and liberalised the electricity retail market.
In April 2001, the Energy Market Authority (EMA) was established to regulate the electricity and gas
industries and promote competition in these industries, and since then, it has progressively opened up the retailelectricity market to enhance competition and allow business consumers more options to manage their energy
cost. The National Electricity Market of Singapore (NEMS), established in 2003, allows generation companies
to compete to sell electricity at half-hour intervals in the wholesale electricity market. NEMS represented a
progression from the Singapore Electricity Pool to fully competitive wholesale and retail electricity markets.
Currently, electricity consumers in Singapore are separated into contestable and non-contestableconsumers. Contestable consumers refer to business consumers with an average monthly electricity
consumption of at least 2 megawatt-hours (MWh). They can opt to purchase electricity either at the regulated
tariffs from SP Group, the market support services company or directly from retailers of their choice at nonregulated prices. Contestable consumers currently represent more than 80% of the total electricity demand in
Singapore. Non-contestable consumers, which include the remaining business consumers and all households
in Singapore, purchase electricity from SP Group at the regulated tariffs (EMA, 2018).
Moving forward, Singapore plans to fully liberalise the electricity industry. Starting from the second halfof 2018, under the Open Electricity Market, all the remaining electricity consumers will also have the optionof buying electricity from retailers other than SP Group.
GAS

The passage of the Gas Act (Act 11) in 2001 marked the beginning of the restructuring of Singapore’s gas
industry. The Act sets the legal basis for separating the contestable part of the gas industry (gas retail and gas
imports) from the monopolistic part (gas transportation). PowerGas Ltd, a subsidiary of SP Group, is the only
gas transporter in Singapore and owns both the natural gas and town gas pipeline networks. It provides open

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and non-discriminatory access to the gas pipeline networks. EMA licenses and works closely with PowerGas
to annually review the natural gas transmission network plan.
The Gas Network Code (GNC), which came into effect on 15 September 2008, marked Singapore’s
newly restructured gas market operation. The EMA developed and enacted the GNC in consultation withindustry players. GNC governs the activities of gas transportation, providing open and non-discriminatory
access to Singapore’s onshore gas pipeline network. The GNC outlines the common terms and conditions
between the gas transporter (PowerGas Ltd) and gas shippers (that is, industry players who engage thetransporter to convey gas through the pipeline network). To ensure that the gas transporter is not incommercial conflict with common interests, PowerGas Ltd is banned from participating in electricity and gas
businesses open to competition such as gas importing, trading and retailing. Other gas industry participants
are not allowed to transport gas.
The gas market’s restructuring is mainly aimed at supporting the liberalisation of the electricity industry
by providing a competitive source of natural gas for electricity generation. The Government of Singapore
expects greater competition in the gas and electricity sectors and the benefits of competition, such as lower
prices and a wider choice of retailers, to be passed through to consumers.
In 2016, Singapore imported 9.7 Mtoe of Natural Gas, comprising 76.6% Piped Natural Gas (PNG) and23.4% LNG (EMA 2017b). Before the introduction of LNG in 2013, Singapore fully depended on PNG
supplies from Indonesia and Malaysia.
Four offshore natural gas pipelines—two from Malaysia and two from Indonesia—supply Singapore’s
PNG needs. Keppel Gas Pte Ltd currently imports 43 million cubic feet per day (MMcf/D) of Malaysian gas
while Senoko Energy Ltd imports 40 MMcf/D of piped gas from Malaysia for its power-generation plant.
From Indonesia, Sembcorp Gas Pte Ltd currently imports 325 MMcf/D of gas from west Natuna while Gas
Supply Pte Ltd imports another 350 MMcf/D of gas from Sumatra (The Business Times, 2014).
Given the growing significance of natural gas in Singapore’s power mix, the Government of Singapore
announced a plan in 2006 to import LNG to meet the rising demand for electricity generation and to diversify
its sources of natural gas. The first Singapore LNG terminal, operated by Singapore LNG Corporation (SLNG)
commenced operations on 7 May 2013, with an initial capacity of 3.5 million tonnes per annum (Mtpa), locatedat an approximately 40-hectare site on the south-west part of Jurong Island. This capacity increased to 6 Mtpa
in January 2014 when the third LNG tank, the fourth open rack vaporiser and two high-pressure booster
pumps were completed and brought into service. Additionally, the secondary berth and the gas engine
generator were completed at that time (SLNG, 2014a).
The terminal’s capacity will rise to 11 Mtpa in 2018 when the fourth tank and additional regasification
facilities become operational (EMA, 2016b). The LNG terminal is also capable of providing ancillary services,such as LNG trucking, cool-down and break-bulks. In addition, the terminal has also commissioned a nitrogen
blending facility which will enable SLNG to receive LNG with varying specifications from more diverse
sources.
In terms of LNG supply, Singapore has been appointing its LNG importers through a competitive
Request-for-Proposal (RFP) process and by awarding them exclusive ‘franchises’ to sell LNG in Singapore. In
2008, BG Singapore Gas Marketing, now part of Royal Dutch Shell, emerged as the winner of the RFP process
and was selected to be the sole LNG importer to supply the first tranche of LNG to Singapore. Subsequently,
in October 2016, Pavilion Gas Pte Ltd and Shell Eastern Trading (Pte) Ltd were appointed to meet the second
tranche of Singapore’s LNG demand. The second tranche of LNG imports commenced on 23 October 2017.
Both the appointed importers will have the exclusive right to sell up to 1 Mtpa of term LNG in Singapore, orfor three years, whichever is earlier (EMA 2017c). To encourage greater gas-on-gas competition, thegovernment will also allow third-party spot LNG imports and new PNG imports on a case-by-case basis (EMA,
2017b).
ENERGY TECHNOLOGY/RESEARCH AND DEVELOPMENT

In 2014, Singapore announced five energy technology roadmaps to guide the formulation of technology masterplans and funding initiatives. These roadmaps are for solar photovoltaic, carbon capture and255

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storage/utilisation, green data centre, building energy efficiency and industry energy efficiency (NRF,
2014a).
Singapore also supports and promotes energy R&D to develop capabilities to support the clean energy
sector as a key growth area; to grow a viable industry that will create jobs; to meet Singapore’s energy challenges
and its sustainable development objectives and so on.
In terms of funding, the National Research Foundation (NRF) allocated SGD 170 million in 2007 andanother SGD 195 million in 2011 to the Energy Innovation Programme Office (EIPO) to promote R&D in
the energy sector (NRF, 2014b). Under the economy’s five-yearly R&D plan covering the period 2011–2015,
the Research, Innovation and Enterprise (RIE) 2015 awarded more than SGD 60 million in funding tocatalyse R&D of innovative technologies and solutions in the energy sector. Building on the momentum, afurther SGD 46 million has been allocated to spur research into energy technologies and build capabilities insmart grids, power utilities and energy storage under the RIE 2020 (EMA, 2016c).
The EIPO has also supported the establishment of research centres for clean energy. For example, theSolar Energy Research Institute of Singapore (SERIS) was established in 2008 to conduct industry-oriented
R&D in solar energy technologies and their integration into power systems and buildings. There are currently
around 150 researchers employed with SERIS, which closely collaborates with universities, researchorganisations, government agencies and industries, both locally and globally. The Energy Research Institute at
Nanyang Technological University (ERI@N) was also established with the objective of advancing research
aimed at improving the efficiency of current energy systems and maximising the use of alternative energy
sources. In a related effort, the Agency of Science, Technology and Research (A*STAR) set up theExperimental Power Grid Centre (EPGC), a programme that undertakes R&D activities in areas such as
intelligent and decentralised power distribution, control and management of distributed energy resources, andsmart and interactive energy utilisation. It features a 1 MW experimental power grid which is designed to create
various power network configurations at near grid-like conditions. This facility acts as a platform forresearchers, industries and public agencies to develop energy technologies before bringing them to larger-scale
test-beds or commercialisation.
The Energy Innovation Research Programme (EIRP) is a competitive R&D grant call initiative under
the EIPO that aims to strengthen Singapore’s R&D capabilities and address its energy-related challenges.
Between 2012 and 2015, the EIRP launched 13 grant calls in areas such as solar, green buildings, power
generation, energy storage, smart grids and gas (NUS, 2015).
The EMA also offers various research grants. Recent example includes a competitive grant call launchedby EMA in May 2017 to seek R&D proposals to improve the resilience of Singapore’s cyber-physical powersystems and energy markets, through the use of technologies such as big data, artificial intelligence and machinelearning. In October 2017, EMA awarded a SGD 6.2 million grant to a consortium led by the National
University of Singapore (NUS) to develop solar forecasting capabilities over a four-year project (EMA, 2017c).
Finally, the National Environment Agency (NEA) also supports environmentally focused energy
research as part of the efforts to help Singapore achieve environmental sustainability. To this end, theSingapore Environment Institute acts as NEA’s training and knowledge division (NEA, 2015a). Additionally,
the NEA, in its capacity as Singapore’s designated national authority for clean development mechanism (CDM)
projects under the Kyoto Protocol to the United Nations Framework Convention to Climate Change(UNFCCC), issued ‘a Letter of Approval (LoA) to CDM projects that meet Singapore’s sustainable
development criteria. The LoA supports the registration of the project by the UNFCCC CDM Executive
Board (EB)’ (NEA, 2015b).
ENERGY CONSERVATION

Singapore has taken measures to decrease its energy consumption through conservation. To this end, theParliament of Singapore passed the ECA 2013 to be jointly administered by the Ministry of the Environment
and Water Resources and the Ministry of Transport; it came into effect in 2013.
The ECA requires companies that are large users of energy to implement energy management initiatives.
Companies that annually consume 54 terajoules (TJ) or more of energy in at the least two out of the three256

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preceding years are required to appoint at the least one energy manager to monitor and report their energy use
and GHG emissions and to submit plans for energy efficiency improvement to the relevant agencies.
The Act also consolidates energy-efficiency-related legislation currently found in different acts including
the Mandatory Energy Labelling Scheme, Minimum Energy Performance Standards and the Fuel Economy
Labelling Scheme for passenger cars and light goods vehicles under the Environmental Protection andManagement Act. In March 2017, enhancements to the Act were announced to come into effect from 2018 tohelp Singapore achieve its pledge under the Paris Agreement. These include strengthening the measurement
and reporting requirements for GHG emissions, requiring companies to undertake regular energy efficiency
opportunity assessments and introducing minimum energy performance standards for common industrial
equipment and systems.
Apart from the ECA, the economy has also sought to decrease energy consumption by improving theenergy efficiency of its industry, transportation, buildings and household sectors.
ENERGY EFFICIENCY

Singapore’s geographical constraints limit the extent of alternative energy deployment. Energy efficiency has
hence been identified as a key strategy to mitigate GHG emissions. It also helps improve competitiveness,
energy security and environmental sustainability. Singapore has adopted several measures to improve its energy
efficiency and to reduce the energy use of various sectors of its economy.
In 2007, the government established the Energy Efficiency Programme Office (E2PO), a multi-agency
committee led by the NEA and the EMA, in order to implement energy efficiency to promote energy efficiency
in both public and private sectors through legislation, incentives and information (NEA, 2014). These energy
efficiency efforts are targeted at various sectors, such as power generation, industry, transport, buildings andhouseholds.
The E2PO promotes and facilitates the adoption of energy efficiency in Singapore under the following
five strategic goals (E2PO, 2014):
Promote energy efficiency through regulation and standards, incentives and open information

Develop human and institutional capabilities by developing a local knowledge base and expertise inenergy management and collaborating with institutes of higher learning (IHLs)



Promote emerging energy-efficient technologies and innovation through support for researchdevelopment and demonstration of new energy-efficient technologies, innovation and businessprocess improvements

Profile and promote energy efficiency internationally through various platforms such as Singapore
International Energy Week (SIEW), APEC and East Asia Summits (EAS)Benchmark Singapore’s energy efficiency initiatives against other countries and internationalframeworks

The E2PO has targeted Singapore’s main energy consumers, namely, industry, transportation, buildings
and households, through its various programmes aimed at improving energy efficiency and reducing their CO2
emissions. Recent examples include programmes for buildings, through the Building Control Act’s Chapter 29
Part IIIB—Environmental Sustainability Measures for Existing Buildings (E2PO, 2015a); for industry, throughthe 2013 Mandatory Energy Management Requirements (E2PO, 2015b) and for households, through the 10%
Energy Challenge of 2008, which is aimed at encouraging households to save at the least 10% (E2PO, 2015c).
Expanding the mass rapid transit system has been the major emissions-reduction policy for the transport sector(E2PO, 2015d).
INDUSTRY

The industrial sector is the largest energy-consuming sector in Singapore. The Industry Energy Efficiency
Roadmap, launched in June 2016, identifies and prioritises the technological potential and opportunities toreduce energy use from BAU levels up to 2030. It also serves as a reference to provide guidance and insight topolicymakers, industry leaders, academia and research institutes and other relevant stakeholders (NCCS, 2016).
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Among the various government initiatives to improve industry’s energy efficiency are the following:Energy Efficiency Fund (E2F): this fund supports energy efficiency efforts at industrial facilities,
namely, facilitating efficient design of new facilities, conducting energy assessments and adoptingenergy-efficient equipment and technologies. E2F provides up to 50% co-funding for industrial
companies to review the design of their new facilities to integrate energy and resource efficiency
improvements as well as to carry out periodic energy assessments to understand their energy
consumption patterns and identify potential energy improvement opportunities. For companies thatwould like to replace their existing equipment with more energy-efficient ones, up to 30% of the
project costs could be subsidised.

Energy Efficiency National Partnership (EENP) Programme: introduced by NEA, EMA and theEconomic Development Board (EDB) in 2010, the EENP serves as a platform to help companies
reduce energy consumption by conducting relevant courses and workshops as well as providing energy
efficiency-related resources, incentives and recognition. It is a voluntary partnership program forcompanies that wish to be more energy-efficient, thereby enhancing their long-term businesscompetitiveness and reducing their carbon footprint. Since 2011, a National Energy Efficiency
Conference has been annually held to provide partners with opportunities to learn and exchange
energy efficiency technologies and best practices. As of January 2018, 261 companies have joined as
partners. The EENP Awards also accords recognition to companies and individuals who excel in theareas of energy management through annual awards.

The Singapore Certified Energy Manager training program and grant: this programme provides athorough understanding of the key energy issues faced by the building and industry sectors. It helps
participants develop the technical skills and competencies needed to manage energy issues in theorganisations that they serve. A training grant is also offered to cover about 80% of the training costs.

Energy Efficiency Financing Programme: to encourage industrial and manufacturing facilities to adopt
energy-efficient equipment or technologies, a third-party financier pays for the cost of energy
efficiency projects and the energy savings are shared among all stakeholders.



The One-Year Accelerated Depreciation Allowance Scheme: this tax incentive scheme allows capital
expenditures on qualifying energy-efficient equipment to be written within one year instead of three.

The Investment Allowance Scheme: this tax incentive scheme encourages companies to replace oldenergy-consuming equipment with more energy-efficient ones by allowing an additional 30% ofinvestment allowance to be deducted from the companies’ taxable income.



The Energy Efficiency Improvement Assistance Scheme (EASe): EASe encourages and helps
companies identify potential energy efficiency improvement opportunities. Under EASe, up to 50%of the cost of appraisals for buildings and facilities will be co-funded.

Energy Service Company Accreditation Scheme: the objective is to enhance the professionalism andquality of services offered by energy services companies. This will, in turn, enhance confidence in theenergy services sector and help promote the growth of the industry.

Design for Efficiency Scheme (DfE): introduced in 2008, this initiative encourages investors toincorporate energy and resource efficiency considerations into the development plans of their facilities
early in the design stage. Under the DfE, up to 80% of the cost to conduct design workshops will be
co-funded.

The Grant for Energy Efficiency Technologies (GREET): GREET is a co-funding scheme launchedin 2008 to incentivise owners or operators of industrial facilities to invest in energy-efficienttechnologies or equipment.



Small and Medium Enterprise (SME) Energy Efficiency Initiative: launched in 2013, this SGD 17
million initiative brings together existing government grants to help SMEs reduce their energy costs,
increase productivity and promote energy efficiency. The grant provides funding for Energy Audit,

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Energy Monitoring System, Energy Efficiency Project Implementation and Energy Efficiency
Thought Leadership (SEAS, 2017).
TRANSPORT

Singapore has sought to increase the energy efficiency of its transport sector through various measures. Thisobjective is embedded in the economy’s land transport strategies which seek to integrate transport and landuse planning, promote greater use of public transport and apply intelligent transport systems to manage roaduse. The government has also pioneered innovative policies such as a vehicle quota system and electronic roadpricing to reduce congestion and a green vehicle rebate to encourage more fuel-efficient vehicles and trials ofgreen technologies such as diesel-hybrid buses and electric vehicles (EVs).
Singapore’s major efforts to increase sector efficiencies include the following:Managing car ownership and usage by limiting the growth of vehicle numbers through the Vehicle
Quota System, refining the Electronic Road Pricing (ERP) system with the ERP 2.0 which is a satellitebased ERP system and further developing Intelligent Transport System solutions.



Testing new technologies such as the Diesel Particulate Filter, diesel-hybrid buses, and electric cars.



Developing a Green Framework for the Rapid Transit System (RTS). The Green Mark provides asystematic and structured approach to evaluating and rating the environmental performance of the
RTS for existing and future lines.

Vehicle Emissions Scheme (VES): the VES became effective on 1 January 2018, replacing the Carbon
Emissions-Based Vehicle Scheme. The scheme is meant to improve the number of green vehicles
purchased, with cars enjoying rebates for having low-carbon emissions while those with high carbon
emissions must pay a surcharge (LTA, 2017).



Fuel Economy Labelling Scheme: since 2012, any passenger and light goods vehicles sold in Singapore
must show a Fuel Economy Label that provides information on its fuel efficiency to help buyers makebetter decisions. Fuel economy labels will be redesigned to help potential vehicle buyers makeinformed decisions in choosing cleaner, more fuel-efficient cars in 2018.



Green Mark for RTS: the RTS is the backbone of Singapore’s public transport system and is also themost energy-efficient means of transporting a large number of commuters. By 2020, the RTS network
is expected to double to 278 km. The objectives of the Green Mark for the RTS framework are topromote sustainable and environment-friendly RTS designs as well as to provide guidance in theformulation of engineering standards for conceptualisation, design and construction of new RTS lines.
The framework has three key pillars—effective use of energy, water conservation and environmental
protection and sustainable development—and covers various aspects of an RTS line (rolling stock,electrical and mechanical systems, civil works, station design as well as operational considerations).



EV test-bed: An inter-agency EV taskforce (EVTF) led by the EMA and the Land Transport
Authority (LTA) launched the EV test-bed from June 2011 to December 2013 in order to determine
the feasibility of EVs in Singapore (EMA, 2014c). Findings from the test-bed have shown that EVs
are technically feasible in Singapore but are still limited by issues such as high upfront costs. In
December 2014, the EDB and the LTA announced the next phase of the EV test-bed, which will
focus on vehicle fleets such as EV car sharing and E-taxis (LTA, 2014). As part of this second phaseof the EV test-bed, HDT Singapore Taxi Pte. Ltd also launched a fleet of electric taxis in late 2016
(The Straits Times, 2016). Singapore will launch an EV car-sharing program in collaboration with the
Bolloré Group by mid-2017. EVs will be deployed in every single Housing & Development Board(HDB) town by 2020, allowing as many residents as possible to enjoy car-sharing facilities (LTA,
2016a).

Promoting Cycling: To promote a cycling-friendly city, Singapore has extended its cycling networkand enhanced the cycling infrastructure. By 2030, all HDB towns will have a cycling network, taking
the total cycling paths across Singapore to 700 km. Other bicycle-friendly infrastructure such as bicycle
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crossings and bike parking facilities are being added to further encourage a cycling culture (LTA,
2016b).
BUILDINGS

The Building and Construction Authority (BCA), a statutory board under the Ministry of National
Development, spearheads energy efficiency improvements in the building sector. In its third and latest Green
Building Masterplan launched in September 2014, the BCA set out ambitious plans to accelerate its green
building agenda and meet the target of greening 80% of the buildings in Singapore by 2030 (BCA, 2017).
Energy efficiency initiatives in Singapore’s building sector include the following:

BCA Green Mark Scheme: launched in January 2005, this scheme is a green building rating systemthat promotes sustainability in the established environment and raises environmental awarenessamong developers, designers and builders. Under this benchmarking scheme, buildings are assessed
for energy efficiency, water efficiency, indoor environmental quality and environmental protection as
well as other green features and innovations.



Building Control (Environmental Sustainability) Regulations: these regulations took effect in 2008
and require new buildings and existing ones undergoing major retrofitting with a gross floor area
(GFA) greater than 2 000 square metres to achieve the minimum green mark certified level.

Building Control Act’s Chapter 29 Part IIIB — Environmental Sustainability Measures for Existing
Buildings: introduced in 2012, this Act requires building owners to comply with the minimum
environmental sustainability standard (green mark standard) for existing buildings; submit periodic
energy efficiency audits of building cooling systems and submit information with respect to energy
consumption and other related information, as required.



Building Control (Environmental Sustainability Measures for Existing Buildings) (Amendment)
Regulations 2016: since January 2017, all buildings (except industrial buildings, railway premises, port
facilities or airport facilities, religious buildings, data centres, utility buildings and residential buildings
other than serviced apartments) with centralised cooling systems and GFA greater than 5,000 square
metres must comply with the revised act, when installing or replacing the building cooling system.



S$50 Million Green Mark Incentive Scheme for Existing Buildings and Premises: launched in 2014,
this is targeted to encourage SME tenants and building owners, or building owners with at the least
30% of SME tenants to adopt energy efficiency improvement measures. The scheme co-funds up to
50% of the retrofitting cost for energy improvements, or up to S$3 million for building owners andS$20,000 for tenants.



Building Retrofit Energy Efficiency Financing Scheme: this scheme was introduced in 2011 to offer
financial aid through an energy performance contract arrangement to offset high upfront costs ofenergy efficiency retrofits. With the scheme, applicants can obtain financing from participating
financial institutions and service the loans through energy savings.

Green Mark GFA Incentive Scheme: to encourage the private sector to achieve higher-tier GreenMark ratings, additional floor area will be allowed to private developments with Green Mark Platinum
or Gold Plus marks from April 2014 to April 2019.



S$5 million Green Mark Incentive Scheme, Design Prototype: valid from December 2014 toDecember 2018, this scheme aims to encourage developers and building owners to strive for greater
energy efficiency in buildings at the design stage, by providing funding support to engage consultants
during the design phase for green buildings.



S$100 Million Green Mark Incentive Scheme for Existing Buildings: this is aimed at owners of existing
private commercial developments to help them implement energy-efficient solutions and to conduct
energy audits in their existing buildings.

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

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Public Sector Sustainability Plan: launched in 2017, the government aims to achieve electricity savingsof 15.0% by 2020 from the baseline electricity consumption in 2013. These include ‘hardware’
improvements, such as replacing or upgrading air-conditioning systems and lightings, and ‘software’
actions, such as promoting organisational habits that minimise electricity consumption. The annual
energy savings from the government’s committed measures amount to 290 GWh. This is sufficient topower 50,000 households for an entire year. Each ministry is required to submit reduction targets andmanagement plans to meet the targets. In addition, new public sector buildings with an air-conditioned
area of greater than 5 000 square metres must attain the Green Mark Platinum rating while existing
public sector buildings with an air-conditioned area of greater than 10 000 square metres must attain
the Green Mark GoldPLUS rating by 2020.

HOUSEHOLDS

Improving energy efficiency of households has been a major target for Singapore as part of its commitment tosustainable development that demands reductions in fossil energy consumption and CO 2 emissions.
Accounting for about one-sixth of the electricity consumed in Singapore, households are encouraged topurchase energy-efficient appliances and adopt energy-efficient habits. Energy efficiency programmes forhouseholds include the following (NEA, 2017):


Mandatory Energy Labelling Scheme (MELS): under the ECA, registrable household appliances thatare sold in Singapore must show the mandatory energy label which displays the energy rating of an
appliance by the number of ticks (from 1 to 5, with 5 being the most energy-efficient). MELS was
introduced to help consumers compare the energy efficiency of different appliances and make more
informed purchasing decisions. It currently covers household refrigerators, air conditioners, clothes
dryers, television sets and lamps.

Minimum Energy Performance Standards (MEPS): the objective of setting MEPS is to raise theaverage energy efficiency of regulated goods in the market. This is done by prohibiting the sale ofappliances that fall short of specified minimum energy efficiency levels and by encouraging suppliers
to bring in more energy-efficient appliances as technology improves. Household refrigerators, airconditioners, clothes dryers and lamps supplied in Singapore must meet the MEPS.



Residential Envelope Transmittance Value Standard: Established in 2008, residential buildings with a
GFA of 2 000 square metres or more must comply with the BCA residential envelope transmittancevalue standard.
RENEWABLE ENERGY

Singapore has very limited options in terms of renewables because of its geological and geographical location.
Hydro, wind, geothermal and tidal energy are not feasible, leaving solar PV systems and WtE as Singapore’s
main renewable energy sources. The economy has also been producing biodiesel since 2010 to help diversify
its liquid energy demand.
In terms of WtE, Singapore currently has four electricity-generating incineration plants (Tuas IP 46 MW,
Senoko WTE Plant two x 28 MW, Tuas South IP 80 MW and Keppel Seghers Tuas WTE Plant 22 MW) thatincinerated a total of 2.83 million tonnes (Mt) of waste in 2016 (MEWR, 2017). In 2015, Singapore announcedplans to build a new 120 MW WTE plant by 2019. More details can be found under ‘New Generation Capacity’in the section on ‘Notable Energy Developments’.
In terms of solar power, Singapore has put in place a series of initiatives to pursue its target of raising the
adoption of solar power to 350 MWp by 2020. As of November 2017, there were 2 056 grid-connected PV
installations with a total capacity of 141.3 MWp, comprising 687 residential (7.1 MWp) and 1 369 nonresidential (134.2 MWp) installations (EMA, 2017a). The list of solar initiatives by the economy includes thefollowing:In support of Singapore’s solar energy plans, HDB has committed to roll out 220 MWp of solar
panels at about 5 500 HDB blocks by 2020. As of November 2017, HDB has held three solar leasing

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tenders under the SolarNova programme and has committed a total solar capacity of 190 MWp for
3 350 HDB blocks (HDB, 2017).


The SolarNova programme was initiated in 2014 to aggregate demand for solar energy acrossgovernment agencies in order to achieve economies of scale and drive the growth of Singapore’s solar
industry (HDB, 2014). This programme is estimated to generate 420 GWh of solar energy annually,equivalent to about 5% of Singapore’s total energy consumption. Under the solar leasing businessmodel, private solar PV system developers will design, finance, install, operate and maintain the solar
PV systems. Town councils managing the HDB blocks with solar panels will then enter a service
agreement with these developers to pay for the solar power generated at a preferential rate not higher
than the retail electricity tariffs (HDB, 2016). The power produced could be used to power lifts,
corridors and staircase lights in common areas.

With effect from May 2017, all future public housing blocks with at the least 400 square metres ofopen roof space will be designed with solar-ready roofs to enable more productive and efficientinstallation of solar panels on HDB rooftops. In addition, HDB will also review developments
currently under construction to assess if solar-ready roofs can be incorporated into their design. As
of August 2017, a total of 18 HDB projects have been designed with solar-ready roofs.



Added to HDB’s efforts to expand solar energy, the EDB and PUB also conducted a pilot SGD 11
million floating PV system test-bed project at Tengeh Reservoir in October 2016. The test-bed wasaimed at assessing the feasibility of installing floating solar PV systems (2 MW) as an alternative torooftop-based installations (NCCS, 2014). It is the world’s largest test site for floating solar panels
and the first project of this nature in Southeast Asia. Results from the test-bed showed that the system
performed better than a typical rooftop solar PV system in Singapore because of the cooler
temperatures of the reservoir environment. Building on these successful results, PUB announcedplans in September 2017 to expand its trials to explore the feasibility of deploying a 50 MWp floating
solar PV system at Tengeh Reservoir and a 6.7 MWp floating solar PV system in Upper Peirce
Reservoir (PUB, 2017).



The EMA has also increased the intermittent generation threshold from 350 MWp to 600 MWp inorder to help expand solar energy growth (EMA, 2016d). This threshold covers power generationfrom renewables that vary for natural reasons (sunshine in the case of solar) and require fossil fuelfired generators as a backup.

Finally, the ‘Handbook for Photovoltaic (PV) Systems’ has been published by the EMA and the BCA
to facilitate the implementation of solar PV systems in Singapore. It provides information on
licensing, market and technical requirements, and building and structural issues related to solar
installations.

In terms of biodiesel production, Finnish oil refining and marketing company, Neste, built the world’s
largest diesel refinery in Singapore at a cost of EUR 550 million in November 2010. The refinery has a capacityof one million tonnes per annum and uses Neste’s proprietary NExBTL technology to produce renewablediesel products (Neste, 2018). In December 2017, Neste announced plans to expand its Singapore refinery byanother one million tonnes per annum. A final investment decision is expected to be reached at the end of
2018, with production at the new facility to begin in 2022 (Platts, 2017).
SUSTAINABLE DEVELOPMENT

Singapore’s IMCSD unveiled its first blueprint sustainable development on 27 April 2009. This plan contains
strategies and initiatives for achieving both economic growth and a good living environment for Singapore
over the next 20 years.
The document details new targets and initiatives to improve resource efficiency and to enhance
Singapore’s urban environment. Improved efficiency in the use of resources such as energy, water and land
will contribute to enhance the city-state’s competitiveness in the long run. Under the blueprint, efforts will be
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made to improve air quality, expand and open up green and blue spaces, conserve biodiversity, and enhance
public cleanliness. These efforts will contribute to making the city a more liveable and attractive place, even asSingapore continues to grow and develop. Targets have been set to measure the progress in these areas. The
blueprint has a 20-year timeframe, with identified key goals for 2030. The blueprint’s goal for the energy sector
is to reduce energy intensity by 35% by 2030 from 2005 levels, with an intermediate goal of 20% by 2020 fromthe 2005 levels (NEA, 2013).
In 2015, Singapore released ‘an extension of the efforts outlined in the 2009 edition’, namely, theSustainable Singapore Blueprint 2015 (MEWR, 2015). This document takes into consideration the feedback
obtained from more than 130 000 people of recent initiatives, including the Land Transport Master Plan 2013
and the Urban Redevelopment Authority’s Master Plan 2014 (MEWR, 2015). Its emphasis is on sustainablehousing and transportation aimed at reducing waste to zero through the reduction of consumption, recycling,reuse of all materials and the adoption of greener practices by businesses (MEWR, 2015). The objective is toturn Singapore into a ‘hub for the cutting-edge business of sustainable development’ and to achieve threeobjectives: a liveable and endearing home; a vibrant and sustainable city and an active and gracious community(MEWR, 2015).
As part of its sustainable development objective, Singapore has taken steps to increase the solar share of
its electricity generation. Among others, the EMA has adopted a policy of proactively enhancing the required
market and regulatory framework to facilitate the deployment of solar units (EMA, 2014d).
NUCLEAR ENERGY

Singapore currently does not have a nuclear energy industry. In 2010, the economy embarked on a prefeasibility study of nuclear energy to objectively evaluate the opportunities, challenges and risks of nuclear
energy and its feasibility as a long-term energy option for Singapore. The study, finalised in 2012, concluded
that nuclear energy technologies currently available, although safer than the older designs still in use in many
countries, were unsuitable for deployment in Singapore given the economy’s small size and high population
density (MTI, 2012).
CLIMATE CHANGE

Singapore is a small and completely urbanised city-state whose CO2 emissions account for less than 0.2% of
global emissions. The economy has made major progress in reducing its CO2 emissions although its options
for non-CO2 emitting energy are very limited (mainly confined to WtE and a very small amount of solar) andnuclear energy is not an option as mentioned earlier (EMA, 2014d).
Hence, in 2009, Singapore pledged in the context of the UNFCCC negotiations to reduce emissions by
16% from 2020 BAU levels in the event of a legally binding global agreement under which all countries will
implement their commitments. The economy set up the National Climate Change Secretariat on 1 July 2010as a dedicated agency under the Prime Minister’s Office to coordinate its domestic and international policies,
plans and actions on climate change (NEA, 2014). Singapore ratified the Paris Agreement in September 2016,
formalising its pledge to reduce emissions intensity by 36% from 2005 levels by 2030 and to stabilise emissions
with the aim of peaking around 2030.
Apart from increasing the share of solar in its power generation energy mix, it has significantly reduced
its grid-generated emissions through greater use of natural gas for electricity generation by increasing its shareof the power mix. Singapore has switched from fuel oil to natural gas as the main energy source for suchgeneration because it produces the least carbon emissions per unit of electricity generated, among fossil fuelfired power plants. By increasing the share of natural gas used in electricity generation from only 19% in 2000
to 95% in 2015, Singapore has substantially reduced its emissions growth over the past 10 years (NEA, 2014).
Singapore’s efforts have resulted in improving its average operating margin grid emission factor from 0.5255
kg CO2/kWh in 2005 to 0.4244 kg CO2/kWh in 2016 (EMA, 2017a).

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SINGAPOREN OTA B L E E N E RG Y D E V E L O P M E N T S
CARBON TAX FROM 2019

Following its climate change pledge, Singapore has been stepping up on efforts to reduce energy use andcarbon emissions. In 2017, the Government of Singapore announced the intention to implement a carbon tax
on the emission of greenhouse gases starting from 2019. This marks Singapore as the first Southeast Asian
economy to implement a carbon tax. The policy aims to enhance Singapore’s existing and planned mitigation
efforts under the Climate Action Plan, and stimulate clean technology and market innovation. In February
2018, the government finalised the details of the carbon tax mechanism as follows (Singapore Budget, 2018):


The carbon tax will generally be applied upstream, for example, on power stations and other large
direct emitters, rather than electricity users. The expected tax rate is between SGD 10 and SGD 20
per tonne of greenhouse gas emissions. Details are pending the results of industry consultation(NCCS, 2017be levied on all facilities producing 25 000 tonnes or more of greenhouse gas emissions
in a year. This represents about 30 to 40 large emitters that contribute 80% of Singapore’s greenhousegas emissions. The government will further assess how to account for the remaining 20% of theemissions.



The initial carbon tax rate is SGD 5 per tonne of greenhouse gas emissions for a five-year period
from 2019 to 2023. The government will review the rate by 2023, with an intention to increase it tobetween SGD 10 and SGD 15 per tonne of emissions by 2030, depending on international climatechange developments, the progress of Singapore’s emissions mitigation efforts and economic
competitiveness.

The carbon tax will apply uniformly to all sectors, without exemption. Taxable facilities will pay forthe carbon tax through the purchase of carbon credits corresponding to their emissions, with the firstpayment in 2020, based on their 2019 emissions.

Over the initial five-year period, the government expects to generate about SGD 1 billion in carbon
tax revenue. This will be used to support companies in improving energy efficiency, such as funding
existing green initiatives via the Productivity Grant (Energy Efficiency) and the Energy Efficiency
Fund.).
OPEN ELECTRICITY MARKETAs Singapore progresses towards a fully liberalised electricity market, a soft launch of the Open Electricity
Market will commence in April 2018. A total of 108 000 residential consumer accounts and 9 500 businessconsumer accounts in the Jurong area will be able to choose to buy electricity from a retailer with a price planthat best meets their needs. EMA will extend this choice and flexibility to consumers in the rest of Singapore
in the second half of 2018. This will involve 1.3 million accounts, mainly households (EMA, 2018).
SMART METERING TRIAL FOR UTILITIES CONSUMPTION

A pilot scheme will be conducted in the second half of 2018 to test technical solutions for remote metering
for utilities. The trial will leverage the existing automated meter reading system for electricity metres to coverwater and town gas meters. It will include the development of a mobile application to provide timely and useful
information to help them better manage their utility consumption (EMA, 2017d).
BUILDING SOLAR FORECASTING CAPABILITIES AND TEST-BEDDING ENERGYSTORAGE SYSTEMSIn October 2017, EMA and the SP Group awarded two consortiums to implement the economy’s first utilityscale Energy Storage System (ESS). CW Group and Red Dot Power will receive about $17.8 million in grants
to build this test-bed with an aggregate capacity of 4.4 MWh. The test-bed is expected to be operational forthree years to evaluate the performance of different ESS technologies under Singapore’s hot, humid and highly
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urbanised environment. ESS could support the deployment of intermittent generation sources (such as solar)
in Singapore by reducing peak demand and providing regulation reserves, which will in turn facilitate greater
deployment of solar power in Singapore (EMA, 2017e). EMA is also exploring the feasibility of combining
energy storage with solar forecasting capabilities. It awarded a SGD 6.2 million research grant to a consortium
led by the NUS to look into improving the accuracy of solar PV output forecasts and grid management using
techniques in weather prediction, remote sensing, machine learning and grid modelling (EMA, 2017c).
REGULATORY SANDBOX TO ENCOURAGE ENERGY SECTOR INNOVATIONSIn October 2017, EMA implemented a regulatory sandbox framework in the electricity and gas sectors. The
framework allows regulations to be relaxed, within defined parameters, in a sandbox that can accommodate
new products and services for testing. It will also allow EMA to assess the impact of new products and services
before deciding on the wider regulatory treatment (EMA, 2017f).
DEMAND-SIDE MANAGEMENT

In October 2016, EMA signed a Memorandum of Understanding with 16 partners for a pilot programme to
optimise energy consumption by managing demand. This pilot, known as Project OptiWatt, aims to test theviability of DSM. Through DSM, energy consumption can be shifted from peak to non-peak hour, thereby
reducing the maximum load that the energy system needs to cater to, yielding system-wide benefits. The project
partners comprise IHLs, government agencies, companies, electricity retailers, research institutions and theelectricity grid operator (EMA, 2017g).
POST-3 MTPA LNG IMPORT FRAMEWORKOn 30 June 2014, the EMA launched a competitive RFP process to appoint up to two importers to supply
Singapore with LNG beyond the first 3 Mtpa from Shell (previously BG Singapore Gas Marketing Pte. Ltd.).
The RFP was conducted in two stages and concluded in October 2016, with Pavilion Gas and Shell Eastern
Trading (Pte) Ltd being appointed as the next LNG importers for Singapore. Each of the companies wasawarded with an exclusive right to import and sell LNG in Singapore up to 1Mtpa each, or for a period of
three years, whichever is earlier (EMA, 2016e).
NEW GENERATION CAPACITY

On 26 October 2015, the NEA signed a WtE services agreement (WESA) with TuasOne Pte Ltd to build
Singapore’s sixth WTE plant scheduled to be operational in 2019 (NEA, 2015c). The plant will be Singapore’s
largest WTE plant with the capacity to incinerate 3 600 tonnes of waste per day to generate 120 MW ofelectricity per day. TuasOne Pte Ltd is a company formed by the consortium of Hyflux Ltd and Mitsubishi
Heavy Industries Ltd. This is the second WtE plant that the NEA has awarded to a private enterprise to design,build, own and operate under the Public-Private Partnership (PPP) scheme after the Keppel Seghers Tuas
WTE plant, which became operational in 2009.
Singapore’s major power-generation companies are Senoko Energy, YTL Power Seraya, Tuas Power
Generation, SembCorp Cogen, Keppel Merliamu Cogen, PacificLight Power and Tuaspring. PacificLightPower and Tuaspring are the most recent generation plants added to the economy. PacificLight Power started
operations in June 2014 as Singapore’s first fully LNG-operated power plant. This state-of-the-art 800 MW
plant was built at a cost of USD 1.2 billion. The Tuaspring cogeneration plant, which combines power andwater desalination facility, commenced operations in August 2015.

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SINGAPORE–– (2017f), Launch of Regulatory Sandbox to Encourage Energy Sector Innovations,
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HDB (Housing & Development Board) (2014), SolarNova, http://www.hdb.gov.sg/cs/infoweb/aboutus/our-role/smart-and-sustainable-living/solarnova-page.
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LTA (Land Transport Authority) (2014), Joint News Release by the Land Transport Authority & EDB on EV Phase
2 – Share an Electric Car, https://www.lta.gov.sg/apps/news/page.aspx?c=2&id=b1f98bcd-e4fc-49029f9d-08bc2309c3df.
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2020,
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MEWR (Ministry of Environment and Water Resources) (2014), Inter-Ministerial Committee on Sustainable
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Project at Solar Pioneer Awards Ceremony, https://www.nccs.gov.sg/news/singapore-announces-regionsfirst-floating-photovoltaic-pilot-project-solar-pioneer-awards.
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SINGAPORE–– (2016), Industry Energy Efficiency Technology Roadmap,
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NEA (National Environment Agency) (2013), Insights of NEA, www.nea.gov.sg/data/htm/sr12/toether-westand/sustainability-in-our-policies-n-public-initiatives.html.
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http://www.nea.gov.sg/training-knowledge/singapore-environment-institute/sei.
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NRF (National Research Foundation) (2014a), Energy Technology Roadmaps,
https://www.nrf.gov.sg/programmes/national-innovation-challenges/energy-technology-roadmaps.
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NUS (National University of Singapore) (2015), Energy Innovation Research Programme (EIRP)
http://www.nus.edu.sg/dpr/energy/funding-opportunities.html.
Platts (2017), Neste announces new biofuels capacity to be based in Singapore, https://www.platts.com/latestnews/agriculture/london/neste-announces-new-biofuels-capacity-to-be-based-26855462.
PUB (Public Utilities Board) (2017), PUB studying clean energy solutions from blue spaces,
https://www.pub.gov.sg/news/pressreleases/pubstudyingcleanenergysolutionsfrombluespaces.
SEAS (2017), About SMEEE Initiative, http://www.seas.org.sg/SME3/index.php/about-smeee-initiative/.
Singapore Budget (2018), Budget 2018,
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SingStat (Singapore Department of Statistics) (2017), Singapore in Figures 2017,https://www.singstat.gov.sg/docs/default-source/default-documentlibrary/publications/publications_and_papers/reference/sif2017.pdf.
SLNG (Singapore LNG Corporation) (2014), Terminal Development,
https://www.slng.com.sg/Website/content.aspx?mmi=60&smi=61&sdmi=0&pr=1&prid=71.
The Business Times (2014), Gas swap sees S'pore-bound PNG re-routed to Indonesia,
http://www.businesstimes.com.sg/top-stories/gas-swap-sees-spore-bound-png-re-routed-to-indonesia.
The Straits Times (2016), October roll-out for all-electric fleet of taxis,
http://www.straitstimes.com/singapore/transport/october-roll-out-for-all-electric-fleet-of-taxis.

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SINGAPOREUSEFUL LINKS

Department of Statistics Singapore—www.singstat.gov.sg
Economic Development Board—www.edb.gov.sg/
Energy Efficiency Programme Office—http://www.e2singapore.gov.sg/
Energy Market Authority—www.ema.gov.sg
Housing & Development Board—http://www.hdb.gov.sg/cs/infoweb/homepage
Land Transport Authority—www.lta.gov.sg
Ministry of National Development—http://app.mnd.gov.sg/
Ministry of the Environment and Water Resources—www.mewr.gov.sg
Ministry of Trade and Industry—https://www.mti.gov.sg
National Environment Agency—www.nea.gov.sg
National Climate Change Secretariat—https://www.nccs.gov.sg/
Singapore LNG Corporation (SLNG)—www.slng.com.sg/website/index.aspx
Solar Energy Research Institute of Singapore (SERIS)—www.seris.nus.edu.sg
Temasek Holdings—www.temasekholdings.com.sg

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CHINESE TAIPEICHI NES E TAI P EII N T ROD U C T I ON

Chinese Taipei is an archipelago comprising Taiwan, Penghu, Kinmen and Matsu, located off the southeast
coast of China and the south-west coast of Japan. With an area of 36 193 square kilometres (km2) (Departmentof Statistics, Ministry of the Interior, 2018), Chinese Taipei represents a natural gateway to East Asia. Although
only one-quarter of the land is arable, the subtropical climate permits multi-cropping of rice and the perennial
growth of fruit and vegetables.
In 2015, Chinese Taipei’s gross domestic product (GDP) was USD 1 002 billion and its per capita income
was USD 42 684 (2010 USD purchasing power parity [PPP]). Its GDP grew on an average at a rate of 3.6%
during 2000–15. Within the past few decades, Chinese Taipei’s economic structure has substantially changed,
shifting from industrial production to the services sector, wherein the latter constituted 63% of the GDP,followed by industry (35%) and agriculture (1.7%) in 2015 (BOE, 2017a). Chinese Taipei is one of the mostdensely populated areas in the world, but its population growth rate has been relatively flat; the economy’s
population of 23 million grew at a rate of 0.4% during2000–15 (EGEDA, 2017).
Lacking natural resources, Chinese Taipei is highly dependent on energy imports in order to meetdomestic energy demand. According to the U.S. Energy Information Administration, Chinese Taipei holds
only 2.4 million barrels of oil reserves (EIA, 2016). Coal reserves in the economy are rather scarce, and owing
to the high mining cost, there has been no coal production in the economy since 2000.
Table 1: Key data and economic profile, 2015
Key data a, b

Energy reserves c

Area (km2)

36 197

Population (million)

23

Oil (million barrels)Gas (billion cubic metres)

2.4
N/A

GDP (2010 USD billion PPP)

1 003

Coal (million tonnes)–

GDP (2010 USD PPP per capita)

42 684

Uranium (kilotonnes of U)–

Sources: a Department of Statistics, Ministry of the Interior (2018); b EGEDA (2017); c EIA (2016).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLYAs mentioned earlier, Chinese Taipei heavily relies on overseas energy resources for its needs. In 2015,
imported energy accounted for 98% of the total energy supply in Chinese Taipei (BOE, 2017a), indicating a
low energy self-sufficiency rate as well as a fragile energy security.
The growth of Total Primary Energy Supply (TPES) in Chinese Taipei is stable and has remained
unchanged over the past few years, increasing 2.3% from 106 514 kilotonnes of oil equivalent (ktoe) in 2012
to 108 970 ktoe in 2015. Regarding the composition of the TPES, fossil fuels continue to be the dominant fuelconsisting of 89% of the total supply. By fuel type, oil contributes the largest share (39%), followed by coal
(33%), natural gas (17%), renewable energy (RE) (2.4%) and other fuels (8.7%) (EGEDA, 2017).
In 2015, Chinese Taipei imported nearly 308 million barrels of crude oil, 2.4% lower than the 315 million
barrels imported in 2014. The Middle East is the major supplier, accounting for 86% of the total oil imports,
followed by Angola (8.1%) (BOE, 2017a). To prevent supply disruption, the Petroleum Administration Act
2001 requires Chinese Taipei’s refiners to maintain stocks of more than 60 days of sale volumes.
Regarding coal, Australia and Indonesia are the major suppliers accounting for 47% and 36%, respectively,of the total coal imports totalling up to 54 million tonnes in 2015. Most of this fuel is used for power generation.
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Because indigenous natural gas only accounts for 1.7% of the total natural gas supply in Chinese Taipei,
almost the entire gas demand is met by liquefied natural gas (LNG) imports. Qatar, Indonesia and Malaysia are
the largest suppliers, accounting for 47%, 17% and 16% of the supply, respectively, in 2015. The total LNG
import in 2015 was 14.2 million tonnes (Mt), 7.6% higher than the 13.2 Mt imported in 2014 (BOE, 2017a).
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

12 414

Industry sector

22 250Net imports and others

101 035

Transport sector

12 161

Thermal

207 861

Total primary energy supply

108 970

Other sectors

12 251

Hydro

7 505

Coal

35 939Non-energy

22 642

Nuclear36 471

Oil

42 699Final energy consumption*

46 681Others

6 183

Gas

18 221

Coal

6 869

Renewables

2 606

Oil

16 406

Others

9 504

Gas

3 142

Renewables

Total power generation

258 020

291

Electricity and others

19 974

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.

In 2015, electricity generation in Chinese Taipei reached 258 026 gigawatt-hours (GWh). Of the total
electricity production, the hydropower generated by the Taiwan Power Company (TPC) comprised 2.9%,
thermal power 51% (23% coal, 4.5% oil and 23% LNG), nuclear power 14%, wind power 0.28%, cogeneration
15% and independent power producers (IPPs) 17%. In terms of the generating capacity, the TPC dominates
Chinese Taipei’s electric power sector with 65% and IPPs account for 18% of the total capacity. IPPs are
required to sign power purchase agreements with the TPC, which distributes power to consumers. To expand
foreign participation, in January 2002, the government permitted foreign investors to own up to 100% of an
IPP (BOE, 2017a).
FINAL ENERGY CONSUMPTION

The total final consumption in Chinese Taipei was 69 304 ktoe in 2015, 1.6% higher than that in 2014. The
non-energy sector is the largest energy consumer with 33%, which is mostly used by chemical andpetrochemical industries. The second largest energy consumer is the industrial sector accounting 32% of thetotal energy used, followed by the transport sector (18%) and other sectors, including residential and services,which consumed 18% of the total energy used. By energy source, electricity and others accounted for 43% of
the final energy consumption (excluding non-energy), followed by oil (35%), coal (15%), gas (6.7%) and RE(0.6%) (EGEDA, 2017).
ENERGY INTENSITY ANALYSISIn terms of energy intensity by the TPES, Chinese Taipei showed an improvement with a reduction of 2.1%,
declining from 111 tonnes of oil equivalent per million USD (toe/million USD) in 2014 to 109 toe/million
USD in 2015. However, energy intensity in terms of the total final consumption showed a 1% increase from68 toe/million USD in 2014 to 69 toe/million USD in 2015, which shows the transformation is more efficient
now.

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Table 3: Energy intensity analysis, 2014 vs 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

111

109

–2.1

Total final consumption

68

69

1.0

Final energy consumption excl. non-energy
consumption

46

47

1.5

Source: EGEDA (2017).
RENWABLE ENERGY SHARE ANALYSIS

Chinese Taipei has been promoting the use of RE to reduce carbon emission as well as to increase power
generation. The use of modern RE, including use for heat and electricity, increased by 12% from 1 200 ktoe
in 2014 to 1 349 in 2015. The share of modern RE to final energy consumption also showed an increase from
2.6% in 2014 to 2.9% in 2015.
Table 4: Renewable energy share analysis, 2014 vs 2015
2014
Final energy consumption (ktoe)

Change (%)
2014 vs 20152015

45 70046 681

2.2

44 50045 332

1.9

Traditional biomass*

0

0

0

Modern renewables*

1 200

1 349

12

Share of modern renewables to final energy
consumption (%)

2.6%

2.9%

10%

Non-renewables (fossils and others)

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal and so on) including biogas and wood pellets are
considered modern renewables although data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKThe Bureau of Energy (BOE) was established under the Ministry of Economic Affairs (MOEA) in 2004 andis responsible for formulating and implementing Chinese Taipei’s energy policy. To cope with the austereenergy situations in Chinese Taipei, the new government elected on 20 May 2016 announced a new policy‘New Energy Policy’ on 25 May 2016 (BOE, 2016). Later in April 2017, the MOEA revised ‘Guideline on
Energy Development’ released in 2012 (BOE, 2017b).
The main vision of ‘New Energy Policy’ is to initiate energy transition and reform power market
regulation. It has two main objectives:
1.

Enlarge clean energy share of power mix: increase RE share to 20% and natural gas share to 50% of
the total power mix in 2025. Reduce coal share of total power mix to 30% in 2025.

2.

Nuclear-free homeland: decommission the three existing nuclear plants when their authorised 40year lifespans expire between 2018 and 2025. Achieve nuclear-free homeland in 2025.
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CHINESE TAIPEIThere are nine major strategies under ‘New Energy Policy’, including the following:

to stabilise power generation source and strengthen consumption management, ensuring stability of
power supplyto promote energy efficiency and energy savingsto diversify energy mix especially developing clean energyto accelerate energy-saving system and strengthen the stability of power grid

to promote smart grid and smart meter

to integrate domestic resources and a system to promote clean energy

to reform power market regulation and improve power supply efficiency and quality

The revised ‘Guideline on Energy Development’ serves as the superior policy guidance for national energy
development, energy policy programmes, standards and action plans. The Guideline is based on paragraph 2
of Article 1 in the ‘Energy Administration Act’; it aims to ensure balanced development in energy security,
green economy, environmental sustainability and social equity to achieve nuclear-free homeland target by 2025
as well as to attain the sustainable energy development. There are four main guiding principles:Energy security: strengthen energy saving on the consumption side, such as adopting a new
economic development model of ‘Innovation, Employment and Equitable Distribution’ to continue
with the optimisation and transition of industrial structure. To diversify the energy mix and increase
the share of self-produced energy as well as expand RE installation to enhance the supply and securityof low-carbon energy. To establish smart system integration including the deployment of smart
meters and the promotion of an overall improvement of regional power transmission anddistribution systems.

Green energy: construct a green energy industrial ecological system, including regulatory incentives,
lad acquisition, financing mechanism and so on. Establish environmental costs pricing mechanism
through policy tools or market mechanism such as cap and trade and create new green service
economy in order to foster green production and green energy investment. Promote regional green
energy application, and, in particular, integrate the development of smart cities and agriculture
villages in conjunction with opportunities of Internet-of-Things development. Innovate in green
energy and carbon-reduction technologies, strengthen the research and development (R&D) of
technologies and the deployment of energy storage and smart gird as well as accelerate thedevelopment of a cloud intelligent energy management system.

Environmental sustainability: improve the air quality by taking the cap of total emissions from air
pollutants as the basis for the planning of new power plants. Select an appropriate site for energy
facility construction to avoid or reduce the impacts on environmentally sensitive areas. Continue
greenhouse gas (GHG) emissions control and the reduction to establish a low-carbon environment.
Achieve nuclear-free homeland target while proposing plans for short-, mid- and long-term
management and disposal policies for high-level and low-level radioactive wastes.

Social equity: promote energy democracy and justice by establishing mechanisms and incentives
for public participation and risks communication as well as to introduce the participatory governanceapproach to energy policy making. Additionally, the government should contribute to equity within
and across generations while assuring the basic energy services for vulnerable groups and the equity
and justice in energy use to avoid energy poverty. Promote domestic power market reform byphases, aiming to achieve the goal of ‘diversified supply, equity in usage and freedom of choice’.

The Guideline also announced to formulate an ‘Energy White Paper’ as a promoting mechanism forenergy transition. The ‘Energy White Paper’ will include more detailed measures and policy tools for futureenergy development. The government aims to submit an annual accomplishment report to summarise theachievements and conduct periodic review for every five years.

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APEC ENERGY OVERVIEW 2017

CHINESE TAIPEIENERGY SECURITY

As Chinese Taipei heavily relies on energy imports, the government has put in multiple measures to enhanceenergy security. In terms of oil supply, the Petroleum Administration Act requires refiners and importers tomaintain 60 days of sales volumes (calculated from the average domestic sales and private consumption overthe preceding 12 months) as stockpiles. The government uses the petroleum fund to finance the storage of oil
and also stockpiles 30 days of oil consumption. The Act mandates that a liquid petroleum gas stockpile lasting
more than 25 days be maintained (BOE, 2017c).
For many years, the Chinese Petroleum Corporation (CPC) has engaged in cooperative exploration withgovernments and large international oil companies in operations throughout the Americas, the Asia-Pacificregion and Africa under the banner Overseas Petroleum and Investment Corporation. As onshore oil and gas
resources might be depleting in 10 years, CPC has made strenuous efforts to develop upstream explorationand conducted acquisitions to secure oil and gas sources. Thus far, CPC has discovered an appraisal well in
Chad, which is estimated to contain 1.6 million barrels of crude oil and another four exploration wells with oil
and gas in Niger, which are estimated to contain 2.3 million barrels of crude, totalling up to 3.9 million barrelsof crude oil for the company. In line with the government’s policy of deepening energy supply safetymechanisms and promoting international energy cooperation, the CPC has engaged in international
cooperation in exploration and development with the hope of discovering new reserves of oil and natural gas.
As of the end of 2016, this cooperation extended to 22 fields spread over eight economies and countries,
totalling up to 1 142 producing wells.
Within Chinese Taipei, CPC completed two-dimensional (2D) seismic surveys over 82 km in Pingtung
Plain, a precise gravity survey of the Fongshan mud structures and geological surveys of 73 km2, in addition to
repairing three production wells in 2016. There are currently 33 oil and gas producing wells spreading over
Chan Mountain and Qing Cao Lake in Taichung City, Jing Shui and Chu Kuang Keng in Miaoli Prefecture andGuang Tien in Tainan City, yielding 320 million cubic metres of natural gas and 8 446 kilolitres (kL) of
condensate annually.
For offshore exploration, CPC cooperates with Canada’s energy company Husky Energy on a deep-water
exploration in Tainan Basin. Pre-Stack Depth Migration on 2D seismic surveys was completed in 2016. A
three-dimensional seismic survey is scheduled to be conducted during the second quarter of 2017. Additionally,
CPC collaborates with National Taiwan University and National Cheng Kung University on a government
contract project to evaluate the potential oil and gas resources in the East China Sea and the South China Sea(CPC, 2017).
ENERGY MARKETSELECTRICITY MARKETSThe government of Chinese Taipei aims to secure a total electricity supply with a reserve capacity of 15%(BOE, 2017c) based on peak consumption. As a state-owned power company, TPC is responsible for power
supply in Chinese Taipei according to the Electricity Act. As of the end of 2016, the installed capacity of TPC
is 42 130 MW, mainly comprising thermal power generation and nuclear power generation as well as pumped
hydro power and RE (TPC, 2017). In the end of 1980s, TPC’s power plant construction was delayed becauseof protests, which led to 36 times the restriction on electricity use during 1991 and 1994 (BOE, 2017d).
In January 1995, the MOEA announced an invitation to the private sectors to participate in power
generation as IPPs. The electricity produced by IPPs must be sold to TPC through its transmission lines. There
are four stages of opening the IPPs from 1995 to 2006. As of end of 2016, there were two coal-fired IPPs,
seven gas-fired IPPs, three hydro IPPs, nine solar-photovoltaic (PV) IPPs and 12 wind-power IPPs (BOE,
2017d).
To become a nuclear-free economy and to achieve the goals stipulated in the Greenhouse Gas Reduction
and Management Act by reducing GHG emissions to 50% below 2005 levels by 2050, the MOEA formulated
a two-stage plan to amend the Electricity Act. The premise of amendment is to ensure stable power supply,
and the goals are 1) multiple supplies and green energy first; 2) fair usage for the electricity grid and 3) free
power purchasing choices for users (BOE, 2017c).

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CHINESE TAIPEIThe first stage amendment includes amendment of three enterprises: generating enterprise, transmission
and distribution enterprise and retailing enterprise (BOE, 2017c).
Generating enterprise: RE-generating corporations can sell electricity in three different ways:
wholesale, wheeling and direct supply. The traditional generating corporation is not allowed tosell the electricity to the end user and can only sell to a retailing utility corporation.

Transmission and distribution enterprise: a utility corporation installs the powertransmission and distribution networks to wheel the electric power. No more than one stateowned corporation and the scope of its business operation covers the entire economy. These areresponsible for fair dispatch and to be a ‘common carrier’.

Retailing enterprise: RE-retailing corporations can only purchase electricity generated by REgeneration equipment for wheeling to the users. A retailing utility corporation is a public utility
company and has the obligation to supply.

The second stage amendment will allow the new traditional generating corporation, joined in the firststage, to perform wheeling and direct supply to customers, introducing generation market competition andallowing the general retail companies to set up. The traditional generating corporation existing before the firststage of the amendment still can only sell their electricity to the retailing utility corporation. However, thesecond stage will not start until the mechanism and the operations of the first amendment are mature.
FISCAL REGIME AND INVESTMENT

Chinese Taipei has limited indigenous energy resources, and thus, it has no formal policy on investment in
upstream assets. However, to secure new energy sources, Chinese Taipei has invested in oil exploration bothin the Taiwan Strait and abroad through the state-owned enterprise—the CPC. Chinese Taipei also welcomesthe participation of foreign investors in bidding on the IPP electricity market.
ENERGY EFFICIENCYAs a promoting mechanism of ‘Guideline on Energy Development’, BOE started drafting an ‘Energy White
Paper’ to help facilitating energy transition. In February 2018, BOE released the ‘Energy Saving Target andRoadmap’ implementation plan, aiming to improve energy intensity by 2.4% every year and electricity intensity
improved by 2% every year between 2017 and 2025. The roadmap includes implementation plans in four
sectors: commercial, industrial, building and transport. It is expected to save 5 Mtoe or 16.5 TWh in 2025 ascompared to 2016 (BOE, 2018a). The energy-saving roadmaps of each sector are as follows:Commercial sector


Target: improved energy efficiency in the commercial sector and the setup of a local energy-saving
mechanism. They expect to save 6.5 TWh electricity and 33 ktoe in 2025 compared to 2016.

Roadmap: promote energy audit and provide energy-saving counselling for the services subsector.
Improve energy efficiency management for the commercial sector. Strengthen basic energy-saving
measures in local areas and increase public participation (BOE, 2018b).

Industrial sector


Target: reduce energy intensity in the industrial sector by 45% in 2025 compared to 2005. Reduce 2.3
Mtoe in during the period 2016–25. Reduce 7 million tonnes of carbon dioxide (CO2).

Roadmap: promote energy-intensive industries transition, such as improving manufacturing
processes and retrofitting factories as well as using more low-carbon fuels. Provide energy-saving andcarbon-reduction counselling services for manufacturers. Promote regional resources integration andsetup an incentive mechanism for energy saving (BOE, 2018c).

Building sector


Target: improve energy-savings design index for new buildings by 10%, add 500 green building
materials and candidate certificates every year. Strengthen current energy-saving measures of existingbuildings. Reduce 636 ktoe or 31 TWh in the building sector in 2025 compared to 2016.
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

CHINESE TAIPEIRoadmap: improve energy-saving-related regulations and measures for buildings. Subsidise local
governments with green building random inspection. Promote transparency of building energy
information. Develop cloud-energy-saving simulation estimation tools for buildings. Conduct
feasibility studies of zero-energy buildings (BOE, 2018d).

Transport sector


Target: reduce 850 000 kilolitres of gasoline use, 104 000 kilolitres of diesel use in 2020 compared tothat in 2017. Increase electricity by 0.4 TWh in 2020 compared to 2017. Reduce 2 million tonnes of
CO2 in the transport sector in 2020 compared to 2017.

Roadmap: eliminate 80 000 Type I (more than 24 years) and Type II (18–24 years) diesel vehicles in2019 by subsidising their replacement on the basis of vehicle type and years during 2017–19 with anamount of NTD 30 000–400 000. Increase highway public transport by 2% in 2020 compared to that
2015—1.2 billion people. Improve fuel economy standards for motorcycles by 10%, passenger car
by 30% and truck by 25% in 2022 compared to those in 2014. Complete the electrification of roundthe-island railway in 2022. Complete the electrification of 10 000 buses in Taipei in 2030. Stop selling
non-electric motorcycles in 2035 and non-electric cars in 2040 (BOE, 2018e).
RENEWABLE ENERGY

The two main RE sources in Chinese Taipei are PV systems and wind power. To promote RE, the government
announced the ‘Renewable Energy Development Act’ in July 2009. The core strategy of the Act is Feed-inTariff (FiT) system. The current tariff is effective for 20 years with annual review.
Table 5: Feed-in-Tariff in Chinese Taipei
Capacity (kW)2016 FiT (US¢/kWh)

2017 FiT (US¢/kWh)≥1~<20

20.3

19.07

≥20~<100

16.3

15.56

≥100~<500

15.0

14.18

≥500

14.6

13.78

Ground Type



14.6

14.2

Floating Type





15.4

≥1~<20

26.6

28.0

≥20

8.78

8.99

Offshore



17.9

18.89

Hydropower

Stream Type



9.09

9.22

Geothermal





15.4

15.4

No biogas
equipment



8.49

8.12

With biogas
equipment



12.3

15.7

RDF





9.2

14.4

Others





8.5

8.13

Item

Type

Roof Type
PV

Wind Power

Biomass

OnshoreSource: (ITRI, 2017).

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CHINESE TAIPEIRE development in Chinese Taipei is aiming to increase renewable supply and achieve 20% of
renewable electricity generation by 2025 with 27 423 MW.
Table 6: Renewable Energy Target by 2025
Power Capacity (MW)Electricity Generation (TWh)2016

2020(f)2025(f)2016

2020(f)2025(f)Solar PV

1 210

6 500

20 000

1.1

8.1

25.0

Onshore Wind

682

800

1 200

1.4

1.9

2.9

Offshore Wind



520

3 000



1.9

11.1

Geothermal



150

200



1.0

1.3

Biomass

741

768

813

3.6

5.6

5.9

Hydro Power

2 089

2 100

2 150

6.6

4.7

4.8

Fuel Cell



22.5

60



0.2

0.5

Total

4 722

10 86127 423

12.7

23.4

51.5

Source: (ITRI, 2017).
PHOTOVOLTAIC SYSTEMS

There are short- and long-term plans for PV promotion projects. In the short-term plan, the strategy is toestablish a foundation, and therefore, BOE proposed a ‘Two-Year Solar PV Promotion Project’ in 2016 witha target of 910 MW for rooftop type and 610 MW for ground type, totalling up to 1 520 MW of solar PV
installation capacity. The long-term plan is to improve the environment and expand the installation over the
economy with establishing fundamental measure. The target is to reach 6.5 GW in 2020 and 20 GW (3-GW
rooftop and 17-GW ground system) in 2025 (ITRI, 2017).
WIND POWER SYSTEMS

The wind power promotion project is divided into two parts—onshore wind power and offshore wind power.
For onshore wind power, the strategy is to develop best wind farms and then secondary ones. By the end of
2016, Chinese Taipei installed 682 MW of onshore wind turbines and will continue to expand the installation
capacity to reach the target of 1 200 MW in 2025. For offshore wind power, the government already installed
8 MW of demonstration offshore wind turbines, it is expected to install up to 520-MW wind farms in shallow
sea area and then develop wind farms in deep sea area to reach the target of 3 000 MW in 2025 (ITRI, 2017).
NUCLEAR ENERGY

Currently, there are four nuclear power plants in Chinese Taipei, of which, three are operational and one issealed. In 2015, the total installed capacity of the three operational nuclear power plants was 5 144 MW withan output of 36 471 GWh accounting for 14% of the economy’s total power generation mix, 3% lower thanin 2013.
In 2011, the nuclear disaster at Fukushima led to public fears regarding nuclear safety in Chinese Taipei.
The government at the time released an energy policy aimed at steadily reducing nuclear dependence bylowering electricity consumption and peak loads and by promoting alternative energy sources to ensure a stable
power supply. In 2016, the newly elected government released the ‘New Energy Policy’, reassuring a nuclearfree homeland in 2025. This policy prohibits life-span extensions for existing nuclear plants and outlines adecommissioning plan as follows: Units 1 and 2 of the first plant will be decommissioned in 2018 and 2019;
Units 1 and 2 of the second plant in 2021 and 2023 and Units 1 and 2 of the third plant in 2024 and 2025.

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CHINESE TAIPEICLIMATE CHANGE
GREENHOUSE GAS EMISSIONS

Chinese Taipei produces CO2 emissions that account for about 1% of the global emissions. Therefore, thegovernment believes that it has a moral obligation to reduce emissions although the economy is not a memberof the United Nations and is consequently not eligible to sign the Kyoto Protocol. It is also not directly required
to adhere to the emissions reduction requirements. Unlike other UN members, Chinese Taipei is unable toconduct carbon emissions trading in the international market to achieve cross-border cooperation in carbon
reduction or to pursue cost-effective carbon-reduction plans. It is therefore necessary for Chinese Taipei toseek alternative ways to reduce the impact of its carbon emissions.
Chinese Taipei has followed the UN Framework Convention on Climate Change as well as its domestic
Basic Environment Act and Greenhouse Gas Reduction and Management Act (hereafter referred to as theGreenhouse Gas Act) in proposing its Intended Nationally Determined Contribution (INDC) to cutting GHG
emissions. This has demonstrated Chinese Taipei’s ambition to actively and steadily reduce its carbon emissions
and use of nuclear energy (Executive Yuan, 2015).
The government’s INDC goal is for Chinese Taipei’s 2030 GHG emissions to be 50% lower than what
they would be if it conducted business as usual and 20% lower than its 2005 total. This should pave the way
for meeting the ultimate target stipulated by the Greenhouse Gas Act: reducing annual GHG emissions to lessthan half of the 2005 levels by 2050 (Executive Yuan, 2015).

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CHINESE TAIPEIREFERENCES

BOE (Bureau of Energy, Ministry of Economic Affairs) (2016), New Energy Policy,
https://www.moeaboe.gov.tw/ECW/populace/content/wHandMenuFile.ashx?file_id=7.
–– (2017a), Energy Statistics Handbook 2015,
https://www.moeaboe.gov.tw/ECW_WEBPAGE/FlipBook/EnergyStaHandBook/mobile/index.ht
ml#p=I.
–– (2017b), Guideline on Energy Development,
https://www.moeaboe.gov.tw/ECW/populace/content/wHandMenuFile.ashx?file_id=1206.
–– (2017c), 2016 Annual Report,
https://www.moeaboe.gov.tw/ECW/populace/content/wHandMenuFile.ashx?file_id=4146.
–– (2017d), Basic Information of Current Independent Power Producer and Current Situation,
https://www.moeaboe.gov.tw/ecw/populace/content/Content.aspx?menu_id=999.
–– (2018a), Energy Saving Target and Roadmap,
http://energywhitepaper.tw/upload/201802/151843222656995.pdf.
–– (2018b), Energy Saving plan in Commercial Sector,
http://energywhitepaper.tw/upload/201802/151843221405172.pdf.
–– (2018c), Energy Saving plan in Industrial Sector,
http://energywhitepaper.tw/upload/201802/151842709071313.pdf.
–– (2018d), Energy Saving plan in Building Sector,
http://energywhitepaper.tw/upload/201802/151840815773508.pdf.
–– (2018e), Energy Saving plan in Transport Sector,
http://energywhitepaper.tw/upload/201802/151841828648775.pdf.
CPC (Chinese Petroleum Corporation) (2017), CPC 2017 Annual Report,
http://www3.cpc.com.tw/CpcAnnual/2017/C/2017CPC-tw.html.
Department of Statistics, Ministry of the Interior (2018), Statistics Database (in Chinese),
http://statis.moi.gov.tw/micst/stmain.jsp?sys=100.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), website ‘APEC
Energy Database’ page, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
EIA (Energy Information Administration) (2016), International Analysis - Taiwan,
http://www.eia.gov/beta/international/analysis.cfm?iso=TWN.
Executive Yuan, R.O.C (2015), Taiwan on track to greenhouse gas reduction,
http://www.ey.gov.tw/pda_en/News_Content.aspx?n=1C6028CA080A27B3&sms=E0588283EFAA
02AD&s=A30BD9B8A63AC3D3.
ITRI (Industrial Technology Research Institute) (2017), Taiwan’s Renewable Energy Policy Development, Challenges
and Outlook (Seminar material from the 13th Japan-Taiwan Joint Seminar on Energy Cooperation 2017)
TPC (Taiwan Power Company) (2017), Taiwan Power Company Sustainability Report 2017,https://www.taipower.com.tw/upload/319/2017122614261936536.pdf.

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APEC ENERGY OVERVIEW 2017

CHINESE TAIPEIUSEFUL LINKS

Bureau of Energy, Ministry of Economic Affairs—www.moeaboe.gov.tw
Chinese Petroleum Corporation—www.cpc.com.tw
Directorate General of Budget, Accounting and Statistics, Executive Yuan—www.dgbas.gov.tw
Ministry of Economic Affairs—www.moea.gov.tw
Taiwan Power Company—www.taipower.com.tw

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T H AI L AN D

THAILANDI N T ROD U C T I ON

Thailand is known as ‘the window to Southeast Asia’ as it is surrounded by fast-growing economies such as
Myanmar, the Lao People’s Democratic Republic and Cambodia to the north and east, and Malaysia to thesouth. Thailand has an area of 513 120 square kilometres (km2) and had a population of about 69 million in
2015. Its gross domestic product (GDP) that year reached USD 1025 billion (2010 USD purchasing power
parity [PPP]), a 2.9% increase from USD 996 billion in 2014. In the same period, the GDP per capita
increased 2.6%, from USD 14 553 (2010 USD PPP) to USD 14 928 (2010 USD PPP). The largest
contributors to its GDP were services (55%) and industry (36%) (UN, 2017).
Thailand has limited energy resources. At the end of 2016, Thailand had proven reserves of 405 million
barrels of oil (Mbbl), 220 billion cubic metres (bcm) of natural gas and 1 036 million tonnes (Mt) of coal.
Based on its production rate in 2016, it will deplete its domestic supply very soon―oil resources within two
years and natural gas in five years (BP, 2017). Most coal in Thailand is lignite, which is a low ranking coalwith high emissions. Notwithstanding its resources, Thailand is highly dependent on energy imports,
particularly oil, with about 84% of its oil and 25% of its gas supply coming from imports. (EPPO, 2017).
Table 1: Key data and economic profile, 2016
Key dataa, bEnergy reservesc

Area (km2)

513 120

Population (million)69

Oil (million barrels)405

Gas (billion cubic metres)

220

GDP (2010 USD billion PPP)

1025

Coal (million tonnes)

1036

GDP (2010 USD PPP per capita)

14 928Uranium (kilotonnes U)–

Sources: a UN (2017); b EGEDA (2017); c BP (2017).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Thailand’s total primary energy supply in 2015 was 130 916 kilotonnes of oil equivalent (ktoe), which
represented a decrease of 2.1% from 2014. Oil accounted for 39% of the total primary supply, while gas,coal and others accounted for roughly 32%, 9% and 20%, respectively. As most of Thailand’s proven coalreserves are lignite coal with lower calorific values, imported stock is needed to meet the energy demand forboth the power and industry sectors. In 2015, coal supply was 11 746 ktoe, down 10% from the previous
year.
Natural gas supply in 2015 was 41 661 ktoe, a 0.2% decrease from 41 753 ktoe in 2014. Althoughnatural gas is used mostly for power generation in Thailand, it is also promoted in the transport sector as areplacement for conventional petroleum products, such as diesel and gasoline. Thailand has increased its
reliance on imported natural gas, both in the form of piped gas and liquefied natural gas (LNG).
In 2015, total electricity generation was 184 350 gigawatt-hours (GWh). Thermal generation, mostly
from natural gas and coal, accounted for nearly all of its power generation (92%), with hydropower andothers accounting for the rest. In addition to its domestic capacity, Thailand purchased power from the Lao
People’s Democratic Republic and Malaysia.

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T H AI L AN D

Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Power generation (GWh)

Indigenous production

76 754

Industry sector

28 125

Net imports and others

63 385

Transport sector

25 595

Thermal

170 073

Total primary energy supply

130 916

Other sectors

21 679

Hydro

3 838

Coal

11 746Non-energy

10 950

Nuclear0

Oil

50 530

Final energy consumption*

75 399Others10 439Gas

41 661

Coal

4 403

Renewables

25 934

Oil

35 225

Others

1 045

Gas

6 070

Renewables

14 103

Electricity and others

15 598

Total power generation

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This isdifferent from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid
waste used in power plants is assumed to be comprising renewables.
NATURAL GAS

Thailand’s proven gas reserves at the end of 2016 amounted to 6.8 trillion cubic feet (Tcf), consisting of 6.6
Tcf in gas fields in the gulf and 0.23 Tcf in onshore areas. Compared with the previous year, the proven gas
reserves fell by 0.47 Tcf (about 6.49%). Although higher production efficiency, new discoveries and new
projects in Bongkot and Arthit resulted in additional proven gas reserves, the total proven gas reserves
decreased because of higher throughput than discovery (DMF, 2016). In 2016, domestic natural gas
production (including Thailand-Malaysia Joint Development Area, JDA) was at 3 767 million standard cubicfeet per day (MMscfd), accounting for 75% of Thailand’s gas. The remaining 25%, 859 MMscfd wasimported from Myanmar, and along with the imported LNG of 390 MMscfd, the total natural gas supply in
Thailand stood at 5 015 MMscfd (EPPO, 2017).
CRUDE OIL AND CONDENSATEAt the end of 2016, Thailand’s proven reserves of oil and condensate reserves stood at 349.4 Mbbl, with
178.3 Mbbl of crude and 171.1 Mbbl of condensate, respectively, of which 293.4 Mbbl came from the gulf
and 56.0 Mbbl from onshore areas. The total proven reserves fell by 47.0 Mbbl (12%) from the previous
year. Falling oil prices had caused the concessionaires to defer their capital investment and resulted in a
reduction of proven reserves. (DMF, 2016). The accumulated domestic oil production in 2015 was 152 387
barrels per day (bbl/d). The major crude oil fields in Thailand are Sirikit, Benjamas, Bualuang, Jusmin and
the Big Oil Project of Unocal (Thailand) Co. Ltd (EPPO, 2017).
COAL/LIGNITE

Thailand has lignite (low-grade coal), which can be used for about 70 years. The total indigenous lignite
output in 2016 was 17 Mt. Domestic lignite production comes from two major sources. One source is themine of the Electricity Generating Authority of Thailand (EGAT) and the other is private mines. EGAT’s
lignite is produced from the Mae Moh mine in Lampang province and is used as fuel for power generation
at the Mae Moh Power Plant for the northern part of Thailand while lignite from private companies isdepleting and is mainly used in the cement, paper, food, and textile industries. In 2016, based on heating
value, the proportion of lignite/coal combustion in the power sector was 51.8% and in the industrial sector,
48.2%. Most of the imported coal is sub-bituminous and bituminous. The amount of coal imports havebeen increasing continuously because domestic lignite concessions have begun to expire and coal isinexpensive compared with other energy sources (EPPO, 2017).
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T H AI L AN D

ELECTRICITYThe EGAT used to be the sole power producer in Thailand. Later, the government promoted the private
sector’s role in power generation to encourage competitiveness in the power generation business. Since
1994, a number of independent power producers (IPP) and small power producers (SPP) have taken part in
the power supply industry, which has led to an improvement in power generation and service quality.
Currently, the use of renewable energy in power generation is being promoted and has resulted in a growing
number of very small power producers (VSPP) using renewable energy as the main fuel to supply power tothe grid. Over the past decade, Thailand’s overall electricity capacity has been increasing. While the electricity
capacity of EGAT decreased from 60% in 2005 to 40% in 2016, there was a large increase in IPP, SPP andimported electricity. In 2016, the economy’s power generating capacity stood at 41 556 megawatts (MW),an increase of 274 MW from 2015, with EGAT contributing 40%; IPP, 36%; SPP and VSPP, 15%; andimported electricity from Lao PDR and exchange with Malaysia, 9% (EPPO, 2017).
FINAL ENERGY CONSUMPTION

Thailand’s total final consumption in 2015 was 86 349 ktoe, an increase of 4.9% from the previous year.
The transport sector was the largest energy-consuming sector, accounting for 25 595 ktoe, or 30% of total
final consumption. The second-largest energy consumer was the industrial sector, which consumed 28 125
ktoe in 2015, an increase of 4.6% from 2014. Besides the energy-consuming sectors, non-energy products,
which are mostly used in the industry sectors, such as feedstock for petrochemicals, account for 13% of
total final consumption, or 10 950 ktoe. By fuel type, oil accounted for 47% (35 225 ktoe) of final energy
consumption (excluding non-energy uses) in 2015, followed by electricity and others (21%), renewables(19%), gas (8.1%) and coal (5.8%).
Natural gas consumption increased by 9.0%, from 5 566 ktoe in 2014 to 6 070 ktoe in 2015. Oilconsumption also increased significantly by 11.7%, from 31 531 ktoe in 2014 to 35 225 ktoe in 2015. In
contrast to natural gas and oil, coal consumption decreased by 4.9%, from 4 629 ktoe in 2014 to 4 403 ktoe
in 2015. Domestic electricity and other energy consumption in 2015 increased by 7.9%, from 14 461 ktoe
in 2014 to 15 598 ktoe in 2015 (EGEDA 2017).
ENERGY INTENSITY ANALYSIS

Thailand’s energy intensity (energy consumption/GDP) in terms of primary energy in 2015 was 128 tonnesof oil equivalent per million USD (toe/million USD), which decreased by 4.9% from 134 toe/million USD
in 2014. The energy intensity of final energy consumption excluding non-energy increased 3.3%, from 71
toe/million USD in 2014 to 74 toe/million USD in 2015.
Table 3: Energy intensity analysis, 2014
Energy intensity (tonnes of oil
equivalent/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

134

128

–4.9

Total final consumption

83

84

1.9

Total final energy consumption excl. non-energy

71

74

3.3

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

Modern renewables consumption decreased by 7.4% from 2014 to 2015, whereas traditional renewables
consumption increased by 4.3% in the same period. The increase of total non-renewables by 9.0% had
caused the share of renewables to final energy consumption to decrease significantly by 12.9%. This isbecause of decreasing crude oil prices in past years which made fossil fuels attractive once again as comparedwith renewables.

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T H AI L AN D

Table 4: Renewable energy share analysis, 2014 vs 20152014
70 9152015
75 399Change (%)
2014 vs 2015
6.3

Non-renewables (Fossils and others)

55 13960 0889.0

Traditional biomass*

6 033

6 291

4.3

Modern renewables*

9 743

9 020

-7.4

Share of modern renewables in final energy
consumption (%)

14%

12%

-13%

Final energy consumption (ktoe)

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels
are typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member
economies, including those that are members of the Organisation for Economic Cooperation and Development(OECD) and those that are not (Non-OECD). All other renewables (hydro, geothermal, and so on) including biogas
and wood pellets are considered modern renewables, although data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKThe Ministry of Energy’s aim is to support sustainable energy management that ensures the economy has
sufficient energy to meet its needs. The ministry is responsible for the following:

establishing energy supply security;

promoting the use of alternative energy;monitoring energy prices and ensuring prices are at levels appropriate to the wider economic andinvestment situation;effectively saving energy and promoting energy efficiency;supporting energy research and development domestically and internationally while simultaneously
protecting the environment and mitigating climate change; andstructuring the energy database centre to systematically consolidate and standardise Thailand’s
energy related information.

The Ministry of Energy is the main government institution responsible for energy policy in Thailand.
Under it are six departments and four state enterprises, as listed below:Office of the Minister—coordinates with the cabinet, the parliament and the general public;

Office of the Permanent Secretary—establishes strategies, translates policies of the ministry into
action plans and coordinates international energy cooperation;



Department of Alternative Energy Development and Efficiency (DEDE)—promotes the efficientuse of energy, monitors energy conservation activities, explores alternative energy sources anddisseminates energy-related technologies;

Department of Energy Business (DOEB)—regulates energy quality and safety standards,
environment and security and improves standards to protect consumers’ interests;



Department of Mineral Fuels (DMF)—facilitates energy resource exploration and development;Energy Policy and Planning Office (EPPO)—recommends economy-wide energy policies andplanning;
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T H AI L AN D

Electricity Generating Authority of Thailand (EGAT)—the state power generating enterprise;

PTT Public Company Limited (PTT) and the Bangchak Petroleum Public Company Limited(BCP)—two autonomous public companies;

The Energy Fund Administration Institute (EFAI)—a public organisation; andThe Energy Regulatory Commission (ERC) and the Nuclear Energy Study and Coordination Office(NESC) —two independent organisations.

According to the energy policy established under the government of Prime Minister Prayuth Chan-ocha and presented to the National Legislative Assembly of Thailand on 12 September 2014, the energy pricestructure will be reformed to reflect actual costs and taxes for different types of fuels and different groupsof consumers. This reform will lead to energy efficiency, consumer awareness and behaviour changes.
On the supply side, the government will proceed with new surveys and exploration for oil and gas,
both onshore and offshore. Additionally, the construction of new power plants using fossil fuels and all
renewable energy initiatives by state-owned enterprises and the private sector will be pursued continuously
through open consultation with the public, with transparency and fairness as well as accounting forenvironmental concerns. The development of energy resources together with neighbouring economies isalso one of the prioritised policies (The Royal Thai Government, 2014).
In 2015, Thailand achieved an important milestone in energy policy development by integrating all
major energy policy plans into a single comprehensive plan, namely the Thailand Integrated Energy
Blueprint (TIEB) (EPPO, 2016a) based on the three principles of economy, ecology and security. The
blueprint consists of five long-term plans, which are the Power Development Plan (PDP2015) (EPPO,
2016b), the Energy Efficiency Development Plan (EEDP2015) (EPPO, 2016c), the Renewable andAlternative Energy Development Plan (AEDP2015) (EPPO, 2016d), the Gas Plan 2015 (Kaewtathip, S,
2017, DMF, 2016) and the Oil Plan 2015 (EPPO, 2016e). All the proposals have been updated andsynchronised to cover the same time period of 2015–36. The PDP2015 includes an energy efficiency target
to reduce energy intensity by 30% from 2010 levels, and also includes a target of the AEDP2015 to develop
renewable energy generating capacity of about 20 gigawatts (GW) or 20% of the total generating capacity,
by 2036.
Figure 1: Thailand’s Integrated Energy Blueprint
Security
EconomyEcology

Security
EconomyEcology

PDP

EEDP

PDP

AEDP

Good Governance of MoEN

EEDP

AEDP

Gas

Oil

Good Governance of MoEN

Source: Sutabutr (2015).
ENERGY SECURITY

The government’s energy security policy will intensify energy development for greater self-reliance, with aview towards achieving a sufficient and stable energy supply. This will be done this by:advancing the exploration and development of energy resources at domestic and international
levels;285

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T H AI L AN Dnegotiating with neighbouring economies at the government level for the joint development ofenergy resources;

developing an appropriate energy mix to reduce supply, price volatility and production cost risks;encouraging electricity production from potential renewable energy sources, particularly fromsmall-scale or very small-scale electricity generating projects; and

investigating other alternative energy sources for electricity generation.

All of the plans under the TIEB contribute to energy security. The PDP2015 aims to strengthen theenergy security of power-generating systems in Thailand by diversifying the fuel mix to be less natural gas
dependent, less electricity-import dependent and setting reserve margins at a minimum of 15%. The
PDP2015 has already included energy savings from the EEDP2015, which identifies 89 672 GWh ofelectricity savings. The largest share of savings is expected to be delivered through a variety of compulsory
measures such as building energy codes, factory and service energy codes, minimum energy performancestandards (MEPS) or high energy performance standards (HEPS), and promotion of LED use.
Electricity consumption will be reduced through the EEDP2015 by 89 672 GWh or 22% comparedwith business-as-usual (BAU) levels. The targets of power generation from renewable energy under the
AEDP are also included in the PDP2015. Generating capacity of 20 GW from solar, biomass, wind, hydroand waste-to-energy are expected by 2036. The share of renewable energy in power generation will be 20%
by 2036. The new gas and oil plans will help to ensure a long-term energy supply along with the PDP2015.
As Thailand has limited energy resources, it will deplete its domestic supply very soon―oil resources
within three years and natural gas, in six. To maintain a degree of energy security, the economy must pursue
new explorations quickly. Since 1971, the Department of Mineral Fuels (DMF) has launched 20 concession
bidding rounds, with the latest announced in 2007. In 2014, the DMF invited bids for exploration andproduction rights for various exploration blocks; however, the initiative was halted. The Petroleum Act was
to be amended along with the government’s energy reform before the twenty-first round of the concession
biddings (DMF, 2016). The plan for the government to re-bid needs to be accelerated to catch up with theexpiry of the concession blocks Bongkot and Erawan in 2022 and 2023, respectively (S&P Global, 2016).
To secure a natural gas supply for the long term, PTT entered into a contract to buy 2 Mt of LNG peryear for the next 20 years from the Qatar Liquefied Gas Company Limited (Qatargas). The first stock ofimported LNG was delivered to Thailand in January 2015. Another contract was also secured by PTT withPetronas to deliver up to 1.2 Mt for a period of 15 years. The first cargo was brought into Thailand in July
2017 (Reuters, 2017). In addition, PTT is in negotiations to acquire 1 Mt of LNG per year from Shell Eastern
Trading (PTE) Ltd. and another 1 Mt of LNG per year from BP Singapore PTE. Limited. The Ministry ofEnergy has also entered into an MoU with Lao PDR to import 7 000 MW of electricity. Under the MoU,
Thailand has already imported 2 000 MW of electricity from Lao PDR. The latest project is the Hong Sa
coal power plant, which expects to connect 1 500 MW to the grid in 2016.
FISCAL REGIME AND INVESTMENTS
ENERGY PRICESThe government’s energy price policy aims to supervise and maintain energy prices at appropriate, stable
and affordable levels. It will do this by:setting a transparent and justifiable fuel price structure that supports the development of energy
products and that best reflects actual production costs;

managing prices through market mechanisms and the oil fund to promote the economical use ofenergy; and

encouraging competition and investment in energy businesses, including the improvement ofservice quality and safety.

The strategy to achieve this involves monitoring energy prices through market mechanisms to ensurethat domestic energy prices are stable, fair and affordable, and reflect the actual production costs. The
domestic energy costs must be reasonable when compared with those in the neighbouring economies. The
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government is supervising the pricing policies and price structure of oil, LPG and NGV to align them withworld market mechanisms and to reflect actual costs; ensuring fairness for the general public through theefficient use of the oil fund; and monitoring refining and marketing margins to maintain them at appropriate
levels. The recent decline in oil prices has created an opportunity for Thailand to restructure fuel pricing
and reduce energy cross-subsidies.
INVESTMENT

The government is keen to encourage competition and investment in energy businesses by creating afavourable environment for investment, transparent competition and internationally accepted energy-related
standards. It will do this by designating an agency, the Thailand Board of Investment, to be responsible forinvestment procedures and processes in the energy industry and by creating a mechanism for a company to
be a service company in the operations and maintenance of the electricity industry, refineries, gas separation
plants and both domestic and overseas oil and gas exploration and production.
ENERGY EFFICIENCY

The first long-term energy policy on energy efficiency, namely the EEDP, was launched in 2011 with a targetof reducing energy intensity (EI) by 25% in 2030 from 2010 levels, equivalent to a reduction in final energy
consumption of 20% by 2030 (38 200 ktoe). Furthermore, the Energy Efficiency Action Plan (EEAP) has
been developed under the strategic framework of the EEDP. The EEAP was approved by the National
Energy Policy Committee (NEPC) and endorsed by the Cabinet in early 2013. The plan includes 67 major
measures or projects.
Most of the measures are sector wide. The rest are sector-specific measures that include 18 in thetransport sector and five measures in each of the following sectors: industry, large and small commercial
buildings and residential. The total amount of energy saved by the plan is expected to be 38 845 ktoe, with
16 257 ktoe from the industrial sector, 15 323 ktoe from the transport sector, 3 635 ktoe from the small
commercial building and residential sector and 3 630 ktoe from the large commercial building sector.
Moreover, the EPPO has completed the development of a 10-year R&D master plan for energy efficiency
to guide R&D in line with the EEAP and EEDP framework.
The EEDP has been updated using the same timeframe as for other energy plans (e.g. 2015–36) andis now known as the Energy Efficiency Plan 2015 or EEP2015. The EEP2015 has set a target to reduceenergy intensity (EI) 30% by 2036 from 2010 levels. This savings target equals 56 142 ktoe, which consistsof 7 641 ktoe of electricity (or 89 672 GWh) and 44 059 ktoe of heating in addition to what has already beenachieved through 2013 at 4 442 ktoe. It also equates to a 30% reduction in BAU energy consumption in2036 (EPPO, 2016c).
The EEDP2015 set the targets of energy reduction for four major economic sectors—industry;
commercial and governmental buildings; residential; and transportation. They are categorised into threestrategic areas with 10 specific measures as follows:
COMPULSORY PROGRAMMEEnforce the Energy Conservation Promotion Act B.E. 2550 (2007), which would put into effectan energy management system based on energy consumption reporting and verification imposedon 7 870 designated buildings and 11 335 factories with transformer sizes of 1 000 kW (1 175 kVA)
and up;

Impose mandatory energy efficiency evaluations for the newly-built and renovating buildings suchas building energy codes (BEC), leadership in energy and environmental design (LEED) and
Thailand’s rating of energy and environmental sustainability (TREES);

Enforce high efficiency performance standards (HEPS) and minimum efficiency performancestandards (MEPS) for equipment or appliance labelling to provide options for consumers to buy
or use highly energy-efficient equipment or appliances;

Implement energy efficiency resource standards (EERS) or minimum standards for large energy
businesses, including power producers and distributors, to implement energy conservation
measures and encourage their customers to use energy efficiently, which would be an important
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mechanism for providing both technical and financial assistance to small and medium enterprises(SMEs).
VOLUNTARY PROGRAMME

Support the operation of ESCO companies using financial tools such as an EE revolving fund, tax
incentives and soft loan and grants to alleviate the technical and financial risks of entrepreneurs
wishing to implement energy conservation measures;Promote the wider use of LEDs for street lights and households through public relations campaigns
and price mechanisms;

Promote energy conservation programmes in the transportation sector by setting up an effective
pricing structure, economising automobile engines, increasing efficient infrastructure and logistics
systems and launching electric vehicle fleets to replace inefficient older generation cars; andPromote R&D that improves energy efficiency and reduces technological costs for equipment orappliances, production processes and materials.

COMPLEMENTARY PROGRAMME

Support the development of professionals in energy conservation fields so that they will have theability to be responsible for energy management and operations, verification and monitoring,consultancy and engineering services as well as for the planning, supervision and promotion of theimplementation of energy conservation measures;Introduce measures that will have a wider impact in terms of fostering public awareness andchanging energy consumption behaviour related to the energy consumption of consumers.
The breakdown of this target is shown in Table 5.

Table 5: The EEDP’s Targets by 2036
Energy Efficiency Measures

Saving Targets in 2036, ktoe

Compulsory Programme

10 972

1. Enforcement of the Energy Conservation Promotion Act B.E. 2550
(2007).
2. Energy efficiency evaluations for buildings (BEC, LEED and TREES).
3. Enforcement of HEPS and MEPS for equipment or appliances.
4. Implementation of EERS for energy businesses.

5 156
1 166
4 150
500

Voluntary Programme

40 7289 524
991
30 213-

5. Support ESCO companies by using financial tools.
6. Promote the wider use of LED for street lights and households.
7. Promote energy conservation programmes in the transport sector.
8. Promote R&D to improve energy efficiency and technological costs.
Complementary Programme
9. Support the development of professionals in the energy conservation field.
10. Introduce measures that foster public awareness.

51 700Total Programme
Source: DEDE (2015).
RENEWABLE ENERGYThe Ministry of Energy is very keen to develop alternative and renewable energy to secure new energy
resources and provide affordable energy to all Thais. There have been several revisions of the renewable288

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and alternative development plan during the past decade. The 10-Year Renewable and Alternative Energy
Development Plan 2012–21 (AEDP), formerly the 15-Year Renewable Energy Development Plan 2008–22(REDP), set as a target an increase in the share of renewable and alternative energy to 25% of total energy
consumption by 2021.
The plan states that the Royal Thai Government will encourage the use of indigenous resources,
including renewable and alternative energy (particularly for power and heat generation) and support the useof transport biofuels such as ethanol-blended gasoline (gasohol) and biodiesel. The plan also strongly
promotes community-scale alternative energy use, encouraging the production and use of renewable energy
at the local level through appropriate incentives for farmers. It also rigorously promotes R&D in all formsof renewable energy.
To achieve these targets, Thailand has set up incentive programmes and mechanisms to encourage
investments, such as the Fund for Energy Services Companies, which acts as a special-purpose vehicle forrenewable energy development projects, with additional investment grants available from the Energy
Conservation Fund. Some of the earlier successful self-working measures, such as the revolving fund, which
provides low interest rates, will be terminated.
Recently, the AEDP timeframe has been updated to 2015–36 and is now called AEDP2015. The
AEDP2015 has set a target for a renewable energy share of 30% of total final energy consumption by 2036.
This target is equal to 39 388 ktoe, which can be divided into power generation of 19 684 MW (5 588 ktoe),heating of 25 088 ktoe and biofuels of 8 712 ktoe. The breakdown of this target is shown in Table 6.
Table 6: The AEDP’s Targets by 2036
Type of Energy

Targets in 2036
5588

ktoe

19 684

MW

500
50
5 570
600
376
680
3 002
6 000
2 906

MW
MW
MW
MW
MW
MW
MW
MW
MW

Heating

25 088ktoe

1. Waste-to-Energy
2. Biomass
3. Biogas
4. Solar
5. Others (for example, geothermal, pyrolysis gas, and so on)495
22 100
1 283
1 200
10

ktoe
ktoe
ktoe
ktoe
ktoe

Biofuels

8 712

ktoe

14
11.3
0.5
4 800
10

million litre/day
million litre/day
million litre/day
tonne/day
ktoe

39 388ktoe

Electricity
1. Municipality Waste
2. Industrial Waste
3. Biomass
4. Biogas (Sewage/Waste)
5. Small Hydropower
6. Biogas (Energy crop)
7. Wind
8. Solar
9. Large Hydropower

1. Biodiesel
2. Ethanol
3. Pyrolysis Oil
4. Compressed Biogas (CBG)
5. Others (for example, bio oil, hydrogen, and so on etc.)
Renewable Energy Consumption
Sources: AEDP2015, DEDE (2016).

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NUCLEAR ENERGY

Nuclear power is recognised as an alternative energy resource that is associated with low emissions and isless expensive than fossil fuels and renewable energy. The Thailand 20-Year Power Development Plan
(PDP2010) had included 5 GW of nuclear power, aimed at ensuring sufficient energy supply and diversifying
the power energy mix. After the Fukushima Daiichi Nuclear Power Plant disaster caused by the earthquake
and tsunami in March 2011, the second revised PDP 2010 postponed the scheduled commercial operation
date (SCOD) of the first unit of the nuclear power project by three years (from 2020 to 2023). Subsequently,
the third revision PDP 2010 further shifted the SCOD of the first unit to 2026 and scheduled the second
unit to begin operations in 2027. By 2030, the last year of the plan, nuclear power would comprise 5% of
the total generation capacity. The PDP2015, which encompasses the time frame 2015–36, includes 1 GW
of nuclear power in the grid in 2035 and another 1 GW in 2036.
CLIMATE CHANGE

Climate change is an important issue in Thailand, even though in 2012 Thailand contributed to only 0.8%
of global GHG emissions. In terms of GHG emissions per capita and per GDP, Thailand’s is lower than
the world average. In Thailand’s Second National Communication, it indicated that 67% of its total GHG
emissions is derived from the energy sector. At the COP20 in Lima, Thailand pledged a pre-2020
contribution of 7–20% GHG emission reduction from BAU levels in the energy and transport sectors.
Thailand also recognises that long-term and continuous effort is required to address climate change,
as stated in its Climate Change Master Plan 2015–50. The master plan provides a continuous framework formeasures and actions over the long term to achieve climate-resilient and low-carbon growth in line with asustainable development path by 2050. This framework plan has already been approved by the Cabinet and
now relevant agencies in various sectors are formulating specific sector plans to address climate change.
Recently, Thailand submitted its Intended Nationally Determined Contribution (INDC) to the United
Nations Framework Convention on Climate Change. Thailand’s INDC indicates its intention to reduce its
GHG emissions by 20% from current BAU levels by 2030 (ONEP, 2015). The ambitious targets in the
PDP2015, AEDP2015 and EEP2015 will significantly contribute to this national intention.
N OTA B L E D E V E L O P M E N T S
THIRD PARTY’S ACCESSTo promote greater competition in the natural gas industry, the Energy Regulatory Commission (ERC) has
issued third party access (TPA) codes for state-owned PTT’s natural gas transmission pipelines and LNG
regasification terminal. This will allow other energy companies to gain access to PTT’s pipelines or the LNG
terminal facilities in a fair and non-discriminatory manner, which will eventually reduce the market
monopoly in the natural gas industry.
THAILAND’S INTEGRATED ENERGY BLUEPRINTThe Ministry of Energy has achieved a significant milestone in accordance with the government’s policy toensure domestic energy security. It has established a comprehensive energy plan, namely the TIEB, basedon the three principles of economy, ecology and security. The blueprint consists of five long-term plansincluding the PDP, the EEDP, the AEDP, the Gas Plan and the Oil Plan. The formulation of these plans
has been delicately designed to ensure that public opinion is taken into consideration through a number ofpublic hearings throughout Thailand.
THE APEC FOLLOW-UP PEER REVIEW ON ENERGY EFFICIENCY IN THAILAND—TRANSPORT SECTOR

Thailand conducted the APEC follow-up peer review on energy efficiency focusing on the transportation
sector from 3–7 August 2015. The final report was endorsed by the environmental working group (EWG)
members in December 2015. It made 48 recommendations to Thailand on energy efficiency intransportation, covering the following six key issues: transport financing and investment; urban land use andtransport integration; low carbon transport systems; travel development management; vehicle fuel economy
labelling and standards and high efficiency vehicle technologies.
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REFERENCES

BP (2017), Statistical Review of World Energy 2017,https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review2017/bp-statistical-review-of-world-energy-2017-full-report.pdf.
DEDE (Department of Alternative Energy Development and Efficiency) (2015), Alternative Energy
Development Plan: AEDP2015. Ministry of Energy, www.dede.go.th.
–– (2016), Energy in Thailand: Facts and Figures 2013, Ministry of Energy,
http://weben.dede.go.th/webmax/content/energy-thailand-facts-figures-2013.
DMF (Department of Mineral Fuels) (2016), Annual Report 2016, Ministry of Energy,
http://www.dmf.go.th/resources/annualReport/annual/en/DMFreport2016mid_opt_17032018.pdf
Kaewtathip, S (2017), Thailand’s Gas Plan, Department of Mineral Fuels, Ministry of Energy, 26 June 2017,
http://www.dmf.go.th/pdf/1.%20GAS%20Plan2015_%20DDG-Sarawut_26June17.pdf.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2017), APEC Energy
Database, http://www.egeda.ewg.apec.org/egeda/database/database-top.html.
EPPO (Energy Policy and Planning Office) (2017), Energy Statistics of Thailand 2017, Ministry of Energy,
https://drive.google.com/file/d/1WfGMhix2DDwB__KpZsaoL76wrSsvq6Lr/edit–– (2016a), EPPO Journal, Special Issue 2016, Thailand Integrated Energy Blueprint. Ministry of Energy,
http://www.eppo.go.th/index.php/en/policy-and-plan/en-governmentpolicystatement#–– (2016b), Power Development Plan (PDP 2015), Ministry of Energy,
http://www.eppo.go.th/index.php/en/policy-and-plan/en-tieb/tieb-pdp–– (2016c), Energy Efficiency Plan (EEP 2015), Ministry of Energy,
http://www.eppo.go.th/index.php/en/policy-and-plan/en-tieb/tieb-eep–– (2016d), Alternative Energy Development Plan (AEDP 2015). Ministry of Energy,
http://www.eppo.go.th/index.php/en/policy-and-plan/en-tieb/tieb-aedp–– (2016e), Oil Plan (Oil Plan 2015), Ministry of Energy, http://www.eppo.go.th/index.php/en/policyand-plan/en-tieb/tieb-oilplan
Reuters (2017), Malaysia’s Petronas Delivers First LNG Cargo to Thailand’s PTT, Reuters,
https://af.reuters.com/article/commoditiesNews/idAFL3N1KC3S3
S&P Global Platts (2016), Analysis: Thai Gas Block Re-bid Plan Unlikely to Change Concessionaires, Singapore(Platts), https://www.platts.com/latest-news/natural-gas/singapore/analysis-thai-gas-block-re-bidplan-unlikely-26454333
Sutabutr, T. (2015), Overview of Thailand Integrated Energy Blueprint. Presented at the APERC Annual
Conference, 9–10 June 2015,
http://aperc.ieej.or.jp/file/2015/9/25/OverviewofThailandIntegratedEnergyBlueprint.pdf
The Royal Thai Government (2014), Statement of the Cabinet to the National Legislative Assembly of Thailand.
The Office of Prime Minister, www.mof.go.th/home/Press_release/News2014/history_61.pdf.
UN (United Nations) (2017), World Statistics Pocketbook 2017 Edition, Series V, No. 41, page 236.
https://unstats.un.org/unsd/publications/pocketbook/files/world-stats-pocketbook-2017.pdf.

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T H AI L AN DUSEFUL LINKS

Department of Alternative Energy Development and Efficiency (DEDE)—www.dede.go.th
Department of Mineral Fuels (DMF)—www.dmf.go.th
Electricity Generating Authority of Thailand (EGAT)—www.egat.co.th
Energy Policy and Planning Office (EPPO)—www.eppo.go.th
Ministry of Energy (MoEN)—www.energy.go.th
Prime Minister’s Office—www.opm.go.th292

APEC ENERGY OVERVIEW 2017

UNITED STATESUNITED STATESI N T ROD U C T I ON

The United States (US) is the world’s second-largest economy, with a gross domestic product (GDP) of
USD 16.6 trillion (2010 USD purchasing power parity [PPP]) in 2015) (EGEDA, 2017). The US spans
9.9 million square kilometres (km2) and has a population of 321 million. The economy’s population growthrate has declined from 1.2% in 1997 to 0.7% in 2015. Per capita GDP in 2015 was USD 51 722, the fourthhighest among the APEC member economies (EGEDA, 2017).
The US enjoyed economic expansion from 1990 to 2000, recording a growth of 3.4% in real terms, whichthen slowed to 1.8% from 2000 to 2015. In 2015, economic growth increased to 2.6% from 2.4% in 2014
(EGEDA, 2017).
The US is the second-largest producer and consumer of energy in APEC. In 2015, the US had 48 billion
barrels of proved oil reserves, 8.7 trillion cubic metres (tcm) of natural gas reserves and 252 billion tonnes ofcoal reserves (BP, 2017).
Table 1: Key data and economic profile, 2015
Key dataa, bEnergy reservesc, dArea (million km2)

9.9

Oil (billion barrels)

48

Population (million)

321

Gas (trillion cubic metres)9

GDP (2010 USD billion PPP)

16 597

Coal (billion tonnes)

252

GDP (2010 USD PPP per capita)

51 722

Uranium (kilotonnes U)

138

Sources: a Census (2010); b EGEDA (2017); c BP (2017); d NEA (2016).
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLYThe total primary energy supply in the US in 2015 was 2 188 million tonnes of oil equivalent (Mtoe). In termsof fuel type, 36% of the supply came from crude oil and petroleum products, 30% from natural gas, 17% fromcoal and the rest from other sources such as nuclear energy, hydropower and geothermal energy. Only 13% of
the economy’s primary energy requirements in 2015 were from net imports. The share of net energy imports
declined from a peak of 32% in 2006 (EGEDA, 2017).
The economy’s total primary energy supply in 2015 decreased by 1.3% compared with the 2014 level of
2 217 Mtoe. The decline resulted mainly from a 13% decrease in coal supply and a 2% decrease in renewableenergy supply. Similarly, a slight reduction in net imports was recorded in 2015 (EGEDA, 2017).
US primary oil supply was 794 Mtoe in 2015, an increase of 1.5% from 2014 (EGEDA, 2017). In 2015,
the US was the world’s largest crude oil and natural gas liquids and condensate producer, with 6% moreproduction than Saudi Arabia. Production averaged 12.8 million barrels per day (bbl/d), an increase of 8%
from the previous year (BP, 2017). Oil import dependence, measured as petroleum net imports as a share of
products supplied, was 24.1% in 2015, the lowest since 1970 (EIA, 2017c).
US primary natural gas supply was 646 Mtoe in 2015, an increase of 3.0% from 2014. While theeconomy’s natural gas supply has grown steadily from 1990 to 2015, with an annual growth rate of 1.6%, theprimary natural gas supply (including net imports in 2015) grew by 3.0% from the 2014 level (EGEDA, 2017).
In recent years, production of inexpensive unconventional gas reserves from shale formations has resulted in
an abundant supply and low wellhead prices. Relatively low natural gas prices and the substitution of gas forcoal by power producers have helped reduce emissions from power generation (EIA, 2016a).

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UNITED STATESTable 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

2 018 527 Industry sector

Net imports and others

257 739 Transport sector

Power generation (GWh)
261 574 Total power generation

4 311 641

628 990

Thermal

2 882 404

2 188 277 Other sectors

506 274Hydro

271 129

Coal

374 122 Non-energy

123 300

Nuclear830 288

Oil

793 952 Final energy consumption

1 396 576

Others327 820Gas

646 390

Coal

19 514

Renewables

147 048

Oil

649 995

Other

226 765

Gas

317 788

Renewables

78 302

Electricity and others

331 017

Total primary energy supply

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel type do not include non-energy uses. This is different
from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste used in
power plants is assumed to be comprising renewables.

The US held approximately 4.7% of the world’s natural gas reserves in 2015 (BP, 2017). As of 2015, theeconomy’s natural gas pipeline transmission network was more than 484 000 kilometres (km) long (PHMSA,
2017). In 2015, the Federal Energy Regulatory Commission (FERC) approved 35 major pipeline projects witha distance of 765 km (FERC, 2017a). In 2015, 392 active underground storage fields in the US had a working
gas capacity of 134 billion cubic meters (bcm). On 20 November 2015, gas in storage peaked at 114 bcm; the2016 peak was on 11 November at a record 115 bcm (EIA, 2017a, 2017b).
Since the mid-2000s, horizontal drilling combined with hydraulic fracturing spurred the economic
production of unconventional gas, largely from shale formations. Shale gas production in the US has increased
rapidly from approximately 8% of gross withdrawals in 2007 to 48% in 2015 (EIA, 2017d, 2017e). Proved
unconventional gas reserves, including shale gas and coalbed methane, are estimated to be 6.2 tcm or morethan 60% of the total reserves as of year-end 2015 (EIA, 2018a). Thus, further increases in shale gas production
are anticipated.
Abundant supplies and relatively low prices have led to several LNG export projects. On 24 February
2016, the first shipment of LNG produced in the lower 48 states left Sabine Pass, Louisiana (EIA, 2016b). By
2020, exporting capacity is expected to rise to 67 million tonnes (Mt) per year, with the addition of five more
LNG plants and another liquefaction unit at Sabine Pass (EIA, 2017f). The newly expanded Panama Canal has
considerably reduced voyage times for LNG from the US Gulf Coast to markets in Northeast Asia (EIA,
2016c).
The primary energy supply of coal in the US totalled 374 Mtoe in 2015. In 2015, primary coal supply
declined by 13% (EGEDA, 2017), as gas took market share from coal in power generation (EIA, 2017c). US
coal reserves are concentrated in the east of the Mississippi River in Appalachia and in several western states(EIA, 2015a).
In 2015, the US was the sixth-largest coal exporter in the world, following Australia, Indonesia, Russia,
South Africa, and Colombia. In 2015, coal exports amounted to 74 Mt, a decrease of 24% from 2014 andsignificantly below the 2012 peak of 126 Mt (EIA, 2017i). More than 60% of exported coal was metallurgical,
with the rest being steam coal. Europe was the largest importer of coal from the US, constituting almost 45%
of US net exports. Coal imports have declined from a peak of 36.3 Mt in 2007 to 11.3 Mt in 2015 (EIA, 2016f).

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UNITED STATESIn 2015, the US produced 4.3 million gigawatt-hours (GWh) of electricity, 67% of which came fromfossil fuel plants, 19% from nuclear energy and 14% from renewable energy and other sources(EGEDA, 2017).
The US generated more nuclear energy than any other economy in 2015 (EIA, 2017i). In 2015, the US
had 99 operable commercial nuclear units, down from a peak of 112 units in 1990. The average utilisation raterose to 92.3% in 2015 and has continued to rise since then (EIA, 2017c). Currently, two commercial nuclear
reactors are under construction, and two stopped construction during 2017 (EIA, 2017g). Many nuclear plants
have applied to the Nuclear Regulatory Commission (NRC) for 20-year extensions of their operating licences,enabling them to operate for 60 years. By late 2017, the NRC had approved licence extensions for 86 operating
nuclear reactor units and had applications for another seven extensions under review, while operators of three
more units had informed the agency regarding their intention to seek extensions between 2021 and 2022
(NRC, 2017a). Operators of eight reactors have announced plans to retire them by 2025 (EIA, 2017g).
Total renewable energy production in the US in 2015 was 147 Mtoe or 7% of the total primary energy
supply. Production declined by 1.7% from the previous year because of decline in biomass, hydro and liquidbiofuels. The largest types of renewable production were biomass and liquid biofuels (EGEDA, 2017).
FINAL ENERGY CONSUMPTION

In 2015, the total final consumption in the US was 1 520 Mtoe, a decrease of 0.7% from the previous year
(EGEDA, 2017), primarily because the winter weather was not as cold in 2015 as in 2014 (EIA, 2017c). The
transport and other sectors constituted 41% and 33%, respectively, of the total final consumption, with theremaining share consumed by the industrial sector (17%) and non-energy sector (8%). In terms of final energy
consumption by fuel (excluding non-energy), petroleum constituted 47%, while electricity and natural gas
constituted 24% and 23%, respectively. Coal contributed a modest 1.4% (EGEDA, 2017).
ENERGY INTENSITY ANALYSISUS energy intensity improved significantly in 2015. (Energy intensity is the amount of energy an economy uses
or consumes for every dollar of GDP it produces.) Primary supply intensity in 2015 improved by 3.8% from
137 tonnes of oil equivalent per million USD (toe/million USD) in 2014. Total final consumption intensity
improved by 3.2% compared with that in the previous year. Final energy consumption intensity, excluding
non-energy, improved by 3.6% (Table 3).
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

137

132

–3.8

Total final consumption

95

92

–3.2

Final energy consumption excl. non-energy

87

84

–3.6

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSISThe share of modern renewables consumed in the US increased to 7.6% in 2015, an increase of 0.2 percentage
points from the previous year. In 2015, the consumption of modern renewables increased by 2.0%.
Production of energy from solar, wind and photovoltaic (PV) sources increased, while that from hydrodecreased. The use of modern biomass increased, mainly in the power sector, while that of traditional biomass
decreased, mainly in the residential and commercial sectors (Table 4).

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UNITED STATESTable 4: Renewable energy share analysis, 2015 (ktoe)
2014

2015

2014 vs. 2015

1 411 727

1 396 576

–1.1

Non-renewables (Fossils and others)

1 289 779

1 276 476

–1.0

Traditional biomass*

17 54013 594-22

Modern renewables*

104 408

106 506

2.0

7.4

7.6

3.1

Final energy consumption (ktoe)

Share of modern renewables to final energy
consumption (%)

Source: EGEDA (2017).
* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal and so on) including biogas and wood pellets are
considered modern renewables, although data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKJURISDICTION AND POLICY

Within the US Government, jurisdiction over the production, transformation, transmission and consumptionof energy is shared by several agencies in the executive branch. Supervision of the use of natural resources falls
under the Department of the Interior (DOI). Energy-related research, development and deployment (RD&D)
takes place mainly under the auspices of the Department of Energy (DOE). The FERC oversees the interstatetransmission of energy, and the Environmental Protection Agency (EPA) regulates the environmental impact
of energy transformations throughout the economy. The Department of Transportation (DOT) also plays animportant role as the regulator of vehicle fuel economy. Compared with many Asian economies, the US
government has a more limited role in the energy sector and its involvement is more decentralised.
While all these federal agencies have some voice in energy policy, the US Congress is responsible forcreating the laws that govern the activities of these agencies and setting the rules for energy markets. Since the1970s, several major legislative packages have defined the economy’s energy policies.
The Energy Policy Act of 2005 (EP Act) was the first major piece of energy legislation passed since theEnergy Policy Act of 1992 (GPO, 2005; US House, 1992). This was shortly followed thereafter by the Energy
Independence and Security Act of 2007 (EISA), the last piece of comprehensive energy legislation passed by
the US Congress (GPO, 2007). The American Recovery and Reinvestment Act of 2009 (ARRA) also
dramatically increased funding for many federal energy programs (DOE, 2012). Key elements of these acts aredescribed below.
ENERGY SECURITY

Among the APEC economies, the US has the lowest exposure to oil supply disruptions, according to a recent
composite index (APERC, 2015). Oil import dependence, measured as net imports as a percentage of productsupplied, peaked at 60.3% in 2005. By 2016, US import dependence declined to 24.4% by the same measure(EIA, 2017c).
Nevertheless, the US is a member of the International Energy Agency (IEA). In 1975, it established astrategic oil stockpile, called the Strategic Petroleum Reserve (SPR). The SPR comprises 60 storage caverns inunderground salt dome formations located at four sites in Texas and the Louisiana Gulf Coast, and this is thelargest government-owned stockpile in the world (DOE, 2016a). Some 669 million barrels of crude oil are

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currently contained in the SPR, the equivalent of 140 days of net crude and product imports, based on the
average 2016 levels (EIA, 2017c).
With the oil in the SPR exceeding the IEA’s 90-day coverage requirement, Congress passed the Bipartisan
Budget Act of 2015 and the Fixing America’s Surface Transportation (FAST) Act in December 2015. In
December 2016, Congress passed the 21st Century Cures Act authorising further sales. These laws mandated
the sale of an estimated 190 million barrels of crude oil between 2017 and 2025 and approved the funding ofan SPR modernisation program through the sale of up to an additional USD 2 billion worth of oil (DOE,
2016a; EIA, 2016d). Congress authorised the sale of an additional 7 million barrels in 2025–27 in its year-end
2017 tax cut legislation (US Congress, 2017a). Under the February 2018 Budget Act, Congress authorised thesale of USD 350 million worth of oil in 2018 for infrastructure modernisation and 100 million additional barrels
from 2022 to 2027 (US Congress, 2018).
In addition to the SPR, the DOE established a 2 million barrel Northeast Home Heating Oil Reserve in2000 and a 1 million barrel Northeast Gasoline Supply Reserve in 2014. These would provide consumers with
supplemental sources of home heating oil and gasoline in the event of supply shortages (DOE, 2016a). The
US Government does not hold strategic reserves of natural gas.
In December 2015, growing US crude oil production also prompted Congress to pass the Consolidated
Appropriations Act of 2016, lifting a 40-year-old ban on the export of crude oil (BIS, 2016).
FISCAL REGIME AND INVESTMENT

US fiscal policy is quite complex, particularly as it relates to the energy sector. This section provides a limited
introduction to the taxation of energy commodities and to the multitude of fiscal incentives that shape energyrelated investments. Energy-producing businesses are taxed like other US corporations, at a maximum
statutory federal rate of 21%, while state rates range from 0% to 10%. However, tax rules result in different
effective tax rates (US Congress, 2017a; CBO, 2005). A detailed discussion of the taxation of energy businesses
is beyond the scope of this overview, but some provisions specifically related to energy investments aredescribed here.
Royalty payments on the production of oil, gas and coal are made to the owner of mineral resources,
which is often the government. The US Office of Natural Resources Revenue collected USD 6.0 billion inroyalty and other payments in Fiscal Year (FY) 2016 (ONRR, 2017). Downstream, sales of some importantenergy commodities such as gasoline and diesel are taxed by state and federal governments. The federal tax on
gasoline and diesel is approximately USD 0.05 per litre (18.4 cents per gallon) and USD 0.06 per litre(24.4 cents per gallon), respectively. In addition, on average, state taxes on gasoline are about 25% higher thanfederal taxes and taxes on diesel are about 6% lower than federal taxes, but there is considerable variation
among the states. There are also about USD 0.03 per litre of other state taxes on gasoline and diesel(API, 2018). Some states have also introduced a ‘public goods charge’ on retail electric and natural gas sales,
the proceeds of which fund energy efficiency programs.
A variety of tax breaks have been introduced by the federal and state governments to promote
investments in energy-related infrastructure. Two key federal instruments are investment tax credits (ITCs)
and production tax credits (PTCs). ITCs allow taxpayers investing in certain qualified energy facilities to reduce
their tax burden by some fraction of the amount invested. Similarly, PTCs reduce the taxpayers’ tax burden in
an amount proportional to the energy production of the facility over a defined period. The types of facilities
qualifying for ITCs range from coal gasifiers to wind turbines (IRS, 2016a). Tax credits for investments inrenewable energy or in energy-efficient home improvements are also available to individuals (DSIRE, 2017).
Two tax breaks historically important to the upstream oil and gas industry are depletion allowances andintangible drilling costs. A depletion allowance is a tax deduction allowed to compensate for the depletion or‘using up’ of natural resource deposits such as oil or natural gas. Intangible drilling costs include all thenecessary expenses made by an operator in the drilling and preparation of wells, such as survey work, groundclearing, drainage, wages, fuel, repairs, supplies, and so on, but not part of the final operating well. Intangible
drilling costs can be deducted in the year spent as a current business expense (IRS, 2016b).

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UNITED STATESRESEARCH AND DEVELOPMENT

The scope of energy-related R&D supported by the US Government has expanded from a focus on nuclear
energy and basic science in the 1960s to include fossil fuels, energy efficiency, renewable energy and carbon
sequestration. Much of this expansion occurred in the immediate aftermath of the 1973 oil crisis. In the five
years following the crisis, spending on energy-related R&D more than tripled. New support for fossil energy,
renewable energy and improved efficiency absorbed much of the increase. Although the amount of spending
declined sharply during the 1980s, the broader scope was preserved (Dooley, 2008).
The DOE is the lead agency for R&D activities. It funds 17 laboratories as well as the research conducted
at 300 universities across the US. Currently supported research ranges from particle physics to pilot projects
for carbon capture and storage (CCS) (DOE, 2016d). Total government spending for energy-related R&D
peaked in FY2009 at USD 3.8 billion with the passage of the ARRA, a one-time economic stimulus. After
FY2009, US federal funding for energy R&D slid to USD 2.3 billion in FY2013 before increasing to USD 3.1
billion in FY2015 and an estimated USD 3.5 billion in FY2016 (NSF, 2016). State governments spent anadditional USD 368 million on energy R&D in FY2016, more than 60% by the State of California (NSF, 2017).
Some business leaders in the US have argued that to confront the energy challenges that the US faces, thegovernment should more than triple spending on energy R&D (AEIC, 2015).
ENERGY MARKETSIn 2015, American consumers spent an estimated USD 1.1 trillion on energy purchases or 6.2% of GDP(EIA, 2017c). Government plays many roles in this large market, such as resource owner, industry regulator
and supporter of R&D.
UPSTREAM DEVELOPMENTThe DOI’s Bureau of Land Management (BLM) administers more than 2.8 million km2 of onshore
underground mineral estates (BLM, 2017a), of which about 110 000 km2 was leased for oil and gas
development in 2016 (BLM, 2017b). The Bureau of Ocean Energy Management (BOEM), another office of
the DOI, leases another 62 000 km2 of offshore oil and gas resources (BOEM, 2018). The BLM and BOEM
also lease more limited onshore lands and offshore areas for the development of above-ground energy
resources such as solar and wind.
While the US Government plays a large role in leasing surface and mineral rights, it is not the sole ownerof such rights. Unlike most other nations, individuals and state governments also own and lease surface lands
and underground mineral rights for energy extraction (DOI, 2017a). In FY2014, only 21% of crude oil and
14% of natural gas were produced from federal lands (EIA, 2015b). State and federal governments share theregulation of upstream development. State oil and gas commissions prevent the waste of resources and protect
public safety in state territories (IOGCC, 2004). In the federal offshore territory, the offices of the DOI exercise
similar responsibilities.
The EP Act promoted the domestic production of oil by removing some regulatory barriers and offering
incentives for production from deep-water resources, low-production wells and unconventional sources. The
law excluded underground injection of hydraulic fracturing fluids from the Safe Drinking Water Act of 1974,
which allowed the exploitation of tight sand and shale hydrocarbon resources. Congress also clearly stated thatthe development of unconventional oil resources should be encouraged to reduce US dependence on foreign
oil imports (GPO, 2005). After more than 40 years of debate, Congress authorised opening the Coastal Plainof the Arctic National Wildlife Refuge Section 1002 area to leasing, drilling and production as part of its 2017
year-end tax cut legislation (US Congress, 2017a).
As part of the effort to go beyond energy independence and achieve energy dominance, the DOI
proposed opening about 90% of federal offshore waters to drilling in 2018. In contrast, current policy puts
94% of the Outer Continental Shelf off limits. There have been no offshore Atlantic lease sales since 1983 andnone off the Pacific coast since 1984 (DOI, 2018). The proposed leasing program is in response to a 2017
executive order by President Trump (GPO, 2017a). The administration has also taken a variety of actions thatmake it easier to drill for and produce oil and gas on federal lands, such as reducing the royalty rate to 12.5%
for a shallow offshore Gulf of Mexico lease sale (BOEM, 2017); speeding up the onshore drilling permitting

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process (DOI, 2017b); and identifying 11 offshore protected areas mostly located in the Pacific Ocean forreview of opportunities for energy exploration and production (NOAA, 2017).
The EPA regulates waste from crude oil and natural gas exploration and production under the Resource
Conservation and Recovery Act (RCRA), and many states also regulate this waste (EPA, 2016b). In particular,
concerns about the impact of hydraulic fracturing on drinking water led the EPA to conduct an extensive study
over the past few years. In December 2016, the EPA concluded that hydraulic fracturing can affect drinking
water under some circumstances (EPA, 2016c). Nevertheless, in 2017, the BLM withdrew a rule proposed in2015 to regulate hydraulic fracturing on federal lands, finding that all 32 states with federal oil and gas leases
have regulations that address hydraulic fracturing (BLM, 2017c). The state of California challenged thisregulation withdrawal in court (CADOJ, 2018).
The federal government plays a larger role in the production of coal than in the production of oil andgas. In FY2014, 41% of US coal was produced from federal lands (EIA, 2015b). President Trump has
encouraged ‘reviving America’s coal industry’ (White House, 2017a), and he and his administration have taken
actions such as cancelling a rule meant to protect streams from the mountaintop removal of mining waste (USCongress, 2017b) and ending a moratorium on leasing federal lands for coal mining (DOI, 2017c).
DOWNSTREAM OIL

The US had almost 123 000 km of crude oil pipelines in 2016 and 100 000 km of oil product pipelines (PHMSA,2018). Interstate crude oil pipelines must have the approval of state authorities, but no broad federal approvalis required. The Pipeline Safety and Hazardous Materials Administration (PHMSA) within the DOT setsminimum federal safety standards for pipeline facilities and transportation (CRS, 2016). The FERC sets oil
pipeline rates and access conditions (FERC, 2016a). The export of crude oil and petroleum products is largely
unregulated (BIS, 2016).
President Trump has promoted building oil pipelines. During his first week in office, Trump issued
presidential memoranda to advance the construction of Keystone XL and Dakota Access oil pipelines (WhiteHouse, 2017b; GPO, 2017b). The Keystone XL Pipeline, a 1 100-km crude oil pipeline to connect oil
production in Alberta, Canada to refineries in the US, cleared its last major regulatory hurdle in 2017 with theapproval of a route by the Nebraska Public Service Commission (NPSC, 2017). However, it continues to facea lawsuit from several environmental groups, alleging that the construction permit was approved without
updating the environmental impact statement (NPRC, 2017). The Dakota Access Pipeline, a slightly longer
project from North Dakota to Illinois, began operation in 2017 (ETP, 2017).
NUCLEAR ENERGYThe US Government supports the nuclear industry through various means, including legislative and financial
measures. For example, the EP Act included several provisions considered to be important for revitalising theAmerican nuclear power industry. It extended the Price–Anderson Nuclear Industries Indemnity Act of 1957
(the Price–Anderson Act) limiting the legal liability of nuclear operators. It also introduced loans to cover costs
incurred by legal or regulatory project delays (GPO, 2005). In 2014 and 2015, the DOE issued USD 8.3 billion
in loan guarantees to support the construction of two Westinghouse AP1000 Generation III+ reactors at the
Alvin W. Vogtle Electric Generating Site, the last two nuclear power plants under construction in the US(DOE, 2017a). Under the February 2018 Budget Act, the Vogtle project will also qualify for an advanced
nuclear facility PTC of 1.8 cents for each KWh of electricity produced and sold once the units come online(US Congress, 2018). This is consistent with the president’s goal to revive and expand the nuclear energy sector(White House, 2017c).
The DOE is responsible for the development and promotion of nuclear energy, while the NRC is theregulatory overseer of the industry. The federal government is also required to provide a site for the permanent
disposal of high-level radioactive waste, with disposal costs to be paid by nuclear operators (NRC, 2016). In
2017, the NRC restarted its endeavour to license a waste depository in Yucca Mountain, Nevada. Work on
licensing was suspended in 2011 after the DOE withdrew its application (NRC, 2017b). The DOE has spent
about USD 15 billion on developing Yucca Mountain, and the cost to continue the licensing process will be
about USD 330 million (GAO, 2017).

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UNITED STATESRENEWABLE ENERGY

Incentives to promote renewables have been established at the federal, state and local levels for utilities andhomeowners. At the utility level, the federal renewable electricity PTC is an inflation-adjusted per kWh tax
credit for electricity generated by geothermal, wind, biomass, hydroelectric, municipal solid waste, landfill gas,
tidal, wave and ocean thermal systems. Wind PTCs extend through 2019, while the others ended in 2017.
Utilities may elect an ITC in lieu of the PTC. Related individual ITCs are available for residential solar electric,
solar water heating, fuel cell, small wind and geothermal heat pump system expenditures through 2021. Several
federal loan and loan guarantee programs also exist to encourage the development of renewable energy andother advanced energy facilities (DSIRE, 2017; US Congress, 2018). The DOE Loan Program Office manages
a portfolio of about USD 14 billion of loan guarantees covering more than 20 renewable projects (DOE,
2017b). In January 2018, President Trump approved a declining 30%, four-year tariff on almost all imported
silicon solar cells and modules, in addition to the existing tariffs on PV cells from China and Chinese Taipei(EIA, 2018b).
Many state and local governments have established financial measures that complement federal incentives
for renewable investment. In addition to subsidies, state legislation has also provided significant indirect
incentives for renewable development through the establishment of policy frameworks such as renewable
portfolio standards (RPS), which mandate that a certain share of electricity sales be sourced from renewableenergy. By mid-2017, 29 states had enacted the RPS legislation with varying degrees of stringency. Hawaii has
the most ambitious goal: 100% renewable generation by 2045 (LBNL, 2017). Other measures have also beenenacted to support renewable development, such as net metering, generation disclosure rules, mandatory utility
green power options, green power purchasing policies and the use of public benefit funds (DSIRE, 2017).
Biofuels have received strong policy support in the transportation sector. In 2007, the EISA mandated afive-fold increase from previous biofuel use targets by 2022, requiring fuel producers to use a minimum of
136 billion litres (36 billion gallons) of biofuel. This included the increase in advanced biofuels usage (otherthan that derived from corn) to 79 billion litres (21 billion gallons) by 2022 (CRS, 2007). Since this law was
passed, US consumption of oil has, in fact, declined in recent years, causing the biofuel blend ratio in gasoline
to rise unexpectedly. Many auto manufactures have stated that their warranties will not cover any damage from
biofuel blending above this ratio. In response, refineries are purchasing renewable credits to waiver their
obligations instead of complying with the mandated targets (CRS, 2013). Consequently, biofuel production isalready tracking below the current targets. Nearly all of US gasoline contains 10% ethanol. The EPA mandated
that more than 19 billion gallons of biofuels overall should be blended into the fuel supply for 2018, still shortof the 26 billion gallons envisioned by Congress in 2007 (EPA, 2017a). In addition, the February 2018 Budget
Act includes a USD 1 per gallon tax credit for biodiesel blenders and producers for the 2017 tax year (USCongress, 2018).
ELECTRICITY AND GAS

The federal government regulates the interstate transmission of electricity and gas, as well as wholesale salesof electricity under the FERC. The FERC’s mandate is to ‘ensure supplies of energy at just, reasonable andnot unduly discriminatory or preferential rates’. In regulating wholesale electric power markets, the FERC has
implemented a policy of fostering competition (FERC, 2008). This has meant granting open access totransmission lines, thereby allowing wholesale customers to meet their needs with purchases from any numberof wholesale suppliers connected across a regional grid. Competitive wholesale electricity markets use distinct
models in different regions. Regional transmission organisations and independent system operators administertransmission networks and operate wholesale markets across large parts of the US and Canada. In otherregions, bilateral contracting between consumers and suppliers, with separate contracting for transmission,
remains the norm (DOJ, et al., 2007).
Retail electricity markets are regulated by the states. Thousands of retail electricity providers operate
under a variety of regulations. Furthermore, 64% of retail customers are served by regulated, investor-owned
utilities, 14% by public power systems and 13% by cooperatives (EIA, 2018c). State regulators ensure thatthese providers serve their customers at rates that are ‘fair, reasonable and non-discriminatory’ (NARUC,
2017). In the 1990s, many states began to explore options for restructuring retail electricity markets to createcompetition among electricity providers while continuing to regulate distribution networks as natural300

APEC ENERGY OVERVIEW 2017

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monopolies. In 2016, 21 states allowed some customers to choose their electricity service provider, while 8%of electricity customers were served by energy-only providers (EIA, 2017h; 2018c).
Natural gas markets are similar to electricity markets, with competitive wholesale markets supplying
federally regulated transmission pipelines and delivering to state-regulated distribution networks. The FERC
sets natural gas pipeline rates. The DOE regulates the import and export of natural gas. The DOT’s PHMSA
regulates gas transmission pipelines to ensure that they are operating safely. The pricing and safety of natural
gas distribution networks are regulated by state agencies (FERC, 2016b; EIA, 2009; DOE, 2016b). The
Department of Health and Human Services subsidises the natural gas bills of low-income families through the
Low Income Home Energy Assistance Program. This subsidy was more than USD 3 billion in 2017–18 (HHS,
2017).
ENERGY EFFICIENCY

Incentives to promote energy efficiency exist at the federal, state and local levels. Federal grants and loans
support residential efficiency improvements. The Weatherization Assistance Program grants funds to states topay for a wide variety of energy efficiency measures for low-income homes, including improvements to thebuilding envelope, its heating and cooling systems, its electrical system and electricity consuming appliances.
Homeowners can also obtain loans from the federal government to finance energy-efficiency measures in new
or existing homes (DSIRE, 2017). The US DOE sets minimum energy conservation standards for more than
60 categories of appliances and equipment, including washing machines, dishwashers, refrigerators/freezers,dehumidifiers, ceiling fans, water heaters, lighting, furnaces, boilers, heat pumps, air conditioners and motors(EIA, 2016e).
At the state level, utilities are generally required to consider energy efficiency on an equal basis with new
generation in their planning; many utilities administer demand-side management programs that provide
incentives and technical assistance to reduce demand for electricity and natural gas (DSIRE, 2017). In 2016,32 states had current or pending efficiency targets that require electric and/or gas utilities to meet energy
reduction targets over time (EIA, 2016e). At the local level, cities often use building codes to mandate building
efficiency improvements (DSIRE, 2017).
CLIMATE CHANGE

On 1 June 2017, President Trump announced that the US would withdraw from the Paris Agreement on
Climate Change (White House, 2017d). As a part of the United Nations Framework Convention on Climate
Change (UNFCCC), the US had previously submitted its Intended Nationally Determined Contributions(INDC) to reduce economy-wide emissions by 26–28% below the 2005 levels by 2025 (UNFCCC, 2016).
Although Congress has not passed specific legislation to control greenhouse gases, the EPA may haveauthority to regulate them under the existing legislation. State and local governments have developed their own
goals and action plans.
FEDERAL REGULATION

Consistent with President Trump’s 28 March 2017 Executive Order on ‘Promoting Energy Independence andEconomic Growth’, the EPA proposed to repeal the Clean Power Plan (CPP) in October, which would have
limited CO2 emissions in the power sector. The CPP was originally published in October 2015, but theSupreme Court stayed its implementation pending judicial review (EPA, 2017b).
Despite efforts to repeal the CPP, Congress enacted a new clean coal tax credit to support CCS
technology in coal plants and other facilities in the February 2018 Budget Act. Any new fossil fuel power plantthat commences construction before 2024 is eligible for tax credits for up to 12 years—USD 50 per tonne forcarbon dioxide (CO2) that is buried and USD 35 per tonne for CO2 that is reutilised (US Congress, 2018).
The EPA sets limits on sulphur dioxide and nitrogen oxide emissions through the Cross State Air
Pollution Rule (CSAPR) and on mercury and toxic pollutants through the Mercury Air Toxics Standard(MATS). Under CSAPR, power plants in 27 states in the Eastern US must limit sulphur dioxide and nitrogenoxide, which are precursors of fine particulates (soot) and ozone (smog). Implementation of the regulations
began in 2015, with further modifications starting in 2017 (EPA, 2016f). The MATS regulates acid gases and301

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mercury from coal-fired plants of 25 MW or greater. Under the MATS, mercury emissions must be 90% below
their uncontrolled levels. The EPA issued its final finding in April 2016 (EPA, 2016a).
On 8 December, the BLM issued a final rule to postpone some of the key requirements of the Methane
Waste Prevention Rule, which aimed to reduce waste of methane from oil and natural gas production activities
on federal and tribal land, until 17 January 2019 (BLM, 2017d). In 2015, the Obama Administration had set a
goal of reducing methane emissions from the oil and gas sector by 40–45% below the 2012 levels by 2025
(UNFCCC, 2016). Methane is a key constituent of natural gas and has a global warming potential more than
25 times greater than that of CO2. In 2016, the EPA issued a final standard to significantly cut methane
emissions from new, reconstructed and modified processes and equipment, including hydraulically fractured
oil wells (EPA, 2016d). On 19 December 2017, the states of California and New Mexico sued theadministration, challenging the issuance of the final rule issued on 8 December to postpone the implementationof the Methane Waste Prevention Rule (CADOJ, 2017). The EPA also issued a final rule in 2016 that requires
new and existing landfills to reduce methane emissions by one-third from the current requirement (EPA,
2016e).
STATE- AND CITY-LEVEL CLIMATE CHANGE INITIATIVESIn addition to federal actions to reduce greenhouse gas (GHG) emissions, regions, states and cities haveundertaken their own initiatives. Nine states in the north-east and mid-Atlantic US are members of the Regional
Greenhouse Gas Initiative (RGGI), which focuses on reducing CO2 emissions from the power sector by 45%
compared with the 2005 levels by 2020. Using a cap-and-trade system, the states sell emission allowances
through auctions and spend the proceeds on energy efficiency, renewable energy and other consumer benefit
programs. The RGGI has conducted 38 auctions thus far and is now considering an additional 30% regionalcap reduction between 2020 and 2030 (RGGI, 2018). The six New England states are also party to the New
England Governors/Eastern Canadian Premiers Climate Change Action Plan, whose 11 members haveresolved to reduce the region’s GHG emissions to 10% below the 1990 levels by 2020 and 35–45% below the1990 levels by 2030 (NEG/ECP, 2017).
In 2017, California set a target of reducing GHG emissions to at least 40% below the 1990 levels by 2030
in legislation (EIA, 2018f). This builds on the Global Warming Solutions Act of 2006, which sets a mandatory
state-wide GHG emissions cap equal to 1990 levels by 2020 (CARB, 2014a). The California Air Resources
Board (CARB) has developed an implementation plan to reach the 2030 goal through a 50% renewable
portfolio standard by 2030, adding 4.2 million zero-emission vehicles by 2030, a 40% reduction in methane
emissions below the 2013 levels by 2030, and so on (CARB, 2017). The governor also signed legislation in 2016
to spend USD 900 million from an ARB-run emissions cap-and-trade program on public transit, housing,communities and high-speed rail (CAGov, 2016a).
California leads a global effort by cities, states, and countries to limit GHG emissions to 2 tonnes per
capita or 80–95% below the 1990 levels by 2050. The Under 2 Coalition was formed in 2015 by the states ofCalifornia and Baden-Wurttemberg, Germany. The coalition represents 205 jurisdictions with more than 1.3
billion people and almost 40% of the global GDP, including 11 US states (Under2, 2017).
In reaction to President Trump’s withdrawal from the Paris Agreement, 19 state governors have joined
the bipartisan United State Climate Alliance, pledging to implement policies that advance the goals of the Paris
Agreement and aiming to reduce GHG emissions by at least 26–28% below the 2005 levels by 2025 as well as
track and report progress to the global community in appropriate settings. Among other steps, the allianceannounced that it would promote opportunities to use the social cost of carbon, an economic measure
abandoned by the Trump Administration, which provides a dollar valuation of the damages caused by carbon
pollution (USCA, 2018).
Municipal governments have undertaken other GHG initiatives. Notably, these include the US Mayors’
National Climate Acton Agenda formed in 2014 by the mayors of Los Angeles, Houston and Philadelphia.
Each of the 392 cities in the coalition, comprising more than 69 million people, is pursuing setting GHG
reduction targets (MNCAA, 2017). The earlier Climate Protection Agreement, launched in 2005 through the
US Conference of Mayors, had 1 060 signatories by 2017. The goal of these mayors is to reduce CO2 emissions
below the 1990 levels (USCM, 2017).

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UNITED STATESVEHICLE EMISSION STANDARDSIn July 2011, a new US combined car and light truck (CAFE) standard was agreed to by 13 major auto
manufacturers in cooperation with the state of California to harmonise economy-wide fuel standards to 23.2
km per litre (54.5 miles per gallon) for cars and light-duty trucks by 2025. The supportive auto manufacturers
together account for over 90% of all vehicles sold in the US (NHTSA, 2011). The program is estimated to save
4 billion barrels of oil and reduce GHG emissions by the equivalent of about 2 billion metric tonnes over the
lifetimes of the 2017–25 model year vehicles (EPA, 2012). The EPA is reconsidering whether the light-duty
vehicle GHG standards established for model years 2022–25 are appropriate and is inviting stakeholders to
submit any data and information they believe are relevant to the reconsideration (EPA, 2017c).
Unlike light-duty vehicles, which have been subject to fuel economy standards since the 1970s, the EPA
and DOT’s National Highway Transportation Safety Administration (NHTSA) are completing the first phase(2014–18) of standards for heavy-duty vehicles. These are expected to reduce the fuel consumption of heavyduty vehicles by 10–20% between 2014 and 2018, save 530 million barrels of oil and reduce carbon emissions
by 270 million tonnes (EPA, 2011). The EPA and NHTSA released final standards for Phase 2 (2018–27) inAugust 2016, which apply to semi-trucks, large pickup trucks and vans and all types of buses and work vehicles.
These standards reduce fuel consumption by 8–24% compared with model year 2017 vehicles, reduce GHG
emissions by about 1 billion tonnes and save about 1.8 billion barrels of oil (NHTSA, 2016).
In addition to the EPA vehicle standards, California is the only state with the right to enact its own
emission standards for new engines and vehicles, which are often more stringent than the EPA standards. To
date, nine other states have fully adopted CARB’s advanced clean car program standards. In July 2014, the
CARB issued a new rule for its zero-emission vehicle (ZEV) program for model year 2018, which subsequently
included battery electric and hydrogen fuel cell vehicles. The ZEV sales requirement for large manufacturers is
4.5% in model year 2018 and will increase to 22% by model year 2025 (CARB, 2014b).
In July 2016, the White House announced that up to USD 4.5 billion would be available for new typesof electric vehicle charging stations, along with plans for electric vehicle charging corridors, more government
electric vehicles and more research (DOE, 2016c). The number of electric vehicle charging stations rose to
more than 42 000 in 2016, an increase of 36% from 2015. Hybrid vehicle sales declined to about 347 000 in
2016, a decrease of 10% from the previous year and 2 230% from the 2013 peak. Plug-in vehicle sales wereabout 160 000, an increase of 38% from the previous year (ORNL, 2017). An ITC of USD 2 500 to 7 500 isavailable for plug-in electric vehicles depending on the size of the vehicle and its battery capacity. The tax credit
is available until 200 000 qualified vehicles have been sold in the US by each manufacturer (DOE, 2017f).
N OTA B L E E N E RG Y D E V E L O P M E N T S
US WITHDRAWS FROM PARIS CLIMATE AGREEMENT

On 1 June 2017, President Trump announced that the US would withdraw from the Paris Climate Accord. He
said that the 2015 agreement imposed unfair environmental standards on American businesses and workers
and vowed to stand against the ‘draconian’ deal. By the end of the year, the US became the only economy in
the world to oppose the agreement. Trump said he wanted to negotiate a better deal, though no steps havebeen taken in that direction (White House, 2017d). Under the accord, the US had pledged to cut its GHG
emissions by 26–28% by 2025 and send USD 3 billion to poorer countries by 2020. Withdrawal from theagreement requires a formal process that could take up to four years (UNFCCC, 2016).
CARBON CAPTURE AND STORAGE POWER PLANT

In January 2017, the first operating power plant with CCS was opened in the US. The Petra Nova facility, acoal-fired plant near Houston, Texas, is one of only two operating power plants with CCS in the world. The
plant’s Unit 8 is designed to capture about one-third of total CO2 emissions, which are then used to enhance
oil recovery at nearby oilfields. The plant is a joint venture between NRG Energy and JX Nippon Oil & Gas
Exploration (EIA, 2017j). The DOE paid USD 190 million of the USD 1 billion overall cost (DOE, 2017c).
In 2018, Congress passed an enhanced tax credit to support the operation of new CCS plants (US Congress,
2018).

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UNITED STATESSUNSHOT HELPS DRIVE DOWN SOLAR COSTS

The DOE announced in September 2017 that its SunShot Initiative cost target of 6 cents per kWh by 2020 for
installed utility-scale PV systems in the US was achieved three years ahead of schedule. Given this success, the
SunShot program announced a new target to reduce the cost to 3 cents per kWh by 2030. Since the program
was launched in 2011, when costs were about 28 cents per kWh, installed capacity has grown from 3 GW to
more than 47 GW in 2017. The DOE projects that combining low-cost storage with low-cost PV could enablesolar energy to supply almost half of U.S. electricity by 2050 (DOE, 2017d).
LIQUEFIED NATURAL GAS

The DOE launched the latest edition of its ‘Global LNG Fundamentals’ handbook on 18 October 2017 in
Tokyo at the LNG Producer–Consumer Conference 2017, sponsored by the Japan Ministry of Economy,
Trade and Industry and the Asia Pacific Energy Research Centre. The handbook attempts to cover a broad
spectrum of topics involved with developing and financing LNG projects, with in-depth coverage of theconsiderations for an LNG export project and the development of a diverse domestic market. The handbook
also addresses LNG import projects as an alternative to economy-to-economy pipelines. It seeks to leverage
the abundance of US natural gas resources and expand LNG exports to promote jobs and economic growthin the US (DOE, 2017e). In July 2017, the private Potential Gas Committee released its biennial assessment
stating that US natural gas resources have reached their highest level in the group’s 52-year history. The report
indicated that the US had technically recoverable resources of 2 817 trillion cubic feet (Tcf) (79 800 bcm) asof year-end 2016. The group assessed technically recoverable resources and did not consider a specific priceor schedule for the discovery and production of gas; these resources are in addition to the proved gas reserves
estimated by the Energy Information Administration (PGC, 2017). In 2016, US LNG exports were 187 billion
cubic feet (bcf) (5 bcm), more than double the previous annual record, and 2017 exports were more than triple
2016 exports (EIA, 2018d).
CRUDE OIL PRODUCTION TOPS 10 MILLION BARRELS PER DAY

In November 2017, US monthly crude oil production exceeded 10 million barrels per day, the highest since1970. At 10.038 million barrels per day, production was just below the November 1970 production value of
10.044 million barrels per day. US crude oil production has increased significantly over the past 10 years, driven
mainly by production from tight rock formations, including shale and other fine-grained rock, using horizontal
drilling and hydraulic fracturing to improve efficiency. The EIA estimated crude oil production from tightformations in November 2017 to have reached 5.1 million barrels per day, surpassing a previous high of 4.7
million barrels per day in March 2015. These formations also produce considerable volumes of natural gas
associated with the crude oil (EIA, 2018e).

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–– (2017b), H.J.Res.38 - Disapproving the rule submitted by the Department of the Interior known as the
Stream Protection Rule, https://www.congress.gov/bill/115th-congress/house-jointresolution/38?q=%7B%22search%22%3A%5B%22Stream+Protection+Rule%22%5D%7D&r=5.
–– (2018), H.R. 1892 - Bipartisan Budget Act of 2018, https://www.congress.gov/115/bills/hr1892/BILLS115hr1892enr.pdf.
White House (The White House) (2017a), ‘An America First Energy Plan’,https://www.whitehouse.gov/america-first-energy.

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UNITED STATES–– (2017b), Presidential Memorandum Regarding Construction of the Keystone XL Pipeline,
https://www.whitehouse.gov/presidential-actions/presidential-memorandum-regarding-constructionkeystone-xl-pipeline/.
–– (2017c), website ‘President Trump Vows to Usher in Golden Era of American Energy Dominance’ page,https://www.whitehouse.gov/articles/president-trump-vows-usher-golden-era-american-energydominance/.
–– (2017d), website ‘Statement by President Trump on the Paris Climate Accord’ page,https://www.whitehouse.gov/briefings-statements/statement-president-trump-paris-climate-accord/.

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UNITED STATESUSEFUL LINKS

Database of State Incentives for Renewables and Efficiency—www.dsireusa.org
Department of Energy—www.energy.gov
Department of Interior—www.doi.gov
Energy Information Administration—www.eia.gov
Energy Star—www.energystar.gov
Environmental Protection Agency—www.epa.gov/energy
Federal Energy Regulatory Commission—www.ferc.gov
Fuel economy—www.fueleconomy.gov
Nuclear Regulatory Commission—www.nrc.gov

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VIET NAM
I N T ROD U C T I ON

Viet Nam is an S-shaped economy located in the centre of Southeast Asia. It is bordered by China to the north,
Laos and Cambodia to the west and the East Sea (Bien Dong) and Pacific Ocean to the east and south,
respectively. Viet Nam has a land area of 331 231 square kilometres (km2) with diverse geography and an
exclusive economic zone stretching 200 nautical miles from its 3 260-km coastline (excluding islands). As it isin a tropical monsoon zone and profoundly affected by the East Sea, Viet Nam has warm weather, abundantsolar radiation, high humidity and generous seasonal rainfall. The economy was part of the final batch of
economies to join APEC in 1998.
Viet Nam is a dynamic, emerging economy with a population of about 92 million (34% live in cities and
66% in rural areas) (GSO, 2017) and a gross domestic product (GDP) of USD 509 billion (2010 USD atpurchasing power parity [PPP]) in 2015 (Table 1). Over the past 30 years, Viet Nam has transformed from acentrally planned economy in 1986 to its current open, socialist-oriented market economy and active
international integration. Viet Nam’s GDP grew continuously between 1990 and 2008 at an annual rate of over
7%. The GDP decreased to 5.8% during the global financial crisis and recession period of 2008–15. In 2017,
the growth reached 6.8%, the highest in the last 10 years. Its economic structure has gradually changed throughcontributions from the industry and service sectors, expanding from 62% of the economy in the early 1990s
to 74% in 2016. Major exports have diversified with more manufactured products, such as electronics,
machinery and vehicles (41% of total exports in 2016) as well as textiles, garments and footwear (21%), in
contrast to traditional fishery products, coffee and rice (nearly 10%) and crude oil (nearly 2%) (Viet Nam
Customs, 2017).
As of 2017, Viet Nam’s business environment ranking has risen by 14 levels and is now ranks 68th in theworld, in part due to improved possibility of electricity, paying taxes and getting credit change (World Bank,2018). Electrification in rural areas and remote islands is up to 99.9%. The government has promoted ‘green
growth’ since 2012 for Viet Nam’s new phase of industrialisation and modernisation.
Table 1: Key data and economic profile, 2015
Key dataa, bArea (km2)

Energy reservesc, d
331 231

Oil (billion barrels)

4.4
617

Population (million)

91

Gas (billion cubic metres)

GDP (2010 USD billion PPP)

509

Coal (million tonnes)

GDP (2010 USD PPP per capita)

5 553

Uranium (kilotonnes U)

3 360
-

Sources: a GSO (2017); b EGEDA (2017); c BP (2017); d NEA-IAEA (2016).

Viet Nam is endowed with diverse energy resources, such as oil, gas, coal, and renewables. Althoughthorough resource assessments have yet to be carried out across the entire territory, especially in deep layers
and deep-sea areas, as of the end of 2016, Viet Nam’s proven fossil energy reserves were 4.4 billion barrels ofoil, 617 billion cubic metres (bcm) of gas and 3 360 million tonnes (Mt) of coal. OECD estimates the identified
recoverable resources of uranium at about 3 900 tonnes, which are yet to be produced. Surveys and assessment
for renewable energy’s potential have been conducted to some extent (APERC, 2016), especially for largehydropower. The economic and technical potential of large hydro is estimated at 95–100 terawatt-hours(TWh)/year or 25 gigawatts (GW), of which the technical potential of small hydropower (less than
30 megawatts [MW]) is about 7 GW (MOIT, 2015e). Other renewable sources under the government’s
consideration for deployment over the next 15 years include wind, solar, biomass and municipal solid wastes(MSW). Potential capacity for wind power development is 6 GW, for solar is 12 GW (PMVN, 2016b), forbiomass is 2 GW and for municipal solid waste (MSW) is 320 MW (MOIT, 2015e). The energy sector is313

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important in attracting significant foreign investments and boosting industry growth, export earnings andscience and technology development.
E N E RG Y S U P P LY A N D C ON S U M P T I ON
PRIMARY ENERGY SUPPLY

Viet Nam’s total primary energy supply (TPES) in 2015 was 71 052 kilotonnes of oil equivalent (ktoe), which
is a considerable increase of 8.9% from the 2014 level (Table 2). By energy source, 35% of the supply camefrom coal, 28% from oil, 13% from natural gas and 24% from renewables and other sources (mostly biomass).
COAL

Viet Nam had about 49 billion tonnes of potential coal resources as of 2010 (PMVN, 2016a). Althoughaccounting for 81% of the resources, development of the sub-bituminous rich Red River Delta coal basin isstill at its preliminary stages. Given the complex geological conditions and its sensitive environmental andeconomic area, the exploitation of coal resources in this basin is predicted to take place only after 2020.
Domestic coal has been produced and supplied mainly by opencast and underground mines in the Quang Ninhprovince.
Viet Nam’s decreasing coal production reflects changes in government’s policy to prioritise coal conservation
for long-term domestic uses rather than boosting exports for generating foreign currencies. In 2015, Viet Nam
produced about 23 231 ktoe of anthracite and semi-anthracite coals. With increasing domestic demand for
coal, coal exports have rapidly declined to 979 ktoe in 2015, about only 4% of the economy’s production androughly 5% of its export peak in 2007 (EGEGA, 2017). Coal imports are predicted to increase significantly
beyond 2017 to meet fuel requirements for over 41 GW of new coal-fired power capacity that the government
has planned to build during 2016–30 in central and southern parts of Viet Nam (PMVN, 2016b).
OIL

Oil reserves are mainly offshore and in the southern part of Viet Nam. Active and successful offshore
exploration has continuously increased the number of oil reserves in recent years. Crude oil production grewby 7.5% from 18.3 million tonnes (Mt) in 2014 to 19.7 Mt in 2015 (AAGR of 4.2% in 2000-15), 49% of which
was exported. According to the Viet Nam Oil and Gas Group (Petrovietnam or PVN) forecast and planning,
oil production based on current proven reserves will be about 16–18 Mt/year through 2022, which will thendecline to less than 14 Mt/year since major fields in the Cuu Long Basin will have matured.
Viet Nam is a net crude oil exporter but a net importer of petroleum products. There were 11.4 Mt ofimported petroleum products in 2015, which continue to account for the majority (66%) of Viet Nam’s total
primary oil supply. Petroleum product imports have shown a slight downward trend since 2009 as the firstrefinery in Viet Nam, the 140 000 barrels per day Dung Quat refinery, began operation during that period but
then rose again from 2013 in pace with economic growth.
NATURAL GAS

Viet Nam is self-sufficient in terms of natural gas supply. There are four offshore gas pipeline systems built todeliver gas from Viet Nam’s oil and gas fields in the petroleum basins of Cuu Long, Nam Con Son, MalayTho Chu and Red River Delta to shores in the south-east and south-west regions of Viet Nam.
Viet Nam’s natural gas supply in 2015 was about 10.5 bcm (PVGas, 2017). Growth in the electricity,
fertiliser and petrochemical industries has driven demand for natural gas. Under the government’s orientation,
PVN and PVGas are preparing for the development of two major gas projects in order to have additional gas
supplies of about 7–10 bcm per year from Block B, Ca Voi Xanh field and adjacent sources to southern andcentral markets beyond 2020 (PMVN, 2016b, PVN, 2014). Viet Nam has also begun to develop new
infrastructure for importing LNG, first in the south, to diversify gas supply sources and ensure national energy
supply security for the period beyond 2021 (PMVN, 2017a; MOIT, 2015b).

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POWER GENERATION

Vietnam Electricity (or EVN) is a state-owned company that has control over the entire national powertransmission and distribution. As of the beginning of 2017, EVN owned approximately 61% of the total 42
GW capacity of electricity in Viet Nam (EVN, 2018). Total power generation in 2015 was 161 923 GWh, anincrease of 13% from its 2014 level. Of this total electricity output, about 35% came from hydro and almost
65% from thermal energy (Table 2). Only a very small insignificant portion is made up by other renewablesources such as wind and biomass.
Among thermal power sources which grow as high as 7% in capacity, coal-fired power plants recorded
the fastest growth in development. With an installed capacity of 13 GW, coal power’s share increased
considerably to 33% in 2015 from 4% in 2008. Growing deployment of hydropower and coal power led torelative reductions in the roles of gas and oil power plants in Viet Nam’s electricity system. Gas power plants
experienced a continuous decline in share, from a record level of 41% in 2008 down to 21% in 2015. The shareof oil power plants is not substantial (2.3%) but is supposed to rise.
To optimise the electricity supply and cost-effectiveness in all regions in the economy, since 2004, Viet
Nam has also relied on power sources from biomass and electricity imports from neighbouring economies
such as China and Laos. However, these sources were still marginal in its economy’s power system during
2008–15.
Table 2: Energy supply and consumption, 2015
Total primary energy supply (ktoe)

Total final consumption (ktoe)

Indigenous production

69 081

Industry sector

23 454

Net imports and others-3 499Transport sector

11 826

Thermal105 609

Total primary energy supply

71 052Other sectors

17 432Hydro

56 123Coal

24 608Non-energy

1 408

Nuclear0

Oil

20 168

Final energy consumption*

52 711Others

191

Gas

9 378

Coal

11 409Renewables

16 762

Oil

15 607

136

Gas

1 491

Renewables

11 866

Electricity and others

12 338OthersPower generation (GWh)
Total power generation

161 923

Source: EGEDA (2017) (data collected in September 2017).
* Final energy consumption and the corresponding breakdown by fuel types do not include non-energy uses. This isdifferent from the total final consumption, which includes non-energy uses. Furthermore, half of the municipal solid waste
used in power plants is assumed to be comprising renewables.
FINAL ENERGY CONSUMPTION

In 2015, Viet Nam’s final energy consumption (excluding non-energy uses) was 52 711 ktoe, up 3.3% from2014 (Table 2). By fuel source, oil consumption contributed to the largest share (30%), followed by electricity,
renewable energy and coal of around 22–23% per source. Gas consumption has remained quite flat since 2012at less than 1.5 Mtoe per year.
Industry is an important sector in GDP growth and represents the largest segment of total final
consumption at a constant 43%. This sector consumed coal at 42%, electricity at 28%, biomass at 16%,
petroleum products at 7% and natural gas at 6%. The transport sector is also a large energy-consuming sector,
accounting for 22% of total final consumption. It remained the main consumer of petroleum products at up
to 76% of the economy’s total requirement. In the other sectors (residential, agricultural and commercial as awhole), energy consumption represented 32% of total final consumption. In this sector, biomass accounted

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for the largest amount at 47%, electricity at 33%, petroleum products at 12% and coal at 9%. All of the biomass
and most of the coal volumes were consumed by the residential sector. Demand for electricity grew rapidly inthe residential and service sectors, reflecting improvements in household income and creating an increase inelectric appliance use and power supply quality.
ENERGY INTENSITY ANALYSIS

In 2015, Viet Nam’s energy intensity in terms of primary energy supply was about 140 tonnes of oil equivalent
per million USD of GDP (toe/million USD), which is an increase of 2.1% from 137 toe/million USD in 2014,
while energy intensity in terms of total final consumption reduced by 2.9% in the same period (Table 3). There
were improvements in energy efficiency from end-use sectors except transport, the sector with the highest
growth rate in 2014–15. The building sector recorded a significant decline in energy intensity at 7.4% as awhole in 2015, while the largest consumer, industry, was at 3% decline.
Table 3: Energy intensity analysis, 2015
Energy intensity (toe/million USD)

Energy2014

2015

Change (%)
2014 vs 2015

Total primary energy supply

137

140

2.1

Total final consumption

109

106

-2.9

Final energy consumption excl. non-energy

107

104

-3.2

Source: EGEDA (2017).
RENEWABLE ENERGY SHARE ANALYSIS

Table 4 shows how the share of modern renewable energy in final energy consumption changed in two years:
from 16.2% to 15.2% in 2015. Final energy consumption increased by 3.3%, while energy consumption fromboth traditional biomass and modern renewables experienced declines.
For electricity specifically, the installed hydropower capacity has tripled from 4.4 GW to 14 GW since2005, reflecting an average annual growth rate (AAGR) of 13%. As a result, total renewables’ share increased
from 38% in 2005 to 43% in 2015. However, the share includes large hydropower, which is soon to saturate,and hence, this share may decrease in the near future.
Viet Nam is a tropical economy that is rich in natural resources and has abundant potential for solar,
wind, and biomass energy, not to mention small and medium hydropower. The economy can contributesignificantly to the APEC renewable doubling goal if the potentials are utilised effectively.
Table 4: Renewable energy share analysis, 2014 vs 2015
Energy2014

Final energy consumption (ktoe)

2015

Change (%)
2014 vs 2015

51 02452 711

3.3

Non-renewables (Fossils and others)

33 70136 555

8.5

Traditional biomass*

9 034

8 130

−10

Modern renewables*

8 290

8 027

−3.2

Share of modern renewables to final energy
consumption (%)

16.2%

15.2%

−6.3%

Source: EGEDA (2017).

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V IE T N A M* Biomass used in the residential and commercial sectors is assumed to be traditional biomass because solid biofuels are
typically used in these sectors for heating (residential) and cooking (residential and commercial), with inefficienttechnologies that often have adverse effects on human health. This definition is applied to all APEC member economies,
including those that are members of the Organisation for Economic Cooperation and Development (OECD) and thosethat are not (Non-OECD). All other renewables (hydro, geothermal and so on.) including biogas and wood pellets are
considered modern renewables, although data on wood pellets are limited.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKThe Ministry of Industry and Trade (MOIT) was formed in 2007 and oversees all energy industries. Within the
MOIT, the General Directorate of Energy (GDE) and the Electricity Regulatory Authority of Viet Nam(ERAV) are two key advisory and executive units assisting the MOIT’s Minister with the management of theenergy sectors. GDE (PMVN, 2011a) focuses on formulating law, policy and planning, and generally, managing
all energy sectors, while ERAV (PMVN, 2008) specialises in regulatory activities in the electricity sector inorder to ensure a safe and high-quality supply of electricity for the economy. However, under the restructureof MOIT in 2017 (GOV, 2017), GDE was disbanded and most of the sub-bodies went to three energy-related
divisions: the Authority of Electricity and Renewable Energy, Department of Energy Efficiency andSustainable Development and Department of Oil, Gas and Coal. Most of the energy research and projection
activities are carried out under the Institute of Energy.
Petro Vietnam (PVN), the Viet Nam National Petroleum Group (Petrolimex), Viet Nam Electricity(EVN) and The Vietnam National Coal - Mineral Industries Group (Vinacomin) are the leading state-owned
enterprises (SOEs) in the energy industries in Viet Nam. They actively contribute to formulating andimplementing development strategies, master plans and annual plans issued by the government in energy
sectors.
The latest umbrella policy document is the ‘National Energy Development Strategy to 2020, with a Vision
to 2050’ (PMVN, 2007a), which addresses the Vietnamese Government’s energy development viewpoints, key
objectives, major policies and measures to be realised up to 2020 in the energy industries. In addition, detailed
sectoral targets and policies for each five-year planning period correspondingly adjust to updated assessments.
During 2015–17, the Prime Minister approved several new or revised strategies and master plans for thedevelopment of oil and gas, renewable energy, coal and electricity sectors. They include oil and gas strategy to2025/20351 (PMVN, 2015b); renewable energy strategy to 2030/2050 (PMVN, 2015c); revised coal plan to2020/2030 (PMVN, 2016a); revised power plan for 2010–20/2030, also known as PDP7 revised (PMVN,
2016b), and gas plan 2025/2035 (PMVN, 2017a).
Below is the summary of some of the main targets for energy development in Viet Nam up to 2020/2030:


To ensure a sufficient and high-quality supply of energy to meet the demands of socio-economic
development, with average GDP growth rates expected to be 7%–7.5% per year during 2011–20 and
6%–6.5% during 2021–30 (PMVN, 2015c);



To strive to increase petroleum reserves at 25–30 Mtoe per year during 2016–20 and 20–28 Mtoe per
year during 2021–30, and to produce 11–14 million tons of crude oil and 11–14 bcm of gas annuallyduring 2016–20 and 5-12 million tons of crude oil and 15–21 bcm for the period 2021–30 (MOIT,
2015d);

To expand oil refining and petrochemical capacities, aiming to satisfy demands of domestic markets
and export of oil and petrochemical products. To ensure domestic production to meet 60%–70% of
Viet Nam’s demand for petroleum products and 50% of the economy’s demand for petrochemical
products over the period 2020–30 (MOIT, 2015d);



To ensure total oil stockpiling (including crude oil and petroleum products) adequate for 90 netimport days until 2020 (PMVN, 2017d);

1 Not open to public

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To strive to reach coal production of 47–50 million tons by 2020 and 55–57 million tons by 2030. To
start exploitation in the Red River Delta coal basin in the period 2021–30 with a targeted commercial
coal yield of 0.5–1.0 million ton per year by 2030 (PMVN, 2016a);

To achieve a share of renewable energy (including large hydropower) in the total primary energy
supply of 31% (or 37 Mtoe) in 2020, 32% (62 Mtoe) in 2030 and 44% (138 Mtoe) in 2050. To develop
renewable power (including large hydro and pumped-storage hydropower) of about 24 GW in 2020
and 49 GW in 2030 (PMVN, 2015c) and

To complete the rural electrification programme for rural, mountainous and remote island areas,
increasing the proportion of rural households with access to electricity to 100% in 2020 (PMVN,
2007a).

As the 2007 National Energy Development Strategy is quite obsolete, MOIT is going to publish National
Energy Master Plan through 2035 with updated energy supply and demand projection by mid-2018.
ENERGY MARKETSELECTRICITY MARKET

Viet Nam’s electricity market is characterised by the active participation of several state-owned enterprises(SOEs) and various private players who are involved in power generation and distribution on a build-operatetransfer (BOT) and independent power producer (IPP) basis. As the leading SOE in Viet Nam’s power sector,
EVN is entrusted to manage the development and operation of the national power transmission system. In
2016, the 42 GW electricity capacity was owned by EVN (61.4%), PVN (10.5%), Vinacomin (4.2%) and BOT
and others (23.9%) (EVN, 2018).
Since 2004, the Government of Viet Nam has established a vision for a competitive power market as partof a long-term development strategy for the electricity sector. The Electricity Law of December 2004 (effective
2005 and amended 2012) outlines the major principles for establishing the power market in Viet Nam. The
scheme and conditions for the power market are detailed in the Road Map (PMVN, 2013a, b), stating the threephases of a competitive market development:Phase 1 (up to 2014): Competitive Generation Power Market;

Phase 2 (2015–21): Competitive Wholesale Power Market (the first two years are pilot) and

Phase 3 (2021 forward): Competitive Retail Power Market (with a pilot period from 2021–23).

Each phase contains two steps: pilot and full operation. Additional regulations and guidelines are enacted
to complement the Road Map, which cover licensing and technical concerns, market rules, tariffs and contract
regulations.
Viet Nam’s competitive generation power market (VCGM) launched its pilot operation on 1 July 2011
and commenced full operation on 1 July 2012. By the end of 2016, there were 76 power plants with a total
capacity of 20.7 GW directly participating in selling electricity in the spot market. Those 55 power plants
constitute 49% of total capacity of the power system.
The first actual pilot year of the competitive wholesale power market started in January 2016, according
to MOIT’s conceptual and detailed design of the Viet Nam Wholesale Electricity Market (VWEM) issued
during 2014–15 (MOIT, 2014b, c and 2015a, c). This year, the market processed the simulation of wholesaletransactions on paper only (or by notes), yet with real payments. Under this pace, the pilot of Vietnam
Wholesale Electricity Market (VWEM) is to start from early 2018 and Vietnam Retail Electricity Market(VREM) is expected to be in full operation from 2023 (EVN, 2018).
TARIFFSElectricity prices are in accordance with the market and under the regulation of the government (Provision 29
of Electricity Law 2004 and amendments in 2012). The calculation of average retail electricity tariff is definedin Decision 24 (PMVN, 2017c) and is based on the audited costs; the generation, transmission and distributionsector investors’ reasonable profits and the costs of regulating, managing and supporting services in the318

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electricity system. EVN calculates the tariff annually and may increase from 3% to under 5%. For higher
increase rates, prompt report to the governmental agencies and approval is required. Current application ofretail electricity tariffs by user categories and wholesale prices for electricity retailers follows MOIT’s
regulations (MOIT, 2014a and 2017) of purchasing and selling prices of electricity from the national electricity
system. The average retail tariff (exclusive of value-added tax [VAT]) is VND 1 720.65/kWh, a 6% increase
compared to the previous period.
CRUDE OIL MARKET

Players in the upstream oil sector in Viet Nam include PVN and its subsidiary PVEP, various international oil
companies and other foreign enterprises. According to the Petroleum Law 1993 and amendments in 2000 and
2008, the government reserves the right to be a priority buyer of oil production from contractors, and in suchcases, foreign contractors have the right to sell their profit oil at international prices.
The Dung Quat refinery built in Quang Ngai province has a refining capacity of 6.5 Mt of crude oil per
year (or 148 000 barrels per day). It has been operated by the Binh Son Refining and Petrochemical Company
Limited (BSR) since 2009 and is the only crude oil consumer in Viet Nam. Currently, BSR as well as PVOiland PVPower are PVN subsidiaries; however, PVN is now inviting domestic and foreign investors for theirequitisation. Over the last eight years, BSR has bought crude oil mainly via PVOil. The sweet crude oil supply
to Dung Quat refinery has mainly come from domestic sources, including about 60% from Bach Ho field and
40% from others offshore Viet Nam; imports remain a negligent contribution.
Viet Nam’s crude oil market and imports are anticipated to further increase together with existing
expansion plans of refining capacity towards 2030. A 10 Mt refinery and petrochemical complex—PVN’s Nghi
Son project (at Thanh Hoa province, central Viet Nam)—is under commissioning; commercial operation isscheduled for the first quarter of 2018, a year behind schedule. It is expected to meet about 40% of domestic
petrol demand. Another 16 Mt project, Long Son, is also under construction from 2018 to approximately 2022.
PETROLEUM ENGINE FUEL MARKET‘Petroleum engine fuel’ (PEF) is a general term used in Viet Nam to refer to products of the crude oil refining
process, which are used as fuel, including gasoline, diesel, jet fuel, kerosene, fuel oil, biofuels (E5 and E10) andother engine fuels, excluding liquefied petroleum gas (LPG) and natural gas products.
The government regulates wholesale prices of fuel oil and retail prices of other PEFs based on theapproval of a baseline selling price for PEF suppliers. The base price for PEFs (excluding E5 and E10) is
composed of several price elements including cost, insurance, freight (CIF) price of importers; government
taxes and levies (import tax, excise tax, VAT, environment tax); business expense norms; deductions for the
Petroleum Price Stabilisation Fund and profit norms. Exchange rates also affect the base price. In regard to
the E5, E10 base price, the calculation takes into account not only the above-mentioned price elements but
also the monthly average price of fuel ethanol (E100) domestically produced and imported to Viet Nam andthe blending percentage of fuel ethanol (5% for E5 and 10% for E10) by its volume with unleaded gasoline
RON 92. The Ministry of Finance takes the leading role in the calculation of each price element in the regulatedbase price. Starting from January 2018, E5 has been officially sold economy-wide to replace RON 92 after five
years of pilot compulsory sales in several cities/provinces.
NATURAL GAS AND LPG MARKETThe government reserves the right to be the first priority buyer of all natural gases exploited and produced inViet Nam. PVN and PVGas are the authorised buyers of natural gas from oil and gas contractors and thesellers to consumers in the Vietnamese market. According to the price law, natural gas prices are not subject
to government regulation; all upstream sellers and downstream buyers are free to negotiate the price and otherterms in the Gas Purchase and Supply Agreement (GPSA) with PVN and PVGas. The natural gas prices andlevels are set considering the competitive position of natural gas against alternative fuels. This ensures areasonable profit margin for investors in related upstream and midstream natural gas projects.
PVN submits the GPSA, including a price formula and level, to authorised organisations and the Prime
Minister for approval before the GPSA goes into effect. PVGas is responsible for planning, developing and319

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operating infrastructure projects to ensure a safe and reliable natural gas supply and support natural gas
exploration and production in Viet Nam.
Business activities, especially trading and distribution of LPG, and natural gas products are, however,open for competition among all domestic and foreign investors. In 2016, the government promulgatedregulations (GOV, 2016a, b) on detailed conditions and investment procedures for conducting LPG, CNG
and LNG businesses. By the end of 2016, there were seven LPG import-export trading companies and 23
LPG distribution companies operating in Viet Nam. PVGas (51%), Bitexco (39%) and TG Asia (10%) havejointly invested and created the first LNG company in Viet Nam, the LNG Viet Nam, operating since August
2016.
COAL MARKET

Vinacomin’s production and sales account for 95% of the total coal market in Viet Nam. Recently, the NorthEast Coal Corporation separated from Vinacomin to become an independent company and operate under theoversight of the Ministry of Defence. In addition, PVN established PV Power Coal, which oversees coal
imports, trading and ensuring coal supply for their five new coal power plants, namely VungAng 1, Thai Binh
2, Long Phu 1, Song Hau 1 and Quang Trach 1. The forecast for total coal demand for these power plants isabout 16 Mt in 2020 and 20 Mt in 2030.
Since July 2009, Vinacomin has set the price for local customers at the market price, except for power
generators. Recently, the government has been preparing a strategy to deregulate the price of coal used for
power generation, which has been enjoying only 60%–70% of market price. In 2012, the government allowed
the coal price for power production to rise according to the latest electricity price adjustment. Any adjustment
would be no less than the coal production cost in order to ensure funding for the renovation, expansion andimprovement of the capacity of the existing mines and the building of new mines to meet coal demand andcontribute to improvements in energy efficiency.
ENERGY EFFICIENCYIn April 2006, the Prime Minister approved the Viet Nam National Energy Efficiency Programme (VNEEP)
for 2006–15 (PMVN, 2006, 2012b). The programme’s overall objectives cover community stimulation,
motivation and advocacy; science and technology and mandatory management measures for carrying out
coordinated activities related to the economical and efficient use of energy in society as a whole. The aim of
the programme was to save 3%–5% of the total energy consumption over the 2006–10 period and 5%–8% in
the 2011–15 period. The programme is expected to continue under phase three, but this has not yet been
decided. Under VNEEP in 2012–2017, a GEF/World Bank-funded project, Cleaner Production and Energy
Efficiency (CPEE), also resulted in significant outcomes related to legal frameworks for action plan and energy
consumption in some industries. Another USD 158 million project from 2017, mostly funded by the World
Bank, is intended to further support industry with energy efficiency technology and practices.
Phase one of VNEEP for the period 2006–11 was successfully implemented, saving about 4 900 ktoe in
total energy consumption in the period 2006–10, equivalent to 3.4% of total energy consumption. Key legal
documents on EE&C were created and issued, including the Law (NAVN, 2010) and its regulations andguidelines by sector. By the end of 2014, the regulation and guidelines of concrete measures for enhancing
energy savings and efficiency covered transport (2011), agricultural (2013) and industrial sectors (2014). In
2013, the National Technical Regulation on Energy Efficiency Buildings was revised in line with the updated
international trends of minimum standards for energy-efficient building exteriors and interior equipment.
Phase two’s results for the period 2011–15 were discussed at a series of conferences on the five-year
implementation of the National Target Programme on Energy Efficiency–period 2011–15, held in the fourth
quarter of 2015 by MOIT in cooperation with the Vietnam Association of Science and Technology in Energy
Saving and Efficiency (VNEEP, 2015). MOIT reported the level of energy savings at 5.96% of Viet Nam’s
total energy consumption during 2011–15. More information can be found at the Compendium of Energy
Efficiency Policies of APEC Economies 2017 (APERC, 2017).

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RENEWABLE ENERGYIn November 2015, the government first issued the national strategy of renewable energy for the period
through 2030, with a vision towards 2050 (PMVN, 2015c). Renewable energy development in Viet Nam
continues to integrate with the implementation of broader objectives of general socio-economic development
and industrial and sectoral deployment. In particular, it contributes to modernisation and new ruraldevelopment, fuel diversification and implementation of Viet Nam’s pledge to mitigate the increase in GHG
emissions.
The ambitious targets set include commercial renewable energy to reach 37 Mtoe (31% of TPES) by 2020
and 62 Mtoe (over 32%) by 2030; renewable power (including large hydropower) to account for 38% of total
generation by 2020 and 32% by 2030 and biofuels to increase to about 5% of total transport fuel demand in2020 (about 800 ktoe) and 13% (3.7 Mtoe) in 2030. The government expects that accelerated renewable energy
growth will contribute to a mitigation of GHG emissions in energy activities of around 5% by 2020 and 25%
by 2030, compared to the business as usual (BAU) plan. Additionally, a reduction in fossil fuel imports forenergy purposes of about 40 million tonnes of coal (compared to the case established in the PDP7 in 2011)
and 3.7 million tonnes of oil products by 2030 is expected. In March 2016, the Prime Minister approved therevised PDP7 to update and detail these new targets and policy measures for renewable power developments
in Viet Nam to 2030. Renewable energy needs to take an even more important role because of the absence ofthe halted nuclear power plant project in late 2016.
Support mechanisms and policies for renewable energy development include various fiscal incentives
within import tax, corporate income tax and land taxes and fees, as well as credit incentives, as specified inlegislation; approved electricity prices (avoided-cost tariffs, feed-in tariff) for on-grid renewable energy;
standardised power purchase and sale contracts (20 years) within an obligation for EVN/its regional electricity
utilities to prioritise renewable energy in grid connection and dispatch and purchase electricity at approved
tariffs; a renewable portfolio standard (RPS) obligation for major electricity generators and traders; netmetering for electricity consumers with simplified connection arrangements and environmental fees fororganisations utilising fossil fuels for energy production. Detailed information on Viet Nam’s renewablepolicies can be found at the most recent APEC’s Peer Review on Low-Carbon Energy Policies (APERC, 2016).
In 2017, the Prime Minister promulgated the Decision on mechanism on encouragement of solar power
development (PMVN, 2017b), and accordingly, MOIT issued Circular on project development and modelPower Purchase Agreements applied to solar power projects (MOIT, 2017), which makes the list of FiT (Table5) more exhaustive.
Table 5: FiT for some renewable energies in Viet Nam
Renewable Energy

Tariff level
VND/kWhUS cents/kWh*Wind energy

1 614

7.8

Biomass power

1 220

5.8

Solid-waste power

2 114

10.05

Solar energy

2 086

9.35

*Roughly estimated at the issuance time of the decision and subjected to change with exchange currency.
Source: PMVN (2011b, 2014a, b, 2017b)

FiT for wind power is still under review to better reflect the market, so that the tariff can reach as highas 8.7 to 9.9 cents per kWh for onshore and offshore power, respectively.

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NUCLEAR

After the decision of halting the Ninh Thuan nuclear power plant project in late 20162, the Government ofViet Nam has not mentioned about any future restart possibility.
CLIMATE CHANGE

Viet Nam submitted its new climate action plan Intended Nationally Determined Contributions (INDC) in
2015, including a mitigation and an adaptation component. It was then converted into First Nationally
Determined Contributions in the next year. In the early stages of industrialisation, and only recently recognised
as a lower middle-income developing economy, Viet Nam contributes only 0.5% global CO2 emissions (GOV,2015). In the past 50 years, however, extreme climate events such as storms, floods, droughts and saline water
intrusion have increased in both frequency and intensity. Viet Nam is one of the economies that may suffer
the most severe impacts of climate change and rising sea levels, according to national and international analysesof climate change scenarios to 2100.
Viet Nam signed the UNFCCC in 1992 and ratified it in 1994 and signed the Kyoto Protocol (KP) in
1998 and ratified it in 2002. Viet Nam has fulfilled all requirements to be an Annex II economy for developing
clean development mechanisms (CDMs) under the protocol.
On 5 December 2011, Prime Minister Nguyen Tan Dung issued the National Strategy on Climate Change(Decision 2139/QD-TTg). This strategy has a century-long vision and is the foundation for all otherministerial, sectoral and local strategies, plans and programmes.
Viet Nam has set a target to reduce 8%–10% of its GHG emission intensity from 2010 levels by 2020,
and after 2020, to reduce GHG emission intensity by 1.5%–2% per year on average (or 20% by 2030). Thesetargets are Viet Nam’s voluntary reduction. Additional international support is required for higher targets of
20% by 2020 and 30% by 2030 (PMVN, 2012a; GOV, 2015). Viet Nam’s BAU scenario for GHG emissions
was developed based on the assumption of economic growth in the absence of climate change policies. BAU
starts from 2010 (the latest year of the national GHG inventory) and includes the energy, agriculture, waste,and land use, land-use change and forestry (LULUCF) sectors.
GHG emissions in 2010: 246.8 million tons carbon dioxide equivalent (tCO2-e);

Projections for 2020 and 2030 (not including industrial processes):
2020: 474.1 million tCO2-e
2030: 787.4 million tCO2-e
N OTA B L E E N E RG Y D E V E L O P M E N T S
2017 - A DYNAMIC YEAR OF MOIT

In June, the Delegation of the European Union to Viet Nam and the Ministry of Industry and Trade co-hosted
the Launching of the Vietnam Energy Partnership Group (VEPG) and Policy Dialogue. VEPG is establishedto strengthen cooperation between Vietnamese Government and Development Partners to effectively utilise
the Official Development Assistance for the energy sector. VEPG aims to be the focal point to establish theEnergy Information System, which can lead to a more robust and transparent energy database. In September,the first-ever publication on energy outlook, a co-product of the Embassy of Denmark and MOIT, waspublished by Danish Energy Agency and Viet Nam Institute of Energy. The report provided a comprehensive
update of current energy status with domestic insights, using commonly adopted methodology (Bamorel) basedon three scenarios of economic growth. It also set the basis for a possibly biennial publication on energy supply
and demand projection in the future. Also, in September, MOIT restructured itself under the Decision 98 of
the Government and the disassembly of six-year-old General Directorate of Energy was one among various
attempts of MOIT to administrative improvement and simplification. Throughout 2017, the Ministry was busy
with APEC preparation: the Ministerial Meeting in May, and finally, the Leaders’ week in November, which

2 http://news.chinhphu.vn/Home/Govt-states-reasons-to-cancel-nuclear-power-project/201611/29076.vgp

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made 2017 a dynamic and eventful year. The new national energy plan may be published in the second quarterof 2018.
ENERGY SECURITY: FILLING THE NUCLEAR GAP

The latest revision of Power Development Plan (PDP) was published in early 2016: nuclear projects were
included with the contribution of 5.7% power generation in 2030. The decision of halting the construction of
the nuclear power plant in late 2016 interrupted the projection of energy supply in the long term. One of theconclusions in the press release then was to replace the gap by thermal power source and actively promoterenewable energy.
Coal is the cheapest source of supply for a developing economy like Viet Nam. While Viet Nam has beena net coal exporter for more than 25 years, increased domestic consumption in 2016 led to a net import of coalfor the economy. In the Energy Outlook 2017, the economy is projected to be a net energy importer soon,
implying that Viet Nam would have to rely on imported fuel (37.5% in 2025), particularly coal.
Regarding natural gas, Viet Nam has been constructing infrastructure to import about one bcm of LNG
per year starting from 2021. Two new gas-fired power plants, Nhon Trach Nos. 3 and 4, are to be added into
the PDP. According to PVGas, in 2017, the company invested about a billion USD for the second phase of
Nam Con Son 2 pipeline project so that it could receive natural gas from Su Tu Trang (White Lion) field inconjunction with the first phase of Nam Con son 2. Commencement of the activity is scheduled for 2019
onwards.
The Government of Viet Nam has also been actively supporting the growth of renewable energy. A few
months right after the Prime Minister’s approval for the decision of encouraging solar power development
projects, MOIT issued detailed supporting measures for these projects (MOIT, 2017). The decision has
enabled solar power projects to be realised, such as those of EVN in southern areas of Viet Nam (EVN, 2018),
where there is a huge potential of variable renewable energy, and many others to be proposed. In an interview
with the Minister of Industry and Trade3, 44 approved PV projects with a total of 4 350 MWp are to be added
to the national power plan. The Government is also considering a more favourable tariff for wind power.
Currently, 50 projects have been submitted and four with 159 MW are under commercial operation. Windpower, in combination with solar power, has exhibited the fastest growth in 20 years ahead. Renewable energy
is quite costly as compared to other sources; therefore, intensifying regional and international energy
cooperation to call for more investment is necessary in this context.
One important measure to strengthen energy security is to improve energy efficiency, reduce energy
losses and implement extensive measures for the conservation of energy. Viet Nam is assumed to accelerate
the energy efficiency programmes which have gained certain fame and impact in the society since it is regarded
as “the first fuel” (MOIT and DEA, 2017).
TOWARDS A GREENER TRANSPORT: BIO-ETHANOL

In late 2017, Viet Nam’s Government made a firm decision to replace all gasoline A92 fuel with E5 biofuel (amixture of gasoline A92 with 5% bio-fuel ethanol by volume), economy-wide from January 2018, a move that
followed the biofuel development scheme (PMVN, 2007b) and reconfirmed the announcement made by thePrime Minister Office in June 2017 (Announcement 255). With that change, only two types of petrol for motor
vehicles are allowed in the market: the biofuel E5 (some USD 0.84 per Litre) and high-octane traditional
gasoline A95 (USD 0.93 per Litre)4. Also from January 2018, all up-to-9 seater cars must be qualified underenergy labelling program, under the Decision No. 04/2017/QD-TTg.
Biofuels have been encouraged in Viet Nam as an alternative to partially replace conventional fossil fuels,
contributing to enhanced energy security and environmental protection. The intention to promote biofuel
originated in 2007 when the government launched a roadmap for biofuels. By 2025, the economy aims to build
an advanced biofuel industry, applying a biofuel production technology in Viet Nam that will eventually reach
the world’s most advanced level (PMVN, 2007b, 2012c, 2015a).
3 From Vietnam Energy Magazine: http://nangluongvietnam.vn/news/vn/nhan-dinh-phan-bien-kien-nghi/nhan-dinh-du-bao/nang-luong-viet-nam-trong-lo-trinh-doi-moi-tong-the.html
4 Price at VND from http://www.petrolimex.com.vn/, retrieved February 16, 2018.

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In 2014, there were five bioethanol plants (E99.5 and above) built in Quang Nam (Dai Tan), Dong Nai(Tung Lam), Quang Ngai (Dung Quat), Binh Phuoc and Phu Tho (Tam Nong), with a total installed capacityof about 500 million litres per year, enough for mixing 10 billion litres of E5 biofuel (MOIT, 2016a). Currently,
there are seven plants but only two in Quang Nam and Dong Nai are under commercial operation. Others are
expected to restart in 2018–2019 as the economy transits to a full switch to E5 biofuel starting from January
2018. Before this deadline, the switch to E5 biofuel was conducted in Ha Noi and Ho Chi Minh City as a pilot.
The economy estimates a total demand of about 5.5 million cubic metres of E5 biofuel in 2018, equivalent to
275 thousand cubic meters of pure ethanol (E100). If domestic production is insufficient, bio-ethanol will be
imported from abroad.
However, consumers have expressed concerns about the switch to biofuels. These include doubts thatthe quality of ethanol might affect a smooth engine start, and that the switch to biofuel might gradually damage
the engine. As a result, some consumers may still choose to purchase more expensive A95 gasoline rather thanthe E5 biofuel.
Despite these challenges, the Government continues to stress on resuming the biofuel development
scheme. If according to Decision 53 of the Prime Minister (2012c), two years later, E5 shall be replaced by
E10.

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USEFUL LINKS

Government of Viet Nam—www.chinhphu.vn
Ministry of Industry and Trade—www.moit.gov.vn
National Energy Efficiency Programme (VNEEP)—www.vneec.gov.vn
Electricity Regulatory Authority of Vietnam (ERAV)—www.erav.vn
National Load Dispatch Centre (NLDC)—www.nldc.evn.vn/
Vietnam Electricity (EVN)—www.evn.com.vn
Energy savings—tietkiemnangluong.vn
Vietnam Energy—nangluongvietnam.vn
Trade & Investment Promotion Centre, Ho Chi Minh City—www.itpc.gov.vn
Vietnam Oil and Gas Group—www.pvn.com.vn
Vietnam National Petroleum Group (Petrolimex)—petrolimex.com.vn
Viet Nam National Coal and Mineral Industries Holding Corporation Ltd (Vinacomin)—www.vinacomin.vn
Vietnam Economic Times—www.vneconomy.com.vn
Vietnam News Agency—http://vietnamnews.vn/

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