A PE C E N E RG YOV E RVI E W
2015

APEC E N E RG Y O VE R VI E W 2015

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
 2016 APEC Secretariat
APEC#215-RE-01.15

APEC E N E RG Y O VE R VI E W 2015

F O R E W O RDFOREWORD
The sustainable development and use of energy resources continues to be at the forefront of energy policyin APEC. Facilitating economic growth and securing adequate energy supply, while also taking into accountthe global responsibility for reducing greenhouse gas emissions, has resulted in a focus on energy efficiency
and carbon emission reduction.
APEC economies continue to develop plans and measures to improve energy efficiency across all sectorsof the economy. Most economies have followed-through on previously committed action plans to improveenergy efficiency; embarked on efficiency awareness raising campaigns; promoted good energy management
practices and facilitated investment in energy efficiency.
In a statement made in November 2011 at the APEC Ministerial Meeting in Honolulu, Hawaii, the APEC
Ministers aspired to meet a new APEC-wide regional goal of reducing the energy intensity of the APEC
economies by at least 45 percent by 2035, using 2005 as a base year. This came after reviewing data analysedby the APEC Energy Working Group (EWG) which indicated that APEC is on the path to significantly
exceed its previous energy intensity goal. The 45% reduction is an aggregate goal, which recognizes that
economies’ rates of improvement may vary for many reasons.
In addition to this, at the APEC Energy Ministers Meeting in Beijing, China on September 2014, theMinisters reaffirmed the UN ‘Sustainable Energy for All’ initiative. They instructed the EWG through theExpert Group on New and Renewable Energy Technologies (EGNRET) to develop the road map for theaspirational goal of doubling the share of renewables in the APEC energy mix, including in power generation
by 2030. As part of this Ministerial reaffirmation, the Asia Pacific Energy Research Centre (APERC) as well
as EGNRET and Expert Group on Energy Data and Analysis (EGEDA) collaborated for facilitating
discussions on this issue at EWG. The APEC Renewable Energy Share Doubling Goal will need to addresseither APEC energy security, reduction of carbon dioxide (CO2) or sustainable development and ensure
goal setting is consistent with that of the APEC Energy Intensity Reduction Goal.
Sustainable energy development can be achieved by employing highly effective government policies and by
broadening energy cooperation between economies through bilateral, regional and multilateral schemes. In
this context, sharing information on common energy challenges is essential. The APEC Energy Overview
is an annual publication intended to promote information sharing. It contains energy demand and supply
data as well as energy policy information for each of the 21 APEC economies. It also contains information
on notable energy developments, including those related to policy updates, upstream development, energy
efficiency, low carbon energy, and environmental protection.
We hope that this report helps to deepen mutual understanding among APEC economies on energy issues
in the region.

Takato OJIMI
President
Asia Pacific Energy Research Centre(APERC)

Masazumi HIRONO
Acting Chair
Expert Group on Energy Data and Analysis(EGEDA)May 2016

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A C K N O WL E D G E ME N T S

ACKNOWLEDGEMENTS
The APEC Energy Overview 2015 could not have been accomplished without the contributions of many
individuals and organisations. We would like to thank all those whose efforts made this overview possible,
in particular those named below.
We would like to thank APEC member economies for their efforts to improve the accuracy and timelinessof the information provided. We also would like to thank members of the APEC Energy Working Group(EWG), APEC Expert Group on Energy Data and Analysis (EGEDA), and APERC Advisory Board, alongwith numerous government officials, for their helpful information and comments.
PROJECT MANAGER
Elvira Torres Gelindon
PROJECT COORDINATOR
Fang Chia Lee
MAIN CONTRIBUTORS
Data Collection and Compilation: Expert Group on Energy Data Analysis (EGEDA) through its
Coordination Agency, the Energy Statistics & Training Office (ESTO), Asia Pacific Energy Research Centre,
The Institute of Energy Economics, Japan.
Economy Chapters: Naomi Wynn (Australia), Dk Nur Afifah Atikah Pg Hj Ismail (Brunei Darussalam),
Hooman Peimani (Canada, Singapore), Luis Camacho Beas (Chile, Peru), Jia Hao (China, Hong Kong,
China), Wanhar (Indonesia), Takashi Otsuki (Japan), Choong Jong Oh (Korea), Muhamad Izham Abd.
Shukor (Malaysia), Juan Roberto Lozano Maya (Mexico), Martin Brown Santirso (New Zealand, Papua New
Guinea), Michael Sinocruz (Philippines), Alexey Kabalinskiy (Russia), Fang Chia Lee (Chinese Taipei), Atit
Tippichai (Thailand), James Kendell (USA) and Tran Thi Lien Phuong (Viet Nam)EDITORS
Cactus Communications K. K. and Fang Chia Lee
ADMINISTRATIVE SUPPORT
Hideyuki Maekawa, Yoshihiro Hatano, Tomoyo Kawamura and Mayumi Akamatsuiv

APEC E N E RG Y O VE R VI E W 2015

C ON T E N T S

CONTENTS
Foreword ........................................................................................................................................................................ iii
Acknowledgements ....................................................................................................................................................... iv
Contents........................................................................................................................................................................... v
Abbreviations and symbols ......................................................................................................................................... vi
Acronyms ...................................................................................................................................................................... vii
Australia ............................................................................................................................................................................. 1
Brunei Darussalam ......................................................................................................................................................... 14
Canada.............................................................................................................................................................................. 22
Chile.................................................................................................................................................................................. 41
China ................................................................................................................................................................................ 52
Hong Kong, China ........................................................................................................................................................ 63
Indonesia ......................................................................................................................................................................... 73
Japan ................................................................................................................................................................................. 89
Republic Of Korea ........................................................................................................................................................ 98
Malaysia.......................................................................................................................................................................... 106
Mexico............................................................................................................................................................................ 122
New Zealand ................................................................................................................................................................. 134
Papua New Guinea ...................................................................................................................................................... 145
Peru................................................................................................................................................................................. 152
The Philippines ............................................................................................................................................................. 161
The Russian Federation .............................................................................................................................................. 175
Singapore ....................................................................................................................................................................... 190
Chinese Taipei .............................................................................................................................................................. 211
Thailand ......................................................................................................................................................................... 221
United States ................................................................................................................................................................. 232
Viet Nam ....................................................................................................................................................................... 247

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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 litters 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 day

tce

tonnes of coal equivalent

Tcf

trillion cubic feettoetonnes of oil equivalenttUtonnes of uranium metalTWhterawatt-hours

W

watt

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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 Change

CSM

coal-seam methane

DUHF

depleted uranium hexafluoride

EAS

East Asia Summit

EGEDA

Expert Group on Energy Data and Analysis

ESTO

Energy Statistics and Training Office, The Institute of Energy Economics, Japan

EEZ

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

IEEJ

The 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 supplyvii

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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
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 Nam

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A U S T RA LI A

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

Australia is the world’s largest island economy and the world’s sixth largest economy in land area. It lies inthe southern hemisphere between the Indian and Pacific oceans. Its total land area of nearly 7.7 million
square kilometres (km2) comprises six states and two territories. The population of just over 23 million lives
mostly in major cities or regional centres along the eastern and south-eastern seaboards. The economy has
maintained robust economic growth for the last 24 years and has had average annual growth rate (AAGR)
of 3.4% from 1960 to 2015 (ABS, 2015). In 2013, gross domestic product (GDP) reached USD 936.9 billion(USD 2010 purchasing power parity [PPP]), a 2.5% increase from 2012 (EGEDA, 2015). Australia has the
only developed economy in APEC to have recorded no annual recessions during the last 24 years (ATC,2014).
Australia has abundant, high-quality energy resources that are likely to last for many decades at current
rates of production. The Australian energy industry contributed to 4% (AUD 66.8 billion) of the economy
in 2014–15 (OCE, 2016b).
In 2013–14, Australia’s primary energy production fell by 4% to 18 715 petajoules (PJ) or 446 979
kilotonnes of oil equivalent (ktoe), compared with a 10% increase in 2012–13 (OCE, 2015a), due to lower
uranium oxide and oil production. Australia produces energy for both domestic consumption and export.
Energy exports grew by 2% compared with 14% in the previous year and accounted for 84% of domesticenergy production in 2013–14 (OCE, 2015a).
Australia produces uranium for export only, while all other energy production supplies both domestic
and international markets. Australia’s energy production increased at an average annual rate of 2.3% from2002–03 to 2012–13; however, it fell by 4% in 2013–14 (OCE, 2015a).
In 2013–14, coal accounted for 66% of Australia’s primary energy production, in energy content terms,
followed by uranium (14%) and gas (13%) (OCE, 2016a). Crude oil and liquefied petroleum gas (LPG)
represented a further 4.5% of total energy production in energy content terms, and renewables represented
1.8% (OCE, 2015a). Relative to 2013–14, Australian export earnings from energy and mineral commodities
decreased by 12% in 2014–15 to AUD 172 billion (OCE, 2015b).
As of 2013 Australia was the world’s eighth-largest energy producer, accounting for around 2.4% ofworld energy production. It is the second largest exporter of coal (27% of total global coal exports in 2014)
and a major exporter of uranium and liquefied natural gas (LNG) (10% of total global LNG exports) (OCE,2016a). Given Australia’s large energy resources and geographical proximity to burgeoning markets in the
Asia-Pacific region, it is capable of meeting a significant proportion of the world’s growing energy demand
as well as its own domestic needs.
Table 1: Key data and economic profile, 2013
Key data a

Energy reserves b

Area (million km2)

7.7

Oil (billion barrels)

Population (million)

23.1

Gas (billion cubic metres)

GDP (2010 USD billion PPP)

937

Coal (million tonnes)

105 246

Uranium (kilotonnes U)

3 472

GDP (2010 USD PPP per capita)405 154

3.8
3 738

Note: Coal reserves are defined as recoverable economically demonstrated resources of black and brown coal.
Sources: a. EGEDA (2015); b. GA (2014).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

In 2013–14, Australia’s total energy production was 18 715 PJ or 446 979 ktoe (OCE, 2015a). Approximately
66% of production came from coal, 4.5% from crude oil and LPG, 13% from gas, 14% from uranium andthe remaining 1.8% from renewables (OCE, 2015a).

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Australia accounts for around 9% of the world’s black coal production and is the fourth largest
producer behind the United States, India and China respectively (OCE, 2016a). Australian coking andsteaming coals are high in energy content and are relatively low in sulphur, ash and other contaminants. Coalis Australia’s second largest commodity export, earning AUD 38 billion in 2014–15 followed by LNG (AUD
17 billion) and crude oil (AUD 8.7 billion) (OCE, 2015b). Coal is also an important component of domesticenergy supply, accounting for approximately 61% of total electricity generation in 2013–14 (OCE, 2015a).
Gas has become increasingly important to the Australian economy, both as a source of export income
and as a contributor to domestic energy needs. Almost all of Australia’s conventional gas comes from threebasins: the offshore Carnarvon Basin, Western Australia; the offshore Gippsland Basin, Victoria; and theonshore Cooper–Eromanga Basin, which straddles the South Australian and Queensland boundary (GA,2014). Gas production in 2013–14 of 63 billion cubic metres (bcm) was relatively stable, the Macedon gas
processing plant began operating in 2013 and offset reductions at some existing fields (OCE, 2015a).
The production of coal seam gas (CSG), which is produced mainly in New South Wales andQueensland, increased 45% from 2013–14 levels to 11.84 bcm (OCE, 2016b). CSG production is projected
to grow over the next five years.
Australia is a net importer of oil products, but a net exporter of LPG (OCE, 2016). Australia’s crude
oil and LPG production declined by 4% in 2013–14 relative to 2012–13 largely due to its mature oil fields
scheduling production outages (OCE, 2015a). Australia’s oil production is likely to continue to decline due
to maturing oil fields and limited plans to develop existing proven and untested reserves (OCE, 2015a).
In 2013–14, 248 297 gigawatt-hours (GWh) of electricity was generated, mostly from coal (61%)(OCE, 2015a). Given its abundance, coal is likely to remain the most commonly used fuel for electricity
generation. However, a large number of wind and solar energy projects are planned or underway. They are
expected to account for an increasing proportion of total electricity generation over the medium to longterm. In 2013–14, the share renewable energy in the electricity generation mix increased to 15% from 8%
in 2003–04 and Australia’s solar PV generation became the eighth largest in the world.
FINAL ENERGY CONSUMPTION

In 2013–14, Australia’s total energy consumption continued its decline that began in 2011–12, andconsumption reached approximately 2009–10 levels at 5 831 PJ (or 139 264 ktoe) (OCE, 2015a). In 2013–
14, the transport sector marginally overtook the electricity generation sector as the largest energy-consuming
sector at 27.3% of Australia’s total net energy consumption. The electricity generation sector followed at
27% and then the manufacturing sector at 20% (OCE, 2015a). This was followed by the mining (9.1%),
residential (7.7%), commercial (5.4%) and other (3.2%) (OCE, 2015a). By energy source, oil accounted for
38% of consumption in 2013–14, coal 32%, gas 24% and renewables 5.9% (OCE, 2015a). Gas has increased
because of greater uptake by the electricity generation sector and growth in mining and industrial use (OCE,2015a). The share of renewable energy consumption has increased over the past few years, with an increaseof 4% between 2012–13 and 2013–14. Between 2012–13 and 2013–14, there has been growth across all
types of renewables used in electricity generation including solar, wind, hydro, biomass, biogas andgeothermal (OCE, 2015a).
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

343 920 Industry sector

24 708 Total power generation

248 961

Net imports and others–209 704 Transport sector

31 143

Thermal

217 700

Total primary energy supply

129 176 Other sectors

19 689Hydro

18 171

Coal

45 676 Non-energy

4 738

Nuclear–Oil

45 889 Total final energy consumption

80 278Others13 090Gas

29 727

Coal

2 796

Other

7 885

Oil

41 706Gas

13 469

Electricity and others

22 309Source: EGEDA (2015).
For full details of the energy balance table, please see www.ieej.or.jp/egeda/database/database-top.html.

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ENERGY INTENSITY ANALYSIS

Australia is contributing to APEC’s aspirational goal of a 45% energy intensity reduction by 2035 from 2005
levels. Over the last 40 years, Australia’s energy intensity has generally improved (OCE, 2015a). In 2013–
14, energy intensity declined by 4%. According to Australian Government analysis, changes in energy
consumption are broken down into the activity effect, which uses changes in the output or level of activity;
the structural effect, which uses changes in the composition of activity; and the efficiency effect, which relies
on changes in energy intensity. In 2013, an analysis of APEC Energy Statistics found an improvement infinal energy demand of 1.4% from 2012 levels.
Australia’s energy intensity improvements are due to developments in energy efficiency. Thesedevelopments originate from two sources: advances in technology and the movement of industry structures
towards less energy-intensive areas such as the commercial and service sectors.
Table 3: Energy intensity analysis, 2013
Change (%)

Energy intensity (toe/million USD)
Energy2012

20132012 vs 2013

Total primary energy supply

138.3

137.9

–0.3

Total final energy consumption

87

86

–1.4

Industry

25.8

26.3

2.2

Transportation

34

33

–2.4

Others

22

21

–3.5

Non-energy

5.2

5.1

–3.1

Source: EGEDA (2015).
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

Australia’s system of government has three tiers: federal government; six state governments and two territory
governments; and local governments. The federal government or the state/territory governments, rather
than private individuals, own Australian energy resources. None of the tiers of government engage incommercial exploration or development. The Australian Federal Government has title and power overenergy 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 orinside the first three nautical miles of the territorial sea (‘onshore’). Each state government oversees theapprovals process for unconventional gas exploration for their jurisdiction. However, the AustralianGovernment, in the form of the Australian Department of the Environment, 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 that are hoping to
explore in its area. Each state/territory then declines or grants access. Similarly, each state/territory carries
out the assessment of safety requirements and environmental regulations for the coal industry in its
respective jurisdiction.
The Australian Department of Industry, Innovation and Science oversees resources and energy mattersat a federal level. This includes energy security, international engagement, energy efficiency programs andenergy markets.
The Australian Government has committed to a set of signature economy-wide reforms that respondto rising business and household costs. These are outlined in its 2015 Energy White Paper. The Energy
White Paper provides a coherent, integrated and efficient regulatory and policy framework that stimulates
sustainable growth, builds community confidence in environmental safeguards and grows investment in theenergy sector. See also the section entitled ‘Notable Energy Developments’.
In December 2013, the Council of Australian Governments’ (COAG) Energy Council replaced the
COAG Standing Council on Energy and Resources (SCER). The COAG Energy Council is a Ministerial
forum for the Commonwealth, states, territories and New Zealand to work together in the pursuit ofnational energy reforms. Such action includes developing and implementing an integrated and coherent
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energy and mineral resources policy. The COAG Energy Council is responsible for the remits of the former
SCER, the Ministerial Council on Energy (MCE) and the former Ministerial Council on Mineral andPetroleum Resources (Industry, 2015a). The Australian Minister for Resources, Energy and Northern
Australia chairs the Energy Council.
The Energy Council’s work covers the following broad themes:Overarching responsibility 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

Facilitating 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 particularenergy source. Instead, energy security is enhanced by diverse commercially driven fuel options and supply
and delivery sources, including through the importation of liquid fuels from multiple supply and delivery
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 fuel markets and changes in energy security drivers.
The Australian Government broadly defines energy security as the adequate, reliable and competitive supplyof energy to support the functioning of the economy and social development. Adequate is defined as theprovision of sufficient energy to support economic and social activity; reliable as the provision of energy withminimal disruptions to supply; and competitive 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 Australia’s economic and social needs. The second assessment in 2011 foundthat Australia’s energy security situation continued to be robust. Further, Australia’s overall energy security
should remain adequate and reliable because of the level of new investment going forward and the price ofenergy. Work has commenced on the development of the next NESA. The updated NESA webpage link iswww.industry.gov.au/Energy/EnergySecurity/nesa/Pages/default.aspx.
The Australian Government has committed to present a plan to return to compliance to theInternational Energy Agency in mid-2016.
UPSTREAM ENERGY DEVELOPMENT

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

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

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

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

The Australian Government does not undertake or finance energy resource exploration ordevelopment. In the offshore petroleum sector, the Australian Government relies on an annual acreage
release of vacant offshore areas in order to create opportunities for investment. The release, distributed
worldwide, is a comprehensive package, which 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 jurisdictions.
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ENERGY MARKETSMARKET REFORMS

Energy market reform is a priority issue for the COAG Energy Council under the energy market reform
program (Industry, 2015a). To date, reforms have included creating the National Electricity Market (NEM),
supporting legislation and an Australian Gas Market Development Plan. Details on recent market reforms
are available on the COAG Energy Council website: www.scer.gov.au/ (COAG, 2015).
ELECTRICITY AND GAS MARKETSThe NEM was established in 1998 to allow the interjurisdictional flow of electricity between the Australian
Capital Territory, New South Wales, Queensland, South Australia and Victoria (Tasmania joined the NEM
in 2005). The NEM is not connected to Western Australia because of the state’s distance from the rest of
the market. The NEM comprises a wholesale sector and a competitive retail sector. All electricity dispatchedmust be traded through the central pool, where output from generators is aggregated and scheduled to meetdemand.
The Australian gas market is separated into three distinct regional markets defined by the pipelinetransmission infrastructure—the eastern gas market (including the Australian Capital Territory, New South
Wales, Queensland, South Australia, Tasmania and Victoria), the northern gas market and the western gas
market.
Australia's gas markets are projected to undergo major changes in the period to 2030, with thedevelopment of new unconventional gas resources causing an expected tripling of domestic gas production
in response to strong international and steady domestic demand growth. On 3 January 2014, in response toconcerns about the dynamics of the eastern Australian gas market during this transition, the AustralianGovernment released the Eastern Australian Domestic Gas Market Study. The objective of this study was
to inform policymakers of the demand-supply situation in the eastern Australian gas market and the barriers
to domestic gas supply from 2012–23. The study also discussed canvassing opportunities that could improve
market efficiency. In its Energy White Paper, the Australian Government and the COAG Energy Council
rejected the need for government interventions such as the establishment of a gas reservation (Industry,
2015b). The study and the White Paper will be complemented by two reviews currently underway. The firstis from Australia’s Competition and Consumer Commission (ACCC) and the second from the Australian
Energy Market Commission (AEMC). Both reports are expected to provide recommendations for market
reforms to increase supply, improve transparency of market trading and increase liquidity in the market. The
reports are due for public release in May 2016.
A key component of the on-going energy market reforms was the establishment on 1 July 2009 of theAustralian Energy Market Operator (AEMO). The AEMO represents the amalgamation of six electricity
and gas market bodies: the National Electricity Market Management Company (NEMMCO), the Victorian
Energy Networks Corporation (VENCorp), the Electricity Supply Industry Planning Council, the Retail
Energy Market Company (REMCO), the Gas Market Company and the Gas Retail Market Operator(AEMO, 2015).
The AEMO’s functions include operating the NEM and the retail and wholesale gas markets in easternand southern Australia; overseeing the system security of the NEM electricity grid and the Victorian gas
transmission network; economy-wide transmission planning; and establishing a short-term trading market
for gas from 2010 (AEMO, 2015).
The AEMO is also responsible for improving the operation of Australia’s energy markets. It preparesand publishes a 20-year National Transmission Network Development Plan, which provides information tomarket participants and potential investors. In addition, it publishes the Statement of Opportunities
regarding electricity, and the new Gas Market Statement of Opportunities, both of which forecast long-term
supply and demand. It also maintains Australia’s gas market Bulletin Board (AEMO, 2015).
The 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 the regulating body. The COAG Energy Council, comprising energy and resources ministers fromall Australian governmental tiers, is responsible for energy policy and the legislative frameworks under which
the AEMO, AEMC and AER operate.
A review of the governance arrangements of these three energy institutions was released in October
2015. It considered the performance of current governance arrangements for energy markets and provided
advice to the COAG Energy Council on potential areas of improvement to the institutions and theiroversight
by
the
COAG
EnergyCouncil.
The
reportisavailable
atwww.scer.govspace.gov.au/workstreams/energy-market-reform/review-of-governance-arrangements. The
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COAG Energy Council provided its response to the review in December 2015 and mostly agreed with therecommendations.
FISCAL REGIME AND INVESTMENTFEDERAL CORPORATE INCOME TAX

The corporate taxation treatment of companies operating in the energy sector is generally the same as thetreatment of corporations in all other industries. Corporations that earn income in Australia are subject tocorporate income tax. This is 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 another project, subject to common ownershipcriteria.
Certain expenditure incurred by energy companies, such as exploration expenditure and royalty
payments, are immediately deductible for corporate income tax purposes. Other indirect taxes, such as
payroll tax, fringe benefits tax, fuel excise and land taxes may apply.
FEDERAL PETROLEUM RESOURCE RENT TAX

The Petroleum Resource Rent Tax (PRRT) is a federal profits-based tax payable on the upstream profits ofa petroleum project. The PRRT has been in operation in Australia since 1 July 1986. Previously appliedsolely to operations in offshore Australia, the PRRT was extended to apply to all onshore and offshore
projects operating in Australia from 1 July 2012 (ATO, 2014a).
Unlike royalty and excise regimes, the PRRT applies to the profits derived from a petroleum projectand not the volume or value of the petroleum produced. In order to ensure that only the economic rent
generated from a petroleum project is captured by the PRRT, deductions are provided for all allowable
expenditure (together with indexation of carry-forward losses). Further, when other layers of resource taxes
are applicable, such as state and territory royalties and federal crude oil excise, such expenditure is creditableagainst the liabilities of PRRT projects. This ensures that petroleum projects are not subject to double
taxation (ATO, 2014a).
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 fromthe project. Because the PRRT is a project-based tax, losses may not generally 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. Further, PRRT liability is calculated
in accordance with Figure 1 below (ATO, 2014a).
Figure 1: Calculating a PRRT liability

Source: ATO (2014a).
ROYALTIESRoyalties are generally levied by the states. They are 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 a profit component). With regard to petroleum, the state and Northern
Territory governments collect royalties for onshore production. The rate is generally from 10% to 12.5% of
the net wellhead value of production, depending on whether it is from a primary or secondary production
licence or a combination of these.
With regard to offshore production (excluding petroleum), 60% of the royalties are directed to thestate or territory government 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 and onshore areas (including coastal waters). Excise is levied on the price of all sales made in a
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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.
EXPLORATION DEVELOPMENT INCENTIVE (EDI)

With effect from 1 July 2014, the Australian Government introduced the EDI to encourage investment insmall exploration companies that undertake ‘greenfields’ mineral exploration in Australia. The scheme isavailable to junior mineral exploration companies that incur eligible ‘greenfields’ exploration expenditure inAustralia.
When a mining company does not have sufficient income to utilise exploration deductions, the EDI
provides a mechanism 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 ofthe package are:

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.

JOINT PETROLEUM DEVELOPMENT AREA

Petroleum produced within the Joint Petroleum Development Area (JPDA) 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 East Timorese governments regarding the percentage of
production each party will receive after the participating parties have recovered a specified amount of costs
and expenses. Government revenues from petroleum extracted within the JPDA are shared 90% to TimorLeste and 10% to Australia.
MINERALS RESOURCE RENT TAX (MRRT)The MRRT regime previously applied to iron ore and coal mining in Australia from 1 July 2012. However,the Australian Government repealed the MRRT in September 2014. Consequently, from 1 October 2014,
MRRT liable entities do not accrue further liabilities (ATO, 2014b).
INVESTMENT
The Australian energy sector faces challenges in attracting investment over the next decade, although
Australia’s practical investment needs over this period will depend on long-term demand trends. The AEMO
2015 National Transmission Network Development Plan (NTNDP) identified that expenditure in theelectricity sector will continue to focus on replacing ageing transmission network infrastructure rather thaninvesting in new network capacity, especially given that electricity demand has been declining in recent years(AEMO, 2015). According to the NTNDP, ‘total annual investment in transmission networks across theNEM has decreased, from AUD 1 282 million in 2008–09 to AUD 745 million in 2014–15, whereas
replacement expenditure has more than doubled over the same period (AEMO, 2015).
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 existing measures from across the COAG Energy Council’s work program, as well as from theCommonwealth and industry. The NEPP provides a framework and an economy-wide work plan designed
to coordinate efforts and accelerate improvement to deliver a 40% improvement in Australia’s energy
productivity from 2015 to 2030. Current research suggests that Australia can meet this target by
implementing financially attractive end-use energy efficiency initiatives alone. In particular, there are costeffective opportunities to improve energy productivity in the transport, manufacturing and building sectors.
(Please see a more detailed section on NEPP under ‘Notable Energy Developments’ below).
Energy productivity is a measure of the amount of economic output derived from each unit of energy
consumed. Over recent years, Australia’s energy productivity has improved, growing at around 1.8% peryear in the last decade. Despite this, Australia is still lagging behind many economies and countries such as
Japan, Germany and the United Kingdom. The NEPP takes action to address this gap. In the past,
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improving Australia’s energy productivity has been challenging because of either a formal or informal
separation between supply-side energy market reform and demand-side energy efficiency actions. The
NEPP aims to bring supply and demand side policy closer together in order to fully realise the benefits toboth the customer and the broader energy system. By supporting better energy management practices andlowering energy costs, this focus on energy productivity will help Australian businesses competeinternationally, growing the economy and creating jobs. The potential for improvement under the NEPP is
great. Australian industry has identified potential energy savings of 164.2 PJ per year (more energy than
Tasmania uses annually) and potential annual net financial benefits of AUD 1.2 billion.
RENEWABLE ENERGY

Australia has abundant and diverse clean energy resources with significant potential for future development,
as shown in Figure 3. Solar PV generation by 27% in 2013–14 from 2012–13 (OCE, 2015a). Wind-powered
electricity generation increased by 29% in 2013–14 compared with 2012–13 (OCE, 2015a). Hydro also
increased 0.83% in 2013–14 compared with 2012–13 and contributed to just under 50% of total renewablegeneration, compared with 55% in in 2012–13 (OCE, 2015a).

Figure 3: Map showing the distribution of Australia’s energy resources

Source: GA (2014).

The Renewable Energy (Electricity) Amendment Act 2009 and the Renewable Energy (Electricity)(Charge) Amendment Act 2010 were passed in September 2009 and June 2010 respectively. The Renewable
Energy (Electricity) Amendment Act 2009 modified the Renewable Energy (Electricity) Act 2000 to enable
the Australian Government to replace the Mandatory Renewable Energy Target (MRET) with the expanded
Renewable Energy Target (RET) from 1 January 2010 (Environment, 2015a).
In June 2010, the Australian Government passed further legislation to split the expanded RET into
two parts. Effective 1 January 2011, the enhanced RET includes the Small-scale Renewable Energy Scheme(SRES) and the Large-scale Renewable Energy Target (LRET). This enhanced RET aims for at least 20%(or approximately 60 000 GWh) of electricity generation to be provided from renewable sources by 2020.
This includes a target of 45 000 GWh of new renewable electricity generation in addition to the 15 000 GWhof existing renewable electricity generation. The LRET is expected to deliver most of the 2020 target (41000 GWh). The uncapped SRES provides a subsidy to small-scale technologies, such as residential solar
panels and solar hot water systems.

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In 2015, the Australian Government undertook a review of the RET and revised the target to 33 000
GWh from large-scale renewable energy by 2020.
The Australian Renewable Energy Agency (ARENA) is an independent agency established by theAustralian Government on 1 July 2012. It has AUD 2.5 billion until 2022 to fund renewable energy projects(e.g. solar, bioenergy, marine, geothermal and enabling technologies such as storage). It also supports
research and development, commercialisation and early deployment activities, together with activities that
capture and share knowledge. The two objectives of ARENA are to improve the competitiveness ofrenewable energy technologies and to increase the supply of renewable energy in Australia. The Australian
Centre for Renewable Energy and the Australian Solar Institute has been incorporated into ARENA. By
June 2015, ARENA had committed AUD 1.1 billion in support of more than 200 projects, studies
fellowships and scholarships, which have a total value of AUD 2.7 billion (ARENA, 2015).
ARENA’s independent decision-making board, also referred to as the ‘Board’, consists of up to sevenmembers appointed by the Minister for the Environment. The Board also has a CEO appointed by the
Minister for the Environment on the recommendation of the members. Membership of the Board reflects
the skills required to meet the objectives of ARENA. For more information, see www.arena.gov.au.
There is no Australia-wide feed-in tariff scheme to support small-scale renewable technologies. Most
state and territory governments implemented jurisdictional feed-in tariff arrangements for small-scale
renewable technologies; however, some of these schemes have now been amended or closed.
In 2015, approximately 15% of Australian households had solar PV installed. Consequently, total solar
PV generation reached 4.9 GW of installed solar, a 27% increase from 2012–13 (OCE, 2015a). Most of thiscapacity is small-scale rooftop systems. In 2015, wind grew by 29% and now accounts for 31% of South
Australia’s total fuel mix, an increase of 25% from 2013–14.
Over the long term, renewables consumption is expected to increase by approximately an AAGR of
0.9% to 2049–50 and renewables in electricity generation will grow by an AAGR of 1.5% to 2049–50(BREE, 2014). Renewables generation is expected to grow to 20% of the percentage share of electricity
generation by 2049–50, with 10% coming from wind energy (BREE, 2014).
ENERGY TECHNOLOGY AND RESEARCH AND DEVELOPMENT

In the Australian science system, the bulk of basic research is conducted in the university sector. Funding
delivery occurs through organisations such as the Australian Research Council, which has established a rangeof competitive grant schemes. Further, the Commonwealth Scientific and Industrial Research Organisation’s(CSIRO) Energy Flagships 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.
CLIMATE CHANGE

The Australian Government is committed to reducing Australia’s greenhouse gas emissions by 5% below
2000 levels by 2020. The Emissions Reduction Fund (ERF) is the government’s program to meet this target.
Legislation for the ERF passed parliament on 31 October 2014 (Environment, 2015b).
The fund has three main components: crediting emissions reductions, purchasing emissions reductions
and safeguarding emissions reductions (CER, 2015). The emissions reduction fund enables the AustralianGovernment to ‘purchase lowest cost abatement (in the form of Australian carbon credit units) from a wide
range of sources’ (CER, 2015). The Clean Energy Regulator (CER) administers the fund. The fund operates
as a reverse auction where the government purchases emissions reductions on eligible carbon reduction
projects. The total amount of money in the fund is AUD 2 550 million (USD 2 300 million). In the twofund auctions so far, the Government has contracted to purchase over 92 million tonnes of emission
reductions from 275 projects at an average price of AUD 13.12 per tonne of abatement (CER, 2015).
The carbon tax was repealed by Parliament with effect from 1 July 2014 (Environment, 2015c).
Australia’s Intended Nationally Determined Contribution (INDC), submitted to the United Nations
Framework Convention on Climate Change (UNFCCC) in 2015, is set as 26–28% below 2005 levels by
2030.

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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
ENERGY WHITE PAPER 2015

On April 2015, the Australian Government released the Energy White Paper. This sets out Australia’s plan
to increase competition, keep prices down, increase ‘energy productivity’ 1 by 40% from 2015 to 2030
through the introduction of a national energy productivity plan, and increase energy resource development
in order to encourage innovation and investor confidence.
Under the 2015 Energy White Paper, the Australian Government aims to achieve its 40% ‘energy
productivity’ target by addressing energy efficiency in buildings, appliances and equipment, and vehicles. It
will also coordinate more effectively data among energy-use related government departments and agencies
in order to assist decision-makers with planning and forecasting. The government plans to implement
market reforms in order to improve consumer choice and lower energy costs through information andvoluntary action programs, and market and regulatory measures. Buildings are particularly important. The
government is extending the existing Commercial Building Disclosure (CBD) program, which requires the
mandatory disclosure of energy ratings for commercial building sales where the area is larger than 2 000
square metres, to cover buildings of 1 000 square metres as well.
There are several programs that are designed to encourage innovation and investor confidence. For
example, the AUD 5 billion (USD 4.5 billion) Asset Recycling Initiative encourages states and territories toprivatise state-owned electricity assets in order to release capital for investment in new infrastructure. The
money from the sales is for new roads, ports and rail projects that are related to energy market
competiveness. The AUD 188.5 million (USD 170 m) Industry Growth Centres improve competitivenessand productivity by focusing on areas of competitive strength. The sectors involved include oil, gas andenergy resources, and mining equipment, technology and services. The AUD 476 million (USD 429 m)
Industry Skills Fund helps to develop the highly skilled workforce that is needed to adapt to new businessgrowth opportunities, rapid technological change and market-driven structural adjustment. It will focus on
training for the oil, gas and energy resources sector and the mining equipment, technology and services
sector with regard to small to medium enterprises. For more information, see www.ewp.industry.gov.au.
NATIONAL ENERGY PRODUCTIVITY PLAN

The Australian Government is strongly committed to a National Energy Productivity Target of a 40%
improvement between 2015 and 2030. To meet this commitment, the Australian Government, along withstates and territories, developed the NEPP, which, as mentioned above, was released by the COAG Energy
Council in December 2015. The NEPP is expected to contribute more than a quarter of the savings required
to meet Australia’s 2030 greenhouse gas emissions reduction target and will complement existing policies
such as the Emissions Reduction Fund while aiming to avoid placing additional burdens on business.
The NEPP covers all energy use, including electricity, gas and transport fuels, and incorporates:Energy market reforms to promote consumer choice and increase competition and innovation in
the energy market; andEnergy efficiency measures that support better energy use in buildings, equipment and vehicles.

The NEPP includes both existing and new initiatives that support:More productive consumer choices when selecting energy services through, for example, costreflective prices, smart meters and access to information, and labels; andMore productive energy services through innovation and competition, such as the reduction of
barriers to entry in the market for new technologies and service options, and through more efficient
minimum standards for equipment, appliances and buildings.

In order to meet Australia’s proposed 40% improvement in accordance with the 2030 energy
productivity target, Australia must increase its annual productivity improvement from 1.5 to 2.3% per year.
This target has been designed to be large enough to promote real change while still being achievable.

1 An Australian Government term that encompasses energy efficiency, reducing energy intensity and energy costs while promoting

economic growth and competitiveness. The government defines it as ‘the economic value created for every unit of energy consumed’.

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VEHICLE EMISSIONS REFORMS

On 2 November 2015, the Australian Government announced that it is taking a ‘whole of government’approach to address vehicle emissions with a Ministerial Forum to examine vehicle emissions standards inAustralia and vehicle testing arrangements. The Ministerial Forum is supported by a working group that is
examining issues that include implementation of Euro 6, fuel quality standards, fuel efficiency measures(CO2) for light vehicles and emission testing arrangements.
Australia already has in place a mandatory consumer information program that mandates fuelefficiency labelling on new cars, as well as a voluntary program through the Green Vehicle Guide that aims
to assist consumers to make informed purchasing decisions.
The Government will examine further measures such as incentives and standards to encourage thepurchase of more fuel-efficient vehicles.
G20–INTERNATIONAL ENERGY FORUM GAS MARKETS DIALOGUEIn November 2014, Australia and Mexico co-chaired the G20–International Energy Forum (IEF) Gas
Markets Dialogue. It was the first G20IEF and aimed to bring together gas industry experts from business,government and international and regional organisations in order to enhance collaboration and identify
practical ways to improve the ways in which gas markets function. The dialogue centred around threethemes: increasing market transparency, encouraging investment in gas infrastructure and exchanging
information about regional approaches to increasing gas market resilience and security.
G20 ENERGY EFFICIENCY ACTION PLAN

As president of the G20 in 2014, Australia led the development of the G20 Energy Efficiency Action Plan.
This was endorsed by G20 leaders at the November G20 summit and provides a significant step towards
the global improvement of energy efficiency through international cooperation.
The G20 Energy Efficiency Action Plan documents six work streams whereby G20 members andguests work together in order to improve energy efficiency. Each G20 member and guest chose the work
streams in which they intended to participate. These work streams were progressed through the International
Partnership for Energy Efficiency Cooperation (IPEEC) and other international organisations such as the
IEA throughout 2015. The G20 also tasked the IPEEC to report on the development of these activities to
the G20 at the end of 2015. The plan is available for download here:
www.g20.org/sites/default/files/g20_resources/library/g20_energy_efficiency_action_plan.pdf.
OFFSHORE PETROLEUM RESOURCES MANAGEMENT REVIEWThe Australian Government Department of Industry, Innovation and Science is finalising a high-levelstrategic review of the offshore petroleum frameworks that govern oil and gas resource management inCommonwealth waters. The Offshore Petroleum Resources Management Review aims to refine theregulatory and administrative frameworks that support timely and efficient commercial investment,
exploration and development. It will outline actions to improve the effectiveness of how resources aremanaged and operated; provide greater flexibility and better alignment with technical and operational
realities; improve transparency; and reduce costs, including through improved administrative efficiency.
A final report is scheduled for release in 2016.
The
terms
of
referenceisavailablefordownload
at:www.industry.gov.au/resource/UpstreamPetroleum/Pages/Offshore-Petroleum-Resources-ManagementReview.aspx.
NEW ENERGY PROJECTS

Australia’s production and infrastructure capacity will be expanded in the future through the completion of
new projects. The Australian Government’s Electricity Generation Major Projects provides a list of major
electricity generation facilities under development, including renewable and non-renewable sources. It isavailable
atwww.industry.gov.au/Office-of-the-Chief-Economist/Publications/Pages/Electricitygeneration-major-projects.aspx.

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REFERENCES

ABS (Australian Bureau of Statistics) (2015), Cat 5206.0—Australian National Accounts: National Income,Expenditure and Product, www.abs.gov.au/ausstats/abs@.nsf/mf/5206.0/.
AEMO (Australian Energy Market Operator) (2015), website ‘2015 National Transmission Network Development
Plan’ page, www.aemo.com.au/Electricity/Planning/National-Transmission-Network-DevelopmentPlan/.
ARENA (Australian Renewable Energy Agency) (2015), Infographic: Our Role in Accelerating Renewable Energy
Technology Innovation, http://arena.gov.au/funding/accelerating-innovation/.
ATC (Australian Trade Commission) (2014), Digital Benchmark Report, www.austrade.gov.au/digitalbenchmark/growth.html#anchor2/.
ATO (Australian Tax Office) (2014a), Petroleum Resources Rent Tax.
https://www.ato.gov.au/Business/Petroleum-resource-rent-tax–– (2014b), Mineral Resource Rent Tax (MRRT), www.ato.gov.au/Business/Minerals-resource-rent-tax/.
BREE (Bureau of Resources and Energy Economics) (2014), Australian Energy Projections 2049–50,
www.bree.gov.au/publications/australian-energy-projections-2049%E2%80%9350/.
CER (Clean Energy Regulator) (2015), Emissions Reduction Fund,www.cleanenergyregulator.gov.au/Emissions-Reduction-Fund/Pages/default.aspx/.
COAG (Coalition of Australian Governments) (2015), COAG Energy Council, www.scer.gov.au/.
Environment (Australian Government Department for the Environment) (2015a), The Renewable Energy
Target (RET) Scheme, www.environment.gov.au/climate-change/renewable-energy-target-scheme/.
–– (2015b), Emissions Reduction Fund, www.environment.gov.au/climate-change/emissions-reductionfund/.
–– (2015c), Repealing the Carbon Tax, www.environment.gov.au/climate-change/repealing-carbon-tax/.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
GA (Geoscience Australia and BREE) (2014), Australian Energy Resource Assessment, Second Edition,www.bree.gov.au/publications/australian-energy-resource-assessment/.
Industry (Australian Government Department of Industry, Innovation and Science) (2015a), COAG
Energy Council, www.industry.gov.au/resource/Pages/AustralianEnergyCouncil.aspx/.
–– (2015b), Energy White Paper, http://ewp.industry.gov.au/.
OCE (Office of the Chief Economist) (2015a), Australian Energy Statistics 2015, Department of Industry,Innovation and Science, www.industry.gov.au/Office-of-the-ChiefEconomist/Publications/Pages/Australian-energy-statistics.aspx/.
–– (2015b), Resources and Energy Quarterly December 2015, Department of Industry, Innovation and Science,www.industry.gov.au/Office-of-the-Chief-Economist/Publications/Pages/Resources-and-energyquarterly.aspx/.
–– (2016a), Energy in Australia, http://www.industry.gov.au/Office-of-the-ChiefEconomist/Publications/Pages/Energy-in-Australia.aspx.
–– (2016b), Resources and Energy Quarterly March 2016, http://www.industry.gov.au/Office-of-the-ChiefEconomist/Publications/Pages/Resources-and-energy-quarterly.aspx.

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USEFUL 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—www.australia.gov.au
Australian Government Department of Industry and Science—www.industry.gov.au
Officeofthe
Chief
Economist/Pages/default.aspx

Economist—www.industry.gov.au/industry/Office-of-the-Chief-

Clean Energy Regulator—www.cleanenergyregulator.gov.au
Commonwealth Law—www.comlaw.gov.au
Energy White Paper—www.ewp.industry.gov.au

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B RU N E I D A RU S A LL A M

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, which means ‘Brunei the Abode of Peace’, is a monarchy state in South-East Asia.
Located between the Malaysian states of Sabah and Sarawak on the north-west coast of the island of Borneo,
it covers a total land area of around 5 765 square kilometres (km2) and has a 161-kilometre coastline along
the South China Sea. Brunei Darussalam has four districts, namely Brunei Muara, Tutong, Belait andTemburong. In 2013, the economy had a small population of about 406 200. More than half of the
population lives in the Brunei Muara district where the economy’s capital city, Bandar Seri Begawan, islocated. This district is also the hub of government and business activities. Seria, a town in the Belait district,is the site of the first commercial discovery of an onshore oilfield and remains at the heart of the oil and gas
industry in Brunei Darussalam.
In 2013, Brunei Darussalam had a gross domestic product (GDP) of USD 28 billion (2010 USD
purchasing power parity [PPP]). The economy’s GDP per capita is the one of the highest in the APEC
region at USD 70 010 (2010 USD PPP). Revenues from the oil and gas sector constitute more than 60% of
the economy’s GDP. This has enabled the citizens of Brunei Darussalam to enjoy a high standard of living,with free health and education among other services. The government has made economic diversification
its main economic priority in order to decrease its strong reliance on the oil and gas industry. This strategy
includes diversification within the oil and gas industry; hence, the government is actively strengthening oil
and gas upstream and downstream activities as well as energy services.
Table 1: Key data and economic profile, 2013
Key dataa, bEnergy reservesc

Area (km2)

5 765

Oil (billion barrels)

1.1

Population (thousand)

406.2

Gas (billion cubic metres)

300

GDP (2010 USD billion PPP)
GDP (2010 USD PPP per capita)28
70 010Coal (million tonnes)–

Uranium (kilotonnes U)–

Sources: a. DEPD (2015); b. EGEDA (2015); c. BP (2015).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

The main energy resources in Brunei Darussalam are oil and gas. The oil that is produced is mostly exported
as term and spot cargoes with a small percentage refined at the Brunei Shell Refinery. About 90% of gas
that is produced is exported as liquefied natural gas (LNG). The remaining gas is used domestically togenerate electricity and town gas. The economy’s largest LNG export partners are Japan and the Republicof Korea. Both countries have long-term contracts with Brunei Darussalam. Another long-term supply
agreement was made in 2013 with a buyer in Malaysia. Further, a growing spot trade was recorded from
Chinese Taipei, China and India during the same period.
In 2013, the total primary energy supply of Brunei Darussalam was 2 847 kilotonnes of oil equivalent(ktoe), of which 79% was represented by natural gas and 21% by oil. Natural gas production was around33.5 million cubic metres a day and oil production was 135 160 barrels per day (bbl/d). The main export
destinations for Brunei Darussalam’s crude oil and condensate in 2013 were the Republic of Korea (18%),
India (16%), Australia (15%), Vietnam (11%), Indonesia (11%) and New Zealand (10%). Meanwhile, otherexport destinations were Thailand (8%), Japan (6%), China (3%), the Philippines (1%) and Singapore (1%).
Brunei Darussalam’s total installed electricity generation capacity of public utilities and auto producers
reached 917 megawatts (MW) in 2013. In the same year, total electricity generated was 4 404 gigawatt-hours(GWh). Almost all of the electricity was generated by natural gas (EGEDA, 2015).

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Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

18 349 Industrial sector

156 Total power generation

4 404

Net imports and others–15 417 Transport sector

447

Thermal

4 402

2 847 Other sectors

313

Hydro

–

200

Nuclear–Geothermal–

Others1.7

Total primary energy supply
Coal– Non-energy

Oil

594 Total final energy consumption

Gas
Others

1 116

2 252

Coal

–

–

Oil

634

Gas

211

Electricity and others271

Source: EGEDA (2015).
FINAL ENERGY CONSUMPTION

Brunei Darussalam’s total final energy consumption in 2013 reached 1 116 ktoe. The transport sector led
the economy’s total energy demand with 447 ktoe, or 40%, of the overall amount. The other sectors(residential, commercial and agriculture sectors combined) followed with 313 ktoe, or 28%, of theeconomy’s energy demand. The remaining amount was for non-energy use (18%) and for the industrial
sector (14%). In terms of energy source, oil accounted for 57% of final consumption, followed by electricity
and other (24%), and gas (19%). Natural gas accounted for 99% of the fuel type used to generate electricity,while 0.95% was generated by diesel fuel and 0.05% from PV solar power system (EGEDA, 2015).
ENERGY INTENSITY ANALYSIS

Brunei Darussalam is committed to reduce 45% of its energy intensity by 2035 from the 2005 level. This isin accordance with APEC’s overall target. In 2013, the economy showed significant improvements for bothprimary intensity and final energy intensity. Primary intensity declined in 2013 by 15% to 100 tonnes of oil
equivalent per million USD (toe/million USD). Similarly, the economy’s final energy intensity decreased
from 56 toe/million USD in 2012 to 39 toe/million in 2013. This was largely due to the reduction of nonenergy use and in the industrial sector by 69% and 22% respectively (Table 3).
Table 3: Energy intensity analysis, 2013
Energy intensity (toe/million USD)

Change (%)

Energy2012

20132012 vs 2013

Total primary energy supply

117

100

–15

Total final energy consumption

56

39

–30

Industry

7.0

5.5

–22

Transportation

15.6

15.7

0.9

Other sectors
Non-energy

10
23

11
7.0

6.2
–69

Source: EGEDA (2015).
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKBrunei Darussalam is heavily dependent on the oil and gas industry as the key driver for economic growth.
The economy’s energy policy is centred on its oil and gas industry. Following the oil production peak at
254 000 bbl/d in 1979, the Oil Conservation Policy was introduced in the early 1980s. This was intended toextend the lifespan of the economy’s oil reserves. Oil production consequently dropped to 150 000 bbl/d
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in 1989. However, the policy was revised in November 1990 when the government removed the limit on
the production ceiling. This resulted in increased production (APERC, 2009). In 2013, the economy’s crude
oil and condensate average production was about 135 160 bbl/d (EIDPMO, Peer Review, 15 April 2016).
In order to satisfy gas export obligations, the Brunei Natural Gas Policy (Production and Utilisation)
was introduced in 2000. The policy aimed to maintain gas production at year 2000 levels, to open new areasfor exploration and development, and to encourage increased exploration by new and existing operators.
Under the Policy, priority is always given to domestic gas use, especially for electricity power generation.
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 carried out by oil and gas companies that hold concession areas in
Brunei Darussalam.
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 thegovernment. PetroleumBRUNEI is given designated areas for which the company has the right to negotiate,conclude and administer petroleum-sharing 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 otherenergy-related matters. The Petroleum Unit, which oversees the development of the economy’s oil and gas
sector, and the 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 Energy Department, Prime
Minister’s Office (EDPMO).
Brunei Darussalam has implemented a series of five-year economic development plans known as
National Development Plans. Currently, the tenth National Development Plan (RKN 2012–17) is in force.
This is the second five-year plan under the long-term development plan, Wawasan Brunei 2035 (Vision
Brunei 2035), which states that the economy’s major goals for the next two decades are:

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 countries in the world; and

To build a dynamic and sustainable economy with an income per capita among the world’s top 10.

In March 2014, the economy launched its first Brunei Darussalam Energy White Paper (EWP). This
describes a framework for strategic actions, which ensures sustainable energy for Brunei Darussalam’s
prosperity.
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, theeconomy works to strengthen the partnership arrangements among all its stakeholders.
Brunei Darussalam is an active member of the Association of South-East Asian Nations (ASEAN). It
likewise supports the implementation of strategies that relate to energy security, the diversification of supply,
energy efficiency and conservation among the regions. The economy is working actively with ASEAN
towards the achievement of the targets set under the ASEAN Plan of Action on Energy Cooperation 2010–
15 (the Action Plan). This includes, among others, the ASEAN Power Grid (APG) and the Trans-ASEAN
Gas Pipeline (TAGP) projects.
The energy sector of Brunei Darussalam plays a vital role in the realisation of Wawasan Brunei 2035.
Energy sector will continue to serve as the major catalyst for the economy’s investment, education andinfrastructure development. Brunei Darussalam Energy White Paper indicated three strategic goals that
address the growth of the energy sector, namely:

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Strengthen and grow oil and gas upstream and downstream activities;Ensure safe, secure, reliable and efficient supply and use of energy; andMaximise economic spin-off from the energy industry, boost local content and secure highparticipation by the local workforce.

In order to assure the achievement of these strategic goals, 10 Key Performance Indicators (KPIs)
have been developed. These KPIs will help address needs across the different segments and parts of thevalue chain in the energy sector in order to achieve the targets set under each strategic goal.
UPSTREAM ENERGY DEVELOPMENT

Brunei Darussalam has numbers of major oil and gas companies that currently operate in the concession
and production sharing areas: the Brunei Shell Petroleum Company Sdn Bhd (BSP), Total E&P Deep
Offshore Borneo B.V. (Total), PETRONAS and Shell Deepwater Borneo. The economy’s existing andpotential oil and gas reserves lie within its northern landmass and extend offshore to the outer limits of its
Exclusive Economic Zone (EEZ). Most of the existing oil and gas production is located in scattered sitesaround 70 kilometres offshore. Although the economy’s oil and gas reserves are expected to last for at least
several decades, a few areas onshore and offshore have been opened up for exploration.
A target has been set to reach a production rate of 430 000 barrels of oil equivalent per day (BOE/d)by 2017 and 650 000 BOE/d by 2035. This is in accordance with the Brunei Darussalam Energy White
Paper. In order to meet its upstream production target, Brunei Darussalam is committed to maintaining its
oil and gas Reserve Replacement Ratio (RRR) of more than one. Specifically, Brunei Darussalam will
undertake several initiatives to stimulate production, such as rejuvenating existing fields, maximising
economic recovery from matured and newly discovered fields and reviewing potential solutions for thedevelopment of uneconomic, small and unconnected fields.
The economy is also aiming to achieve around 100 000 BOE/d from upstream international ventures
investment by 2035. On 19 November 2013, PetroleumBRUNEI was awarded Block EP-1, the onshore
Kyaukkyi-Mindon area located 250 kilometres north of Yangon, Myanmar. This covers an area of 1 135
square kilometres. PetroleumBRUNEI will carry out all petroleum activities in Myanmar under the
production sharing agreement. Other upstream projects for PetroleumBRUNEI abroad include offshore
fields in Sarawak, Malaysia, and a shale gas project in Canada, thereby increasing international investments(PB, 2013).
DOWNSTREAM ENERGY DEVELOPMENT

Brunei Darussalam is aiming to increase the revenue from domestic downstream industries to BND 5 billion
in 2035 in accordance with Brunei Darussalam Energy White Paper. The biggest contributor to the existing
downstream industry in Brunei Darussalam comes from methanol produced from the economy’s natural
gas resources as feedstock. This industry aims to contribute about BND 300 million to the economy
annually, which means increasing the economic output from downstream processing in order to satisfy thegrowing demand, especially for the supply of emerging markets. In order to accommodate these growing
needs, the Brunei Economic Development Board (BEDB) initiated the development of specialised 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 in order to encourage more investors
to venture into developing and diversifying additional downstream opportunities such as gas-based
petrochemicals, and crude- and condensate-based petrochemicals. A priority initiative entitled the ‘Evaluate
Feasibility of Downstream Derivatives’ was likewise established as part of the downstream energy
development in order to ensure the achievement of the target. Enabling such activity under this initiative
could function as a possible extension of the petrochemical chain, which includes ethylene and propylenebuilding blocks.
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 is now considering whether to adopt a comprehensive
policy and regulatory framework in order to support the strategic objectives that have been established forthe energy sector. EIDPMO has initially identified four key regulatory policies and frameworks, which
include, among others, instituting a regulatory body to monitor the local content requirement in the bidding
process for contracts from operators. A Local Business Development (LBD) framework has been enforced
to ensure that there is a fair and level playing field in the market.
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ELECTRICITY MARKETThe Department of Electrical Services, established in 1921, fulfils the regulatory functions for the power
sector. Its purpose includes the management and development of the electricity sector. There are twoelectrical utilities in Brunei Darussalam, the Department of Electrical Services (DES) and the Berakas PowerManagement Company Private Limited (BPMC). BPMC is owned by the Brunei Investment Agency andoperates as a private company 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 at Belingus (Temburong
District) and the 1.2 MW Tenaga Suria Brunei (TSB) photovoltaic demonstration plant. The transmission
system consists of three grids operated by the two electrical utilities (DES, 2013).
ENERGY EFFICIENCY

A 20-year roadmap on energy efficiency and conservation (EEC) was established in May 2015 by the
economy’s National EEC Committee. This roadmap focuses on five major sectors, namely power,
residential, commercial, industrial and transportation. This initiative aims to achieve a 63% reduction in totalenergy consumption of fossil fuel supplies for inland energy use by 2035, which was announced by His
Majesty Sultan and Yang Di-Pertuan of Brunei Darussalam at the United Nations (UN) Climate Summit in
September 2014 (RTB News, 2014).
In order to ensure that this target is achieved, Brunei Darussalam is actively promoting energy
efficiency and conservation through the following implementation of the EEC legislative measures by 2035
(UNFCCC, 2015):
Electricity Tariff Reform—Electricity tariffs were first reformed in the residential sector on the 1
January 2012 with the objective of reducing electricity consumption in this sector. The transitionis from a regressive tariff to a progressive tariff. It will be introduced to other sectors whenappropriate.

Standards and Energy Labelling for Products and Appliances—The Brunei National Energy ResearchInstitute (BNERI), which serves as the economy’s think tank, in collaboration with EIDPMO, iscurrently developing the Standards and Labelling Order for electrical appliances, which is expected
to be implemented in late 2016.

EEC Building Guidelines for the Non-Residential Sector—The EEC Building Guidelines 2015 for NonResidential Buildings were launched by the Ministry of Development in May 2015. All government
and new buildings are obligated to adopt the guidelines whereby an Energy Efficiency Index (EEI)
baseline for kilowatt-hours per square metre is set. It is estimated that with the introduction ofthese baselines, the energy consumption of new buildings could be reduced up to 50%.

Fuel Economy Regulation—EIDPMO is currently working together with the Ministry ofCommunication for the implementation of fuel economy regulations. In order to support thispolicy initiative, the introduction of hybrid cars and fuel-efficient vehicles (FEV), as well as electricvehicles, 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 on energy-efficient appliances and products.

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



Awareness Raising—The government will continue to increase awareness through energy clubs,
energy exhibitions, road shows, seminars and workshops on energy savings and best practices in
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 having a structured maintenance program in place.
BRUNEI DARUSSALAM HOUSEHOLD ENERGY CONSUMPTION SURVEY (2015)

This is the first comprehensive energy consumption survey in Brunei Darussalam. Its purpose is to provide
insights into the consumption behaviour of the residential sector and to recommend policy options andmeasures that have the greatest influence. This project was conducted and supported by the Economic
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Research Institute for ASEAN and East Asia (ERIA) in cooperation with EIDPMO and BNERI. The
survey was completed in December 2015.
RENEWABLE ENERGY

Brunei Darussalam has set a long-term target that requires 10% of the economy’s total power generation
mix in 2035 to be from renewable energy. This represents one of the KPIs under the second key strategic
goals. Renewable energy development in Brunei Darussalam has four major priority initiatives, namely(EIDPMO, 2014):


The introduction of a renewable energy policy 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 research, development and demonstration (RD&D), and technology transfer.

Solar energy is by far the most promising renewable energy, given the economy’s exposure to equatorialsunshine. In July 2010, the economy commissioned a 1.2 MW solar power plant known as Tenaga Suria
Brunei (TSB). TSB is connected to the national power grid and is designed to produce 1 600 megawatthours (MWh) of electricity annually, saving 340 kilolitres of crude oil and avoiding 940 tonnes of CO2
emissions annually. The actual electricity recorded in 2010 was 808 MWh. This saved an equivalent 205
kilolitres of crude oil and avoided 566 tonnes of CO2 emissions into the atmosphere.
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. Other alternative energy sources suchas wind power, hydropower and tidal power are currently being researched by the government.
NUCLEAR ENERGY

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 include:Implementing the highest environmental standards for existing and new industries in accordancewith the established international standards and practices;
Strictly enforcing appropriate regulations on the maintenance of environments that affect publichealth and 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 in 2007 andsubsequently to its Kyoto Protocol in 2009. It also associated itself with the Copenhagen Accord in 2009.
At the 21st session of the Conference of the Parties (COP21) to the UNFCCC, Brunei Darussalam identified
some key actions directed at reducing greenhouse gas emissions by 2035 through the following aspirations(UNFCCC, 2015):


To reduce 63% of the economy’s energy consumption in accordance with the BAU scenario;
To have 10% of the energy mix from the utilisation of renewable energy; andTo reduce 40% of greenhouse gas emissions from morning peak-hour vehicle use in accordancewith the BAU scenario.
N OTA B L E E N E RG Y D E V E L O P M E N T S
ENERGY INFRASTRUCTURE PROJECTSBrunei Darussalam seeks to maximise the potential of the economy’s oil and gas resources and to takeadvantage of its strategic location for trading. One of the key initiatives under Vision Brunei 2035 is todesignate industrial ‘cluster-specific’ sites with supporting infrastructures and facilities. The first site,
established in 2007, was the Sungai Liang Industrial Park (SPARK), designed specifically for downstream
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petrochemical processing activities. The first petrochemical plant constructed at the site, a methanol
production plant, was successfully commissioned in April 2010 (BMC, 2010).
A second industrial site is being developed at Pulau Muara Besar (PMB) for oil field support services,such as an integrated marine supply base (IMSB), fabrication yard and further downstream activities. The
anchoring project will be a USD 4.3 billion oil refinery and aromatics cracker project to be developed by the
Zheijiang Hengyi Group Co. Ltd. The project is expected to begin operation in 2019, with a production
capacity of approximately 175 000 bbl/d. In addition, a new 430 MW cogeneration power plant will be built
at Pulau Muara Besar in order to provide power and steam to industries including Hengyi.
In the power sector, a memorandum of understanding was signed between Brunei’s Government,
Brunei LNG and the Brunei Shell Petroleum Company in order to expand the Lumut Co-Generation Power
Station to an installed capacity of 246 MW, an increase of 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 an improved efficiency greater than 60% through theapplication of combined heat and power integration or cogeneration (EWG, 2012).
Meanwhile, Brunei Gas Carriers Sendirian Berhad (BGC Sdn Bhd.) welcomed its fifth A-Class vesselin the third quarter of 2015. The vessel, named ‘Amadi’, follows the arrival of its sister ship ‘Amani’, BGC’slargest ship with a capacity of 155 000 cubic metres. The replacement of B-class ships owned by Brunei
Shell Tankers (BST), which have a smaller capacity for transporting LNG, to A-class ships is in accordancewith a strategic program by the LNG carrier to modernise and localise its service. BGC provides LNG
transportation services from Brunei Darussalam to Japan, South Korea, Malaysia and Chinese Taipei (BGC,
2015).
THE US-ASIA PACIFIC COMPREHENSIVE ENERGY PARTNERSHIP (USACEP)At the seventh East Asia Summit (EAS) in 2012, President Obama of the United States, 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 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 this 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 anddialogue partners to elevate the role of renewable energy in the region. The project areas cover solar
photovoltaic, wind and hydro (US DOE, 2013).
REFERENCES

APERC (Asia Pacific Energy Research Centre) (2009), APEC Energy Demand and Supply Outlook 4th Edition– Brunei Economy Review,www.ieej.or.jp/aperc/2009pdf/Outlook/Outlook_Volume_II_4E.pdf.

BGC (Brunei Gas Carriers) (2015), BGC—The Launching of AMADI,
http://bgc.com.bn/press_release/the-launching-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) (2015), BP Statistical Review of World Energy June 2015,
www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html.
DES (Department of Electrical Services) (2013), Overview of the Department of Electrical Services,
http://www.des.gov.bn/SitePages/Overview.aspx.
DEPD (Brunei Department of Economic Planning and Development) (2015), Brunei Darussalam Statistical
Yearbook 2014,
http://www.depd.gov.bn/DEPD%20Documents%20Library/DOS/BDSYB/BDSYB%202014.pdf.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
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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.
EWG (APEC – Energy Working Group) (2012), Key Notable Energy Developments since EWG43 Brunei
Darussalam,www.ewg.apec.org/documents/Key%20Notable%20Energy%20Developments%20since%20EWG
43.pdf.
PB (PetroleumBRUNEI) (2013), International – Block EP-1, Myanmar, http://www.pb.com.bn/PBbusinesses-exploration-production.html.
RTB News (2014), The United Nation Climate Summit, 24 September 2014,www.rtbnews.rtb.gov.bn/index.php?option=com_content&view=article&id=22638%3Athe-unitednations-climate-summit&Itemid=106/.
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%20INDC_FINAL_30%20November%202015.pdf.
US Department of Energy (DOE) (2013), U.S.–Asia Pacific Comprehensive Energy Partnership,www.energy.gov/articles/us-asia-pacific-comprehensive-energy-partnership.
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 Shell Petroleum Company Sdn Bhd—www.bsp.com.bn
Energy and Industry Department, Prime Minister’s Office—www.ei.gov.bn
PetroleumBRUNEI—www.pb.com.bn

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

In terms of land area, Canada ranks second only after Russia worldwide. The economy is a neighbour of theUnited States of America (the US) to the south and partly to the west (Alaska). The Canada-US border isthe world’s longest international border and extends to the Pacific Ocean to the west, the Atlantic Ocean tothe east and the Arctic Ocean to the north. Canada is composed of ten provinces and three territories andhas a population of 35.9 million (2013). Most Canadians reside near the southern Canadian borders. In 2013,
Canada’s real gross domestic product (GDP) grew by 2% to USD 1 458 billion. Real GDP per capita grew
by 0.8% over the same period (USD 41 470) (EGEDA, 2015).
Canada has an abundance of natural resources, including fossil fuels. Canada is the fourth largest
energy producer in the APEC region and the fifth largest in the world behind China, the US, Russia andSaudi Arabia. The energy sector directly contributed 10% to Canada’s GDP in 2013 and indirectly
contributed (through purchases of goods and services from non-energy industries) an additional 3.5%
(NRCan, 2014). In 2013, Canada exported CAD 128 billion worth of energy products and imported CAD
55 billion (NRCan, 2014). Canada is one of the world’s top four exporters of crude oil, natural gas, uraniumand electricity (IEA, 2015).
The economy has extensive conventional and unconventional oil, natural gas and coal reserves as wellas significant uranium deposits. It has the world’s third largest amount of proven oil reserves after Venezuela
and Saudi Arabia. The reserves were estimated at 171 billion barrels, of which oil sands accounted for 97%(166.3 billion barrels), at the end of 2014 (CAPP, AER, 2015). The bulk of the oil sands reserves are in theprovince of Alberta although the province of Saskatchewan is also rich in such reserves. Conventional oil
reserves exist in various amounts in six Canadian provinces and territories, namely British Columbia,
Saskatchewan, Ontario, Manitoba, the North West Territories (NWT) and the Yukon. However, Alberta
and Saskatchewan, and Newfoundland and Labrador have the largest onshore and offshore reserves
respectively (NEB, 2015).
Canada has substantial proven gas reserves, which are estimated at more than 2 trillion cubic metres(tcm) and equal to 1.1% of global reserves in 2013 (BP, 2015). The largest concentration of gas reserves isin Alberta and British Columbia, although Saskatchewan, Newfoundland and Labrador, New Brunswick,
Nova Scotia, the NWT and the Yukon also have reserves to a much smaller extent (NEB, 2015).
Canada currently holds 8.7 billion tonnes of proven resources of coal-in-place, of which 6.6 billion
tonnes are recoverable (NRCan, 2016a). More than 90% of Canada’s coal deposits are located in western
provinces, namely Alberta, British Columbia and Saskatchewan, while the rest are located in the eastern
province of Nova Scotia (CAC, 2016).
Canada’s uranium reserves (493 900 tonnes in 2012), most of which are located in the Athabasca Basinof northern Saskatchewan, are the fourth largest in the world after those of Australia, Kazakhstan andRussia. This basin has the world’s largest high-grade deposits (Natural Resources Canada, Peer Review, 22
April 2016). These reserves are equal to 8% of the world’s known resources, which are recoverable at a priceof CAD 128.1 (<130 USD) per kilogram. If the price of uranium were to increase in the future, new uranium
deposits would become economically recoverable and thus Canada’s uranium resources would increase.
Table 1: Key Data and Economic Profile, 2013
Key dataa, bEnergy reserves c, d, e, f

Area (million km2)

9.9

Oil (million cubic metres)

27 187

Population (million)

35.9

Gas (million cubic metres)

2 097

GDP (2010 USD billion PPP)

1 458

Coal (million tonnes)

8 700

GDP (2010 USD PPP per capita)

41 470Uranium (kilotonnes U)c494

Sources: a. EGEDA (2015); b. NEB (2015); c. CAPP, AER, 2015; d. NRCan (2016b); e. SC (2015a); f. SC (2015b).

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E N E RG Y D E M A N D A N D S U P P LY
PRIMARY ENERGY SUPPLY

Canada’s domestic energy production reached 431 107 kilotonnes of oil equivalent (ktoe) in 2013. This
represented an increase of 3.2% compared with 2012 (417 474 ktoe) (ESTO, 2015). Fossil fuel dominatedthis production with its share of about 84%, which reflected no major change compared with 2012 (83.1%).
Oil, including natural gas liquid (NGL), accounted for the largest share (195 249 ktoe, 45%), followed bygas (130 348 ktoe, 30%) and coal (35 039 ktoe, 8.1%). The share of nuclear of the non-fossil energy
production was 5.3% (22 756 ktoe), thereby leaving a share of approximately 11% for renewables. These
consisted of hydro (33 690 ktoe, 7.8%); other renewables (bioenergy), including biomass, wood and waste(12 958 ktoe, 3%); and geothermal, solar, wind and ocean (1 067 ktoe, 0.2%) (ESTO, 2015). Canada is aleading global producer of energy, as evident in its global production ranks for gas and crude oil (fifth in2014) and hydro (second in 2014) (NRCan, 2016c).
Canada is a net exporter of oil, gas, coal and electricity. Canada’s energy exports go mainly to the US.
Between 2000 and 2012, energy exports grew at an average rate of 2.3% per year. Exports continued their
growth in 2013 as apparent in their 4.5% increase compared with 2012 (ESTO, 2015). In 2013, Canada
exported 262 663 ktoe of energy, which consisted of crude oil and NGL (139 121 ktoe), petroleum products(24 718 ktoe), gas (68 856 ktoe), coal and coal products (23 421 ktoe), electricity (5 772 ktoe) and renewables(776 ktoe) (ESTO, 2015). Energy exports accounted for 30% (CAD 146 billion) of domestic merchandise
export revenue (Natural Resources Canada, Peer Review, 22 April 2016).
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

431 107 Industry sector

59 793 Total power generation

636 340

Net imports and other–184 594 Transport sector

61 139Thermal

139 842

Total primary energy supply

245 940 Other sectors

66 272Hydro

391 750

Coal

17 372 Non-energy

23 541

Nuclear87 321

Oil

78 382 Total final energy consumption

210 744

Others17 427

Gas

83 788

Coal

2 653

Others66 398Petroleum products

95 865Natural gas

59 786

Electricity and others

52 440Source: EGEDA (2015).
CRUDE OIL

Canada’s oil production has increased for the past two decades to turn it into the world’s fifth largest oil
producer in 2013 (CAPP, 2016). Its production of crude oil, including NGL, in that year was 195 249 ktoe,
an increase of 6.3% from 2012 (ESTO, 2015). Oil sands’ production, which has increased by 192% since
2000, has been responsible for most of the recent growth in production (CAPP, 2014a). Oil sands’ output
surpassed conventional oil production for the first time in 2010 (NRCan, 2014a). Production from oil sands,
which are mainly located in the Athabasca oil fields in Alberta, has grown consistently since it began in 1967.
In 2013, its production reached 1.9 million barrels per day (Mbbl/D) (CAPP, 2014b), an increase of 5.5%
over 2012 (CAPP, 2013). Conventional oil production in 2013 was 1.5 Mbbl/D (CAPP, 2014b), an increaseof 7.1% from 2012 (CAPP, 2013).
Canada’s crude oil production is geographically dispersed, but comes from three principal sources: theresources in the broader Western Sedimentary Basin, offshore Atlantic Canada and the oil sands. In 2013,
the bulk of crude oil production (83%) occurred in the Western Canadian Sedimentary Basin provinces,namely Alberta (42%), Saskatchewan (35%), Manitoba (3.7%), British Columbia (1.4%) and the NWT(0.8%). Offshore production in the Atlantic Ocean (the Jeanne d’Arc Basin and the Hibernia field)
accounted for almost the entire remaining production (17%), except for small-scale production in Ontario(0.1%) and New Brunswick (0.1%) (CAPP, 2015).
In 2013, the economy’s oil exports, including NGL, (139 121 ktoe) and petroleum products (24 718
ktoe) reflected a significant increase over 2012 of 8.8% and 7.4% respectively (ESTO, 2015). The mainmarket was the US.
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GAS

Canada holds a relatively small share of the world’s proven natural reserves but is a major exporter. In 2013,
natural gas production reached 130 348 ktoe, an increase of 0.3% from 2012 (ESTO, 2015). This is a reversalof a declining trend, which began in 2007 after production peaked in 2006 (BP, 2015). Canada is the world’s
fifth-largest producer of natural gas (NRCan, 2015a).
Western Canada accounted for the bulk (99%) of the economy’s gas production in 2013 with Alberta
as the largest producer (69%) followed by British Columbia (26%), Saskatchewan (3.2%) and the NWT(0.1%) (CAPP, 2015). Eastern Canada’s gas production is mainly offshore in the Atlantic Ocean (1.2%)
together with small-scale production in New Brunswick (approximately 0.1%) (CAPP, 2015).
The economy is the world’s fourth-largest exporter of natural gas (NRCan, 2015a). In 2013, the volumeof its gas exports was 68 856 ktoe, a decrease of 6.4% compared with 2012 (ESTO, 2015).
Although conventional natural gas reserves have depleted, technological advances and rapid
investment in the Western Canadian Sedimentary Basin have renewed the growth potential from shale gas,tight gas and coal-bed methane. Shale gas is emerging as the new low-cost source of natural gas in North
America, resulting in greater investment and research for its development. In Canada, shale gas resources
are found in British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, New Brunswick andNova Scotia. Most of the current drilling and production activities occur in north-east British Columbia in
the Montney and Horn River shale basins (NRCan, 2012).
COAL

Annual coal production has experienced minor fluctuations since 2004 (BP, 2015). In 2013, Canada
produced 35 039 ktoe) of coal, indicating a 4.6% increase over its 2012 production (ESTO, 2015). All of
Canada’s coal production occurs in the Western provinces of Canada, including Alberta, British Columbia
and Saskatchewan (NRCan, 2015b).
Canada is a mid-size coal producer. Approximately half of its annual production of 69 million tonnes(Mt) is metallurgical (coking coal), which is used in steel manufacturing and largely exported, while the otherhalf is thermal coal, which is used domestically for electricity generation (NRCan, 2015b).
Canada exported 67% (23 402 ktoe) of its coal production in 2013, a 12% increase over its 2012 exports(ESTO, 2015). Coking coal accounted for 90% of the exports (NRCan, 2015b). Asia is the primary export
market, accounting for more than three quarters of Canadian exports, while the rest is exported to a numberof European countries, the US, Mexico, and Latin America (NRCan, 2015b). The importance of coal exports
for Canada is evident in the value of its 2013 exports (CAD 5.5 billion) (NRCan, 2015b).
URANIUM

Canada is among the three leading producers of uranium along with Kazakhstan and Australia. Collectively,
these three exporters accounted for about 65% of total global output in 2013(WNA, 2016). Canada
maintained its position as the world’s second largest uranium producer in 2013 when it produced 9331
tonnes of uranium metal (tU) (WNA, 2016). This production passed the 2013 level by 3.6% and accounted
for 16% of global production (WNA, 2016). Current production is concentrated in the Athabasca Basin ofnorthern Saskatchewan (NRCan, 2015c).
The mining and milling of uranium is a major industry (CAD 2 billion per annum) and directly employs
over 3 000 Canadians at the mine sites (NRCan, 2015d). Uranium continues to rank among Canada’s top
10 metal commodities in terms of output value. (NRCan, 2015c).
NEW AND RENEWABLE

Canada has substantial renewable energy resources including bioenergy, hydro, solar, wind, geothermal andocean energy. In 2013, the economy’s total renewable production was 47 715 ktoe consisting of hydro (33690 ktoe), bioenergy (12 958 ktoe) and solar, geothermal, wind and ocean (1 067 ktoe) (ESTO, 2015).
Production was 4.5% above the 2012 level (ESTO, 2015). Renewables accounted for slightly more than
11% of total indigenous energy production in 2013 (ESTO, 2015).
FINAL ENERGY CONSUMPTION

Canada’s total final energy consumption (TFEC) in 2013 reached 210 744 ktoe, a slight increase of 0.8%
over that of 2012 (ESTO, 2015). This consumption makes Canada the APEC region’s fifth largest energy
consumer after China, the US, Russia and Japan (ESTO, 2015).
The single largest sectoral contributor to consumption was the transport sector (61 139 ktoe, 29%)
followed by industry (59 793 ktoe, 28%). A combination of smaller sectors, namely residential, commercial
and public services together with agriculture and non-specified others, accounted for the largest consumers
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C AN AD A(66 272 ktoe, 31%) (EGEDA, 2015). The share of non-energy of Canadian TFEC was 11% (23 541 ktoe)(EGEDA, 2015).
Fossil fuels accounts for the largest share of TFEC (75%), consisting of petroleum products (95 865
ktoe, 46%), gas (59 786 ktoe, 28%) and coal and coal products (2 653 ktoe, 1.2%) (ESTO, 2015). The
remainder is the share of renewables (10 072 ktoe, 4.8%), electricity (41 726 ktoe, 20%) and heat (542 ktoe,0.3%) (ESTO, 2015). However, reductions in consumption of coal and coal products (1.5%) and petroleum
products (approximately 1.8%) compared with 2012 and increases in consumption of gas (6.1%) andrenewables (11%) suggest that the economy is becoming less carbon intensive (ESTO, 2015).
Factors contributing to Canada’s higher consumption of energy relative to that of other industrialised
countries include cold climate that requires 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 636 340 gigawatt-hours (GWh) of electricity in 2013, an increase of 0.5% from theprevious year (EGEDA, 2015). Renewables accounted for the largest share of this generation (64%) withhydro as the major contributor (62%). Other renewables (solar, wind, geothermal etc.) accounted for theremainder. Nuclear’s share was 13.7%, which increased the combined share of non-fossil energy to 78%.
The share of oil, gas and coal-fuelled thermal generators was 22% (EGEDA, 2015). Coal accounted for thelargest share of the latter (46%) followed by natural gas (40%) and other fossil fuels such as diesel, light fueloil, heavy fuel, wood and spent pulping liquor (14%) (SC, 2015c).
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 promoterenewable energy, while discouraging 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, 2014a).
In December 2013, the NWT released a three-year Energy Action Plan calling for the greater use of hydro,
wind, biomass and solar resources instead of imported oil. The territory has developed 55 megawatts (MW)of an estimated 11 500 MW of its hydro potential (NEB, 2014a).
As part of its 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 Stationand six at the Bruce Nuclear Generating Station. These refurbishments will add about 25–30 years to theoperational life of each unit. Refurbishment at Darlington is to start in 2016 with one reactor, andcommitments on subsequent reactors will take into account the cost and timing of preceding refurbishments,
with appropriate off-ramps in place. Refurbishment at Bruce is to start in 2020. This investment will annuallydisplace 31 to 52 Mt in greenhouse gas (GHG) emissions relative to coal or gas-fired electricity.
Low natural gas prices, the rapidly decreasing cost of renewable energy and new regulations which
limit the use of coal have all made Canada’s electricity sector increasingly ‘greener’ (NEB, 2014a). Canada is
the APEC region’s and the world’s second largest hydroelectricity producer after China (IEA, 2015).
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 2013, Canada exported 5 772 ktoe of electricity to the US while
importing 1 472 ktoe (EGEDA, 2015). This makes Canada APEC’s largest exporter of electricity and theworld’s second largest after Germany (IEA, 2015). The bulk of the electricity trade with the US occurs
between the provinces of Québec, Ontario, Manitoba and British Columbia and the neighbouring American
states (NEB, 2015). The excess supply of hydro and nuclear power in 2013 resulted in Canadian net exports
reaching a 10-year high (NEB, 2015).
ENERGY INTENSITY ANALYSIS

Certain factors make Canada a highly energy-intensive economy. They include its vast geography, cold
climate and an industrial structure with a high rate of energy-intensive industries. The economy’s abundantfossil energy reserves and renewable capacity (particularly hydro) at relatively low costs also play a role.
Nevertheless, Canada has been successful at gradually reducing its energy intensity over the past few
decades, as apparent in the respective 2013 figures. Primary energy intensity and final energy consumption
intensity fell by 4.1% and 1.1% from 2012 respectively (EGEDA, 2015). This was mainly because of asignificant decrease in the energy intensity of the residential, commercial, public services and agricultural
sectors, which registered a 3.8% reduction in their energy intensity compared with 2012. Increasing energy
efficiency and reducing energy intensity have been policy goals for the Canadian Government as a means to
mitigate climate change and conserve energy. Among other factors, major improvements in energy intensity
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have been the result of substantial efficiency improvements supported by various measures, programs andregulations introduced by Canadian federal, provincial and municipal governments. An example at thefederal level is the development by Natural Resources Canada of policy guidelines and programs such as
eco-energy efficiency for buildings, housing, industries and vehicles.
Table 3: Energy intensity analysis, 2013
Energy intensity (toe/million USD)

Change (%)

Energy2012

20132012 vs 2013

Total primary energy supply

176

169

–4.1

Total final energy consumption

146

145

–1.1

Industry

29

41

4.7

Transportation

41.8

41.9

0.4

Others

47

46

–3.8

Non-energy

18

16

–11

Source: EGEDA (2015).
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKCanada’s federal government and those of its 10 provinces and three territories have all a role in shaping the
economy’s energy policy. Energy policy at any of these levels of government is market-based for determining
supply, demand, price and trade. The fundamental principles include respect for jurisdictional power granted
under the Constitution Act of 1867 and targeted intervention in the market process in order to achieve
specific policy objectives (e.g. pipeline regulation) through regulation and other means (GOC, 2016a; NEB,
2014a).
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 (i.e. national parks andinternational waters) in accordance with Sections 91 and 92 of the Canadian Constitution (GOC, 2016b;
NEB, 2014a). The provincial governments have the primary responsibility for shaping policies in theirjurisdictions; consequently, energy policy varies from jurisdiction to jurisdiction. Unlike the provinces, thethree territories do not own the ground resources but do share partial management responsibility. In addition
to frontier lands, the federal government is responsible for regulating uranium resources and nuclear energy,
interprovincial/international trade and commerce, trans-boundary environmental impacts, interprovincial
work (e.g. pipelines) and developing policies in the national interest (economic development, health andsafety, and energy security) (GOC, 2016c; NEB, 2014a).
Energy policy at the federal level involves a number of government agencies with regard to thedevelopment and implementation of such policy. Natural Resources Canada (NRCan) is the federal
department that is mandated to develop ‘policies and programs that enhance the contribution of the natural
resources sector to the economy and improve the quality of life for all Canadians’ (NRCan, 2016d). The
National Energy Board (NEB) is an independent federal regulator responsible for pipelines, energy
development and trade issues in the Canadian public interest. Other important government agencies include
Environment and Climate Change Canada, Fisheries and Oceans Canada, Indigenous and Northern Affairs
Canada and Global Affairs Canada.
ELECTRICITY MARKETSThe federal and non-federal actors have distinct roles in the Canadian electricity market. The federal
government is responsible for electricity exports, international and designated interprovincial power lines
and nuclear policy, including regulation and safety. These issues are especially important because theeconomy-wide market is interconnected at many points with the United States in order to form a larger grid
(NEB, 2014b). The provinces and territories have jurisdiction over the generation, transmission anddistribution of electricity within their boundaries. Such jurisdiction also encompasses restructuring initiatives
and electricity prices (NEB, 2014b).

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The electricity industry in most provinces is highly integrated. The bulk of generation, transmission
and distribution 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 appear in
the provinces of Alberta, which has moved to full wholesale and retail competition, and Ontario, which has
established a hybrid system with competitive and regulated elements.
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 generation plus a
reasonable rate of return. Whereas retail electricity prices in Alberta are more market-based than in otherprovinces and territories, and the remaining regulated price plan is gradually being phased out in Ontario,
both regulated and deregulated price plans are offered (NEB, 2013).
Institutional arrangements have been made to improve the reliability of the electricity power system.
The United States Energy Policy Act 2005 called for the creation of an Electric Reliability Organisation(ERO) in order to address concerns about the reliability of the North American grid, which had been
prompted by the 2003 blackout. In July 2006, the Federal Energy Regulatory Commission of the UnitedStates (FERC) certified the North American Electric Reliability Corporation (NERC) as the ERO authorised
the NERC to enforce reliability standards on the owners, operators and users of the bulk power system inboth Canada and the United States (FERC, 2014). The Canadian and United States governments alsoestablished the Bilateral Electric Reliability Oversight Group as a forum in which the United States
Department of Energy, the FERC, the NRCan and the provincial energy ministries can discuss issues ofmutual concern (FERC, 2014).
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
and the Canadian energy-producing provinces in 1985. The latter opened up the oil and gas markets togreater competition by permitting more exports, allowing users to buy directly from producers andunbundling production and marketing from transportation services (NEB, 1996). Oil and gas pipeline
networks continue to be regulated as natural monopolies
Private and state-owned international oil companies’ investments in Canada’s oil and gas sector haverisen rapidly. As per the February 2015 briefing note, addressed to Deputy Finance Minister Paul Rochon,foreign investors are estimated to own 40–50% of the Canadian oil and gas sector (TCP, 2016).
Federally, the Investment Canada Act, which had stipulated that any large investment greater than
CAD 325 million in Canada had to be a net benefit to Canada, was revised as per subsections 14.1(1) and(2) of the Investment Canada Act. For private sector World Trade Organization (WTO) investments, thereview threshold was increased to CAD 600 million starting from 24 April 2015, to be increased to CAD
800 million on 24 April 2017 and CAD 1 billion on 24 April 2019 (ISEDC, 2013). From 24 April 2021
onwards, the threshold level will be adjusted annually based on growth in nominal GDP in accordance withthe formula set out in subsection 14.1(2) (i.e., the growth in Nominal GDP at market prices multiplied by
the threshold amount determined for the previous year) (ISEDC, 2013).
For state-owned enterprise WTO investments, “the review threshold for 2016 is CAD 375 million in
asset value for investments to directly acquire control of a Canadian business by:1.

WTO investors that are state-owned enterprises; and2.

Non-WTO investors that are state-owned enterprises where the Canadian business that is the
subject of the investment is, immediately prior to the implementation of the investment, controlled
by a WTO investor.”“This threshold will be annually revised to reflect the change in Canada's nominal gross domestic
product (GDP) in accordance with the formula set out in subsection 14.1(2) (i.e., the annual change in
Nominal GDP at market prices multiplied by the threshold amount determined for the previous year)”(ISEDC, 2013).

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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, 2012).
Among the many existing regulations, a recent regulation adopted in August 2012 places a performancestandard on new coal-fired electricity. This should further reduce coal consumption in Canada but notnecessarily coal production. The regulation, adopted under the Canadian Environmental Protection Act
1999, is a performance standard that sets an emissions intensity level for Natural Gas Combined Cycle(NGCC) technology, a high-efficiency type of natural gas generation, at 420 tonnes per GWh (GOC, 2016d).
It also contains a caveat in order to encourage new technology for the reduction of greenhouse gas (GHG)
emissions whereby units which incorporate carbon capture and storage (CCS) technology can apply toreceive a temporary exemption from the performance standard until 31 December 2024 (GOC, 2016d).
ENERGY EFFICIENCY

The federal and provincial governments have joint responsibility for energy efficiency; but their roles andresponsibilities vary and target different aspects of efficiency. Each province has ministries responsible foradministering energy and environmental policies and programs, including energy efficiency programs.
Examples of energy efficiency programs include energy-efficient building codes, equipment standards andconsumer rebates. The foundation of all provincial policies rests upon the federal Energy Efficiency Act
1992, which was amended in 2009 to expand its scope and effectiveness (GOC, 2016e). This Act provides
for the creation and enforcement of regulations on the energy efficiency of products and supports thereplacement of the least efficient products with high-efficiency, cost-effective ones.
The Energy Efficiency Act 1992 and related efficiency issues are administered at federal level by the
NRCan through its Office of Energy Efficiency (OEE). The aim is to improve the utilisation of energy by‘leading Canadians to [improve] energy efficiency at home, at work and on the road’ (NRCan, 2015f). The
OEE delivers the ecoENERGY Efficiency program in order to improve energy efficiency for a cleaner
environment and reduced GHG emissions, while saving Canadians money and making the most of Canada’s
natural resources (NRCan, 2015g). Since 2011, the ecoENERGY Efficiency program has invested CAD
195 million to improve energy efficiency in all end-use sectors, thereby making the housing, building andequipment stock more energy-efficient, energy performance more visible and industrial and vehicle
operations more efficient. The ecoENERGY efficiency program addresses the following components ofefficiency.
ecoENERGY Efficiency for Buildings provides information and benchmarking tools to improvethe building energy performance of new and existing buildings.

ecoENERGY Efficiency for Housing encourages the construction and retrofit of low-rise
residential housing, making the stock more energy-efficient.

ecoENERGY Efficiency for Equipment Standards and Labelling introduces or raises energy
efficiency standards for a wide range of products and promotes energy-efficient products throughthe ENERGY STAR® initiative in Canada.



ecoENERGY Efficiency for Industry aids the adoption of an energy management standard andaccelerates energy-saving investments and the exchange of best practice information within
Canada's industrial sector.

ecoENERGY Efficiency for Vehicles provides individual Canadians and Canada's
commercial/institutional fleet sector with decision-making tools for buying and operating theirvehicles in order to reduce fuel consumption. It also promotes vehicle efficiency by introducing
improved vehicle fuel consumption labels and a light-duty tyre information system (NRCan, 2015g).

Apart from the aforementioned CAD 195 million, the government has been investing in alternative
fuels and biofuels in order to diversify its energy sources. Since 2011, the federal government has committed
CAD 3 million to support alternative fuels used in the transport sector (NRCan, 2015g). Federally, there isa further CAD 1.5 billion of funding available in the period 2008–17 to support the production of renewable
alternatives to gasoline and diesel for the development of a competitive domestic industry (NRCan, 2015g).
Additionally, the Canadian Government has introduced the Federal Buildings Initiative (FBI) (NRCan,
2015h). This is a voluntary program that helps facilitate energy efficiency retrofit projects in buildings owned
or managed by the government. Developed and administered by NRCan's OEE, the FBI enables federal
organisations to implement these projects through third-party energy performance contracts without
necessarily using their own capital funds. The initiative enables third parties to work with representatives
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from federal organisations to help implement successful retrofit projects. As of 2015, over 80 retrofit
projects attracted CAD 360 million in private sector investment in order to generate over CAD 47 million
in annual energy cost savings. These projects demonstrated average energy savings of 15–20% and
cut GHG emissions by 295 kilotonnes (NRCan, 2015h).
As of 2015, over 80 retrofit projects attracted CAD 360 million in private sector investment in orderto generate over CAD 47 million in annual energy cost savings. These projects demonstrated average energy
savings of 15–20% and cut GHG emissions by 295 kilotonnes (NRCan, 2015h).
RENEWABLE ENERGY

Canada has an abundance of renewable energy resources. Canada is a world leader in the production anduse of renewable energy, with 19.5% of its total primary energy supply in 2013 originating from renewableenergy resources (ESTO, 2015). At the federal level, NRCan’s CanmetENERGY research centre leads clean
energy research and development. The federal government supports renewable energy, namely small hydro,
wind, solar, bioenergy and marine energy, by funding CanmetENERGY. This organisation engages in
research, development and demonstration to accelerate renewable technologies towards commercialisationand self-sustainability (NRCan, 2015i).
Budget 2016 provided funding in three main areas for energy R&D: 1) CAD 82.5 million over two
years to support the research, development and demonstration of clean energy technologies; 2) CAD 62.5
million over two years to support the deployment of infrastructure for alternative transportation fuels,
including a charging infrastructure for electric vehicles and natural gas and hydrogen refuelling stations; and
3) CAD 50 million over two years to invest in technologies that will reduce GHG emissions from the oiland gas sector. Budget 2016 was a first step in the government’s plans to support clean technology andinnovation. These investments will contribute to Canada’s Mission Innovation commitment. Budget 2016
also signals the government’s plan to provide over CAD 1 billion over four years, starting in 2017–18, to
support clean technology, including in the natural resources sector. Further details about the allocation ofthis funding will be provided as part of the implementation of the Government’s upcoming Innovation
Agenda.
Hydro is the most important source of renewable energy in Canada, supplying 62% of Canada’s
electricity generation in 2013 (EGEDA, 2015). In 2013, Canada’s installed hydraulic capacity was over 75
873 MW (SC, 2013). Among several potential options, Canada promotes small hydropower technologies as
one of the best alternatives to the highly polluting and very costly diesel generation used for electricity
generation in the economy’s most remote communities (NRCan, 2015j). The installed small capacity wasapproximately 3 636 MW in 2014.
Canada has access to large and diversified biomass resources for energy production owing to its large
landmass filled with active forests and agricultural industries. In 2013, bioenergy was the second mostimportant form of renewable energy, with biofuels and renewable waste representing 3% of Canada’s total
primary energy supply (ESTO, 2015).
Canada had 67 bioenergy power plants with a total installed capacity of 1 580 MW in 2013. 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 accounts for 2% of world biofuel (ethanol and biodiesel)
production in 2014, making Canada the fifth largest producer after the United States, Brazil, the European
Union and China (NRCan). The bioenergy sector has been growing significantly as evident in the number(70) and the installed capacity (2 043 MW) of bioenergy power plants in 2014 (NRCan, 2015e). The federal
government, alongside the provinces, has introduced regulations on renewable content to increase future
production and the use of biofuels. The Canadian Government has developed a comprehensive renewablefuels strategy consisting of four elements:
A Renewable Fuels Regulation which establishes a minimum renewable fuel content of 5%
renewable content based on the gasoline pool and 2% renewable content in diesel and heating oil;A commitment of CAD 200 million over four years to the ecoAgriculture Biofuel Capital Initiative
to support farmer participation in the industry;

A commitment of CAD 1.5 billion over nine years to the ecoENERGY for Biofuels program tosupport domestic production; and

A commitment of CAD 500 million to the Next Gen BioFuels FundTM to support next-generation
technologies from non-conventional feedstock (NRCan, 2015e).

Wind is also an important renewable energy source whose provincial leaders are Ontario, Quebec, andAlberta (NRCan, 2015e). However, other provinces with wind potential are increasing the share of wind
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energy in their power mix. Prince Edward Island (PEI) is a major electricity importer from New Brunswick,
which uses coal and nuclear among others. PEI’s indigenous electricity generation is almost entirely wind,but this only accounts for 17% of its demand (NRCan, 2015k).
Canada has vast areas with significant potential for wind resources to make the expansion of windgenerated power very economical. Installed wind power capacity has expanded rapidly in recent years andis forecasted to grow at a rapid pace given the government initiatives in place support its growth. In 2013,
Canada had over 5 100 wind turbines in operation in 187 wind farms, with a total installed capacity of 7 801
MW. In 2014, installed capacity increased further to 9 694 MW (CanWEA, 2015). In May of 2015, Canada
surpassed the 10 000 MW threshold to place it seventh in the world for installed capacity (CanWEA, 2015).
Solar energy has also experienced continuous growth both in thermal and photovoltaic (PV) power.
Cumulative PV power capacity grew to 1 211 MW (±3%) in 2013 (IEA, 2014). Ontario was the leading
province in terms of solar capacity in that year (1 020 MW) (IEA, 2013). Off-grid capacities are not reported
in 2013 but were estimated at approximately 1% of the total installed capacity (IEA, 2014). Other Canadianprovinces, including British Columbia, Alberta and Saskatchewan, were also expanding their solar capacity
in 2014.
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. It has one of the world’s few tidal power plants in Nova Scotia,
generating 20 MW of electricity, and two wave and tidal current technology demonstration projects in British
Columbia and Nova Scotia. In British Columbia, wave energy capacity is 100 kilowatts (kW). The 4 MW
project in Nova Scotia will be the first deployment of commercial-scale tidal turbines in Canada (NRCan,
2015e).
Geothermal power has not experienced similar momentum as solar, wind and biomass. A number ofheat and power generation projects are being considered in Alberta, British Columbia, the NWT and the
Yukon where the highest temperature geothermal resources are located. Demonstration projects are under
way in Western Canada, including the South Meager project in British Columbia, the most advanced
geothermal power plant in Canada. In 2010, there were over 95 000 ground-source heat pumps with the
installed capacity of about 1,045 megawatts of thermal energy (NRCan, 2015e). CanmetENERGY has been
financially supporting the demonstration projects in British Columbia, the NWT, the Yukon and Alberta.
These demonstration projects are not commercially viable.
NUCLEAR ENERGY

Nuclear energy is an important component of Canada’s energy mix. In 2013, nuclear energy accounted for
14% of its electricity generation (EGEDA, 2015). Canadian nuclear power generation is concentrated in theprovinces of Ontario (18 reactors) and New Brunswick (one reactor). In 2012, Gentilly 2, the province ofQuébec’s only nuclear plant, was permanently shut down and put in a safe storage state following thedecision of the provincial energy utility provider, Hydro-Québec, not to proceed with refurbishment becauseof the high cost (Canadian Nuclear Association, 2014). Hydro-Québec is now proceeding with a 50-year
decommissioning plan.
Nuclear energy falls within federal jurisdiction, unlike other energy sources. The federal governmentis responsible for all regulation of nuclear materials and activities along with supporting research anddevelopment (R&D). Concerned with the impact of nuclear activities on health, safety, security and theenvironment, the federal government has put in place a comprehensive nuclear legislation framework. The
latter comprises the Nuclear Safety and Control Act 1997, the Nuclear Energy Act 1985, the Nuclear Fuel
Waste Act 2002 and the Nuclear Liability Act 1985 2 (NRCan, 2015l). They provide the framework fordeveloping nuclear energy in Canada. Nuclear energy issues are administered through a layeredorganisational approach. The involved organisations in this regard include the following.
Natural Resources Canada: Responsible for developing ‘policies and programs which enhance theeconomic and environmental well-being of Canadians’. The Department provides advice on energy
policy, as well as institutional, legislative and financial frameworks for the nuclear industry.

2 The Nuclear Liability and Compensation Act (NLCA), Part 2 of the Energy, Safety and Security Act, received Royal Assent on 26

February 2015. 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 would increase the operator’s liability limit from CAD 75 million under the current Nuclear Liability Act
to CAD 1 billion. Subject to the approval of the Government, the new Act could enter into force on 1 January 2017 once regulations
are completed and ministerial decisions are taken on insurance and government financial cover. The NLCA would repeal and replace
the existing Nuclear Liability Act of 1985

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C AN AD ACanadian Nuclear Safety Commission: An independent agency of the Canadian Government tasked
with ‘regulating the use of nuclear energy and materials to protect health, safety, security and theenvironment and to respect Canada's international commitments on the peaceful use of nuclear
energy’.

Atomic Energy of Canada Limited (AECL) is a federal Crown corporation with the mandate toenable nuclear science and technology and fulfil Canada’s radioactive waste and decommissioning
responsibilities. By enabling nuclear science and technology activities, AECL enables work that has
benefits and applications in the areas of health, safety, security, energy, non-proliferation,
environmental protection and emergency response. AECL’s Chalk River Laboratories in Ontario
is home to Canada’s largest research and development complex.



Following a multi-year restructuring process, AECL now delivers on its mandate through a longterm contract with the private sector for the management and operation of its sites, facilities andassets under a government-owned, contractor-operated model. AECL works to monitor
performance under this model in order to meet government objectives. Canadian Nuclear
Laboratories is responsible for the day-to-day management and operation of AECL’s sites,
including the Chalk River Laboratories, the Whiteshell Laboratories and the Port Hope Area
Initiative Management Office.

Global Affairs Canada (GAC) is responsible for managing Canada’s international commitmentswith regard to nuclear energy, and is the lead on issues of non-proliferation and nuclear security.
GAC also supports the Canadian nuclear industry in terms of pursuing export opportunities.



Health Canada (HC) is responsible for coordinating the Federal Nuclear Emergency Plan (FNEP),a multi-departmental event-specific plan that outlines the roles and responsibilities of federal
organisations in preparing for and responding to a nuclear emergency.

Other departments, such as Transport Canada and Innovation, Science and Economic
Development Canada are not directly involved in nuclear legislation or policy development but
have jurisdiction over areas affecting nuclear energy, such as transportation and research (NRCan,
2015l).

The federal government is the central body, which regulates nuclear energy, but the decision to invest
in nuclear power plants for electricity generation rests with the provinces (in concert with relevant provincial
energy utilities) (NRCan, 2015l). Given the current context and the outlook of each provincial electricity
utility, no new nuclear capacity is projected, although existing operational plants will undergo refurbishment.
Ontario has announced a CAD 25 billion investment into the refurbishment of 10 nuclear reactors: 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 Darlington
is to start in 2016 with one reactor, and commitments on subsequent reactors will take into account the cost
and timing of preceding refurbishments, with appropriate off-ramps in place. Refurbishment at Bruce is tostart in 2020.
CLIMATE CHANGE

Canada is fully committed to address climate change in a meaningful manner while ensuring thecompetitiveness of its economy (GOC, 2016f). Climate change is a complex issue making Canada’s approach
multifaceted and layered at the provincial, federal and international levels. All these levels work incollaboration to ensure that policies, regulations and initiatives are aligned and work in concert.
PROVINCIAL

Provinces/territories hold the jurisdictional authority to regulate natural resources. Consequently, theyplay an integral role in climate policies since energy production and consumption contribute significantly to
Canada’s GHG emissions. As such, each province develops and implements policies, regulations andinitiatives in an effort to mitigate climate change and reduce GHG emissions. Examples of regulations andprograms that focus on reducing direct GHG emissions include the following.
Alberta: This province passed the Specified Gas Emitters Regulation 2007, as amended in 2015.
This requires facilities emitting more than 100 000 tonnes of GHG to reduce emissions by 12%.
Among other options, companies may choose to pay CAD 15 per tonne for every tonne over theirtarget if they do not physically reduce their emission levels (PA, 2015).

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British Columbia: A revenue neutral carbon tax has been applied to the purchase or use of fuels
within the province at a current rate of CAD 30 per tonnes of CO 2 equivalent (British Columbia
Ministry of Finance, 2015).



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 (PNS, 2013).



Ontario: As of April 2014, the province no longer uses coal to generate electricity. Further, theprovincial government has proposed a regulation to ensure no future coal-burning, grid-connected
electricity generation (PO, 2014). The government also introduced the Green Energy and Green
Economy Act 2009, which implemented a feed-in tariff that promotes and facilitates the connectionof renewable generating facilities (Ontario Power Authority, 2014). Ontario’s nuclear plantrefurbishments, a CAD 25 billion investment, also represent a major component of the province’s
climate change mitigation strategy by ensuring that the province’s electricity supply remains almost
entirely non-emitting.

Quebec: This province is part of the Western Climate Initiative, a GHG emissions cap-and-tradesystem with Ontario and California. It has placed a small levy on fuel and fossil fuels (PQ, 2012).



Saskatchewan: The provincial power utility, SaskPower, has made the world’s largest per-capita
investment in carbon capture and storage (CCS) technology at its electricity generating facility at
Boundary Dam. In its first year of operation, the plan captured 400 000 tonnes of carbon dioxide.
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
million tonnes of the world’s GHG emissions each year.

FEDERAL

Energy production and consumption contribute significantly to Canada’s GHG and air pollution emissions.
The Canadian Government’s policies aim at promoting energy efficiency and cleaner technologies, boosting
renewable energy supplies and reducing GHG emissions. Since 2006, the federal government has invested
more than CAD 10 billion to reduce GHG emissions and build a more sustainable environment throughinvestments in green infrastructure, energy efficiency, clean energy technologies and the production ofcleaner energy (EC, 2013a). Closely related to this, the Canadian government promotes investment in clean
technology to help address climate change. Towards this end, its 2016 budget “proposes to provide over
CAD 1 billion over four years, starting in 2017–18, to support clean technology, including in the forestry,
fisheries, mining, energy and agriculture sectors” (Budget, 2016).
The government also takes measures to help Canada adapt to climate change impacts, including withrespect to public infrastructure. Thus, the 2016 budget “proposes to provide [CAD] 129.5 million over five
years, starting in 2016–17, to seven federal departments and agencies to implement programming focusedon building the science base to inform decision-making, protect the health and well-being of Canadians,building resilience in the North and Indigenous communities and enhancing competitiveness in key
economic sectors” (Budget, 2016). It also proposes to provide an additional CAD 40 million over five years
starting in 2016–17 to “integrate climate resilience into building design guides and codes” (Budget, 2016).
The federal government is regulating GHG emissions through a sector-by-sector approach, withregulations already in place in two of the largest emission sectors: electricity and transportation.
Electricity Sector: In 2012, the Canadian Government announced stricter regulations concerningcoal-based electricity generation, with new standards applicable for new and old power plants thathave reached the end of their economic life. The expected result is a cumulative reduction in GHG
emissions of approximately 214 Mt in the first 21 years (EC, 2013a).

Transportation Sector: The proposed final regulation in the transportation sector aims to ensurethat 2 025 passenger vehicles and light trucks will emit around 50% less GHG than 2008 models
while emissions for 2018 model heavy duty vehicles will be reduced by up to 23% (EC, 2013a). The
transportation regulations were developed to align with US Environmental Protection Agency(EPA) standards, in order to work collaboratively towards a common North American standard(EC, 2013a).

The federal government has constitutional authority to regulate emissions with regard to certain
aspects of climate change, even though the provinces have jurisdiction over natural resources and thus
authority over other aspects.
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Thus, “the federal government has jurisdiction to regulate air pollution that is released from a sourcein Canada and experienced in a country outside Canada. Under the Canadian Environmental Protection Act,
1999, the federal Minister of the Environment must first offer an opportunity for the government
responsible for the area in which the source is situated to prevent, control or correct the air pollution, before
acting” (PA, 2013).
With regard to industrial emissions, the Canadian provinces “have jurisdiction over most types ofindustries, including mining and manufacturing, and therefore they also have jurisdiction to regulate
emissions from these industries. The federal government, in turn, regulates emissions from those industries
that come under its jurisdiction, including several that may have a significant environmental impact, such asaviation and interprovincial and international transportation” (PA, 2013).
However, the federal and provincial governments have both authority when it comes to addressing
GHG and climate change per se. The provincial governments have jurisdiction to regulate most types ofbuildings, businesses, industries and intraprovincial transportation, and therefore they also have jurisdiction
to control the greenhouse gas emissions related to these matters. While the federal government has
jurisdiction over certain industries [mentioned above], its jurisdiction to regulate the emission of greenhousegases is based in its power to regulate toxic substances as an aspect of criminal law. In 2005, the government
added six greenhouse gases to the List of Toxic Substances set out in Schedule 1 of the Canadian
Environmental Protection Act, 1999, and therefore it now, arguably, has jurisdiction to regulate the emissionsof these greenhouse gases (PA, 2013).
In 2012, the federal government used this jurisdiction as it “made regulations to reduce the emissionof carbon dioxide from coal-fired generation of electricity. Since no court has ruled on the constitutionalityof this exercise of federal jurisdiction, which some people might characterise as relating to electricity
generation (a subject matter of exclusive provincial jurisdiction – the regulations remain in effect”(PA, 2013).
In the following year, the federal government “again made regulations under the Canadian Environmental
Protection Act, 1999 to reduce greenhouse gas emissions, this time in relation to emissions from heavy-duty
vehicles and engines. However, this exercise of federal jurisdiction was not based on the federal power toregulate toxic substances as an aspect of criminal law. Rather, it relied on the federal government’s power toregulate international and interprovincial trade and commerce, since the regulations set emissions standards
that heavy-duty vehicles and engines must meet in order to be imported or transported across a provincial
border. Accordingly, while the most obvious means for the federal government to regulate the emission ofgreenhouse gases might be by using its power to regulate toxic substances as an aspect of the criminal law,other federal powers might also be used, depending on how a regulation is structured” (PA, 2013).
This creates a dichotomy between the two institutional powers in terms of regulating emissions comingfrom natural resource production. The federal government has indicated the next step of the Canadianclimate change plan is to regulate the remaining major sources of emissions, including the oil and gas sector(EC, 2013a). The federal government has been in negotiations with industry and all provincial governments
since 2012.
INTERNATIONAL

Canada’s international commitments are a driver of action at the federal and provincial levels. Canada is asignatory to the United Nations Framework Convention on Climate Change (UNFCCC). In 2009, Canada
signed the Copenhagen Accord and committed to reducing GHG emissions to 17% below 2005 levels by
2020 (EC, 2013b). Since the end of the Doha round of negotiations under the UNFCCC in December 2012,
Canada has continued its engagement in the UNFCCC negotiations to support the establishment of a fairand comprehensive global climate change regime. The Cancun Agreement endorsed this approach. The
intention is to develop a possible future cap-and-trade system, and develop and deploy clean energy
technologies in a regionally focused effort.
Canada actively participated in the Twenty-First Conference of the Parties (COP21) in Paris(December 2015) and made a full commitment to the resulting agreements. As laid out by Prime Minister
Justin Trudeau in November 2015, the “five principles upon which Canada’s actions on climate change
would be based and on which “Canada delivered concrete actions” at the Twenty-First Conference of theParties are as follows (EC, 2016).


Canada will act based on the best scientific evidence and advice
Throughout the negotiations, Canada actively supported including in the agreement of the needto limit average global temperature rises to well below 2 degrees Celsius above pre-industrial
levels, as well as pursuing efforts to limit increases to 1.5 degrees. Canada has advocated for this33

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recognition of the urgency of the threat to small-island states, like the Marshall Islands with whom
we [Canada] now stand as part of the High Ambition Coalition.


Canada will support and implement policies that contribute to a low-carbon economy
Canada joined the Carbon Pricing Leadership Coalition (CPLC), which brings together leadersfrom government, business and civil society, to support the introduction and implementation ofcarbon pricing practices around the world. Canada also endorsed the Fossil Fuel Subsidy Reform
Communiqué in support of accelerating action to eliminate inefficient fossil-fuel subsidies.

Canada will work with our provinces, territories, cities and Indigenous leaders
Canada has emphasized a collaborative and inclusive approach, setting out with a Canadiandelegation of dedicated federal, provincial and territorial representatives including Premiers andMinisters of the Environment, leaders and members of opposition parties, Indigenous leaders,
representatives from youth organisations, environmental NGOs and members of the business
community. And throughout the negotiations, Canada consistently advocated for the inclusion in
the Paris Agreement of language that reflects the importance of respecting the rights ofIndigenous Peoples.

Canada will help the developing world tackle the challenges of climate change
Canada pledged [CAD] 2.65 billion over the next five years to support developing countries’
transition to low-carbon economies that are both greener and more climate-resilient. This is themost significant Canadian climate finance contribution ever. During COP 21, Canada announced
financial support totalling [CAD] 275 million for the Least Developed Countries Fund, the Climate
Risk and Early Warning Systems, the G7 Initiative on Climate Risk Insurance, the G7 African
Renewable Energy Initiative, and to address short-lived climate pollutants. Canada continues tosupport countries in need and recognises the specific circumstances of the least-developed
countries and small-island developing states.

Canada views climate change not just as a challenge, but as an historic opportunity tobuild a sustainable economy
Prime Minister Trudeau joined French President François Hollande, US President Barack Obama
and Bill Gates to announce the launch of Mission Innovation, an ambitious clean technology
initiative that seeks to double government investment over the next five years in clean energy
research and development, and to spur business investment in clean technology.

Canada has taken measures to ensure the fulfilment of its commitments under COP21. They include
an agreement between all the Canadian provinces and territories and federal government reached at the First
Ministers’ Meeting on 3 March 2016 to work together to “create the Vancouver Declaration on Clean
Growth and Climate Change. The Declaration is the first step in developing a concrete plan to achieve
Canada’s international commitments to reduce greenhouse gas emissions and build on the momentum of
the United Nations Paris Agreement” (Budget 2016). Moreover, the Canadian 2016 budget proposes toprovide “almost [CAD] 2.9 billion over five years, starting in 2016–17, to address climate change and air
pollution issues” (Budget, 2016).
To ensure the continued active engagement of Environment and Climate Change Canada, Natural
Resources Canada and Global Affairs Canada towards advancing Canada’s climate change and air pollution
objectives, the 2016 budget proposes to provide CAD 61.3 million over five years, starting in 2016–17(Budget, 2016). The objective is to ensure Canada’s continuing leadership role in international environmentalorganisations, such as the UNFCCC, and “will allow Canada to work toward a North American clean energy
and environmental agreement with the United States and Mexico (Budget, 2016).
N OTA B L E E N E RG Y D E V E L O P M E N T S
LNG TERMINAL PROJECTS

A dramatic shift occurred in the North American liquefied natural gas (LNG) market over the past decade.
In the early 2000s, mounting concerns over decreasing conventional supplies of domestic natural gas
resulted in bullish forecasts about future LNG demand in North America, prompting an investment boom
in building LNG import facilities (NRCan, 2015m). One such investment included the Canaport LNG
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terminal in Saint John, New Brunswick, which began gas-import operations in 2009 and has remained
Canada’s only operating LNG facility (regasification) since.
However, despite these early concerns, natural gas production in Canada and the US surged becauseof the technological advancements made in unconventional natural gas production. Greater supply fromshale gas and tight gas formations outpaced the growth in natural gas demand, which ultimately enabled the
US to become increasingly self-sufficient in natural gas. Given this significant shift in the US, Canadian
exports to the US have declined.
Canada intends to diversify its market by exporting its gas in the form of LNG to overseas markets.
This objective requires LNG export terminals. The west coast of Canada has experienced a significant
number of proposed LNG facilities to address the growing demands of the Asia-Pacific region. However,these projects involve long lead times, which are needed for obtaining approvals, establishing markets andconstructing facilities (NEB, 2014a).
In 2016, Canada does not have any operational export facilities. However, as of early October 2015,
the National Energy Board (NEB) “approved 23 applications for long-term LNG export licences, andanother seven applications [were also] before the Board” (NEB, 2016). The majority of the proposed LNG
projects are in British Columbia although there are proposed LNG projects in Nova Scotia, New Brunswick
and Quebec (NEB, 2016). In fact, in the third quarter of 2015, the NEB issued three competing LNG export
licences in New Brunswick and Nova Scotia. However, the NEB stated that the issuance of the licences did
not mean that plants would necessarily be constructed because market considerations would determine any
such plans (CBC, 2015).
According to the NEB, “there is considerable uncertainty regarding how much LNG will be exported
from Canada. The numerous projects currently under construction around the world could provide
sufficient capacity to meet global LNG demand for many years to come, leaving limited room for Canada
in the market. However, Canada’s advantageous location relative to the Asian market, and its abundantnatural gas supplies, could make it a competitive player in the global LNG market. Other uncertainties that
could impact Canada’s future LNG export volumes include North American and global natural gas prices,
crude oil prices, the pace of global LNG demand growth and the ability of LNG proponents to addressenvironmental and social concerns” (NEB, 2016).
As of December 2015, British Columbia’s planned LNG export terminals are all awaiting approval
and/or final investment decisions; thus, their construction is yet to start (LWS, 2015). Final investment
decisions will be influenced by factors, including construction costs, pricing arrangements and competition
with other existing or potential LNG exporters (NEB, 2014a).
To encourage investment in LNG projects, the Canadian federal government’s 2016 budget maintains
the existing accelerated capital cost allowance (CCA, which is currently available for certain LNG facilities(Budget, 2016). Accordingly, for assets acquired before 2025, an “effective CCA rate of 30 per cent isavailable for eligible liquefaction equipment and 10 per cent for related buildings. This treatment serves as
an incentive to invest in new facilities that supply LNG to new markets” (Budget, 2016). This is “consistent
with Canada’s G20 commitment to eliminate fossil fuel subsidies over the medium term” for which “thegovernment intends to maintain this tax preference as currently legislated and allow it to expire as scheduled”(Budget, 2016).
Once in operation, an LNG terminal generally falls under provincial regulations. However, LNG
terminal proposals require numerous federal and provincial environmental assessments and permits. Amongother federal requirements, a licence from the NEB is required to export LNG. The NEB ensures that the
proposed volume of gas exports does not exceed the surplus, which is needed to meet estimated domestic
demand (NRCan, 2015m).
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 based mainly 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 distance is far from the major refining hub on the US’s Gulf Coast and ocean ports, which
would provide access to the expanding overseas market. The government and industry are working together
to find options to access markets. Consequently, numerous pipeline proposals are in the regulatory processor have recently received approval. One such proposal, of major significance, is the Keystone XL, which isintended to increase oil exports to the US. However, in November 2015, the US Government rejectedTransCanada’s request for its construction (New York Times, 2015).

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Meanwhile, TransCanada began leading the proposed Eastern Mainline Pipeline (4 600 km). The USD
12 billion project would transport 1.1 million barrels per day (bbl/d) of oil from Alberta and Saskatchewan
to refineries and port terminals in Eastern Canada by converting an existing west-east gas pipeline andadding an extension to connect it to Canada’s Atlantic ports, from which oil could be shipped to the US andother export markets by tankers. The extension would link Canada’s Ontario-Quebec border to the Port ofSaint John, New Brunswick (Pipeline International, 2015).
ABORIGINAL ENGAGEMENT

The participation of Aboriginal peoples is a critical factor in Canada’s ability to realise the full benefits ofenergy resource development. A key reason for the importance of this participation, on a number of levels,is the close proximity of energy development projects to indigenous communities, lands and traditional
territories. Moreover, consultation with Aboriginal groups is also a requirement, both for the Crown, in
fulfilling its legal and constitutional accountabilities to respect and uphold Aboriginal or treaty rights, andfor the private sector, as part of its regulatory requirements.
The Canadian Government has undertaken efforts and adopted initiatives in recent years to enhance
its engagement and consultation efforts with Aboriginal communities. As part of this policy, and buildingon certain court decisions, Aboriginal consultations are integrated into environmental assessment andregulatory processes as a way of identifying and addressing potential rights-based impacts before decisions
are made. Further, consultation protocols or agreements with Aboriginal groups are also established for
project reviews. In 2012, the Canadian Government introduced the Responsible Resource Developmentplan.
As many proposed energy infrastructure projects on Canada’s west coast pass through or near
Aboriginal communities, and to enhance relationship building, the Major Projects Management Office, West
(MPMO West), was established in 2014. This serves as a single window for coordinating activities on energy
infrastructure development with the BC government, Alberta First Nations and industry (GOC, 2011).
Green infrastructure on reserves, including for water, is an important issue and closely related to energy
and climate change. Appreciating its importance for this matter among others, the Canadian government,
through its 2016 budget, aims to improve the “reserve water and wastewater infrastructure and waste
management by providing [CAD] 2.24 billion to First Nations communities to support such improvements”
over the next five years (Budget, 2016). The proposed investment is part of the first phase of its 10-year plan
“to invest in green infrastructure. The second phase of this plan will include additional investments in green
infrastructure in Indigenous communities” (Budget, 2016).
ARCTIC AND OFFSHORE ENERGY

Exploration and study by the oil and gas industry and the Canadian Geological Survey has indicated strong
potential for petroleum discoveries in Canada’s northern region, particularly its Arctic section, since the1950s. However, the respective costs of developing the fields and transporting their fuels to the market havebeen quite high. In particular, the low oil prices of the previous decades and transportation bottlenecks havemade discoveries uneconomical to develop (NRCan, 2007). However, interest in the region’s vast oil andgas potential has grown on the assumption of high oil and gas prices, and the promise of new pipeline
systems. For example, the potential of the offshore continental shelf is considered quite high with 19
significant discovery licences issued for the Arctic islands and 60 licences in the Mackenzie Delta/Beaufort
Sea region (NEB, 2014a). Discoveries in these regions exceed 1 billion barrels of oil and 10 trillion cubicfeet (Tcf) of gas.
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), the Canada Petroleum Resources
Act (CPRA) and the National Energy Board Act. However, Canada’s Atlantic offshore oil and gas industry
is regulated by the Canada-Nova Scotia Offshore Petroleum Board and the Canada-Newfoundland andLabrador Offshore Petroleum Board. It is important to note that a 1972 federal moratorium restricts
offshore field development off the Pacific coast of Canada, where there is an estimated 9.8 billion barrels ofrecoverable resources (NRCan, 2013).
In order to enhance responsible resource development, the Canadian Minister of Natural Resources
introduced legislation in early 2014, which is intended to change Canada’s offshore oil and gas regime. The
Energy Safety and Security Act (2015) (GOC, 2015) contains amendments to the Canada-Nova Scotia Offshore
Petroleum Resources Accord Implementation Act, Canada-Newfoundland Atlantic Accord Implementation Act, the Canada
Oil and Gas Operations Act (COGOA) and the Canada Petroleum Resources Act (CPRA) (NRCan, 2014b).

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The proposed changes to the mentioned Acts “focus on four main areas: prevention, response,
accountability and transparency. They help to strengthen safety and security further in order to prevent
incidents and ensure a swift response in the unlikely event of a spill.” (NRCan, 2014b)
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–– (2015c), Uranium Production, www.nrcan.gc.ca/energy/uranium-nuclear/7705.
–– (2015d), Uranium in Canada, www.nrcan.gc.ca/energy/uranium-nuclear/7693.
–– (2015e), About Renewable Energy, www.nrcan.gc.ca/energy/renewable-electricity/7295.
–– (2015f), Office Energy Efficiency, www.nrcan.gc.ca/energy/offices-labs/office-energy-efficiency/.

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APEC E N E RG Y O VE R VI E W 2015

C AN AD A–– (2015g), ecoENERGY Efficiency and Alternative Transportation Fuels, www.nrcan.gc.ca/energy/officeslabs/office-energy-efficiency/5691/.
–– (2015h), Federal Building Initiative, www.nrcan.gc.ca/energy/efficiency/buildings/eefb/3705.
–– (2015i), CanmetENERGY, www.nrcan.gc.ca/energy/offices-labs/canmet/5715/.
–– (2015j), Small Hydropower, www.nrcan.gc.ca/energy/renewable-electricity/small-hydropower/7363.
–– (2015k), Wind Energy R&D Park and Storage System for Innovation in Grid Integration,www.nrcan.gc.ca/energy/funding/current-funding-programs/cef/4979.
–– (2015l), Nuclear Energy, www.nrcan.gc.ca/energy/uranium-nuclear/7711.
–– (2015m), Canadian LNG Projects, www.nrcan.gc.ca/energy/natural-gas/5683/.
–– (2016a), What is Coal? www.nrcan.gc.ca/node/14377.
–– (2016b), About Uranium, www.nrcan.gc.ca/energy/uranium-nuclear/7695/.
–– (2016c), Key Facts and Figures on the Natural Resources Sector, www.nrcan.gc.ca/publications/keyfacts/16013.
–– (2016d), About Us, www.nrcan.gc.ca/department.
Ontario Power Authority (2014), OPA FIT Program: Introduction, http://fit.powerauthority.on.ca/fitprogram/introduction/.
PA (Province of Alberta) (2015), Alberta Climate Change and Emissions Management Act: Specified Gas Emitters
Regulation, www.qp.alberta.ca/documents/Regs/2007_139.pdf.
Pipeline International (2015), ‘TransCanada Reaches Energy East Deal with Major Natural Gas
Distributors’, 26 August 2015,
http://pipelinesinternational.com/news/transcanada_reaches_energy_east_deal_with_major_natural_gas_distributorsv/98439.
PNS (Province of Nova Scotia) (2013), Nova Scotia Greenhouse Gas Emission Regulations,
www.novascotia.ca/just/regulations/regs/envgreenhouse.htm.
PO (Province of Ontario) (2014), Ontario Ontario's Climate Change Update 2014,
https://dr6j45jk9xcmk.cloudfront.net/documents/3618/climate-change-report-2014.pdf.
PQ (Province of Quebec) (2012), Quebec in Action Greener By 2020: 2013–2020 Climate Change Action Plan,
www.mddelcc.gouv.qc.ca/changements/plan_action/pacc2020-en.pdf.SC (Statistics Canada) (2013),
Table 127-0009: Installed Generating Capacity, by Class of Electricity – Hydraulic Turbine,
http://www5.statcan.gc.ca/cansim/a26.
SC (2015a), Canada’s Population Estimates, Third Quarter 2015, www.statcan.gc.ca/dailyquotidien/151216/dq151216e-eng.htm?HPA.
–– (2015b), Land and Freshwater Area, by Province and Territory, www.statcan.gc.ca/tables-tableaux/sumsom/l01/cst01/phys01-eng.htm.
–– (2015c), Table 128-0014: Electricity Generated from Fossil Fuels—Annual (Megawatt Hour),www5.statcan.gc.ca/cansim/a26?lang=eng&retrLang=eng&id=1280014&tabMode=dataTable&srch
Lan=-1&p1=-1&p2=9.
The Canadian Press (TCP) (2016). Andy Blatchford. Level of foreign ownership unclear in energy sector
as PM seeks more cash: memo,
http://www.thecanadianpress.com/english/online/OnlineFullStory.aspx?filename=DOR-MNNCP.4bc2c29d089044b0b10270a470d99506.CPKEY2008111303&newsitemid=36112783&languageid=1.
WNA (World Nuclear Association) (2016), World Uranium Mining Production, http://www.worldnuclear.org/information-library/nuclear-fuel-cycle/mining-of-uranium/world-uranium-miningproduction.aspx.
USEFUL LINKS

Atomic Energy of Canada Ltd—www.aecl.ca
Canada Gazette—www.gazette.gc.ca
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APEC E N E RG Y O VE R VI E W 2015

C AN AD A

Canadian Association of Petroleum Producers—www.capp.ca
Canadian Nuclear Association—www.cna.ca
Canadian Nuclear Laboratories—www.cnl.ca
Environment 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 E N E RG Y O VE R VI E W 2015

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. Locatedin South America, it shares borders with Peru to the north, Bolivia to the north-east and Argentina to thewest. Its coastline runs along the Pacific Ocean for 6 435 km, with an average width of 175 kilometre (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 (Intendente) appointed by the President. In 2013, the economy’s
population was around 18 million, with 87% living in urban areas (INE, 2013b). Forty per cent of the
population resides in Santiago, the capital (INE, 2013a). Given the size and shape of its territory and numberof inhabitants, Chile’s average population density was almost 23 inhabitants per km2 in 2013, although it ismuch higher in metropolitan areas such as Santiago and Valparaíso, having as many as 455 and 110 people
per km2, respectively (INE, 2013a).
Chile’s economic growth is based in solid macroeconomic fundamentals, such as fiscal responsibility,
an independent central bank and a floating exchange rate. Chile has more than doubled its gross domestic
product (GDP) per capita, from USD 8 728 in 1990 to USD 19 973 in 2013 (2010 USD purchasing power
parity [PPP]). It is one of the fastest growing economies in South America with an average annual growthrate (AAGR) of 3% between 1990 and 2013. In 2013, Chile’s GDP reached USD 349 billion (2010 USD
PPP), which represents an increase of 3.1% from 2012 levels, led by retail sales (7.2%), mining (6.1%) andbusiness services (3.5%). Copper accounted for nearly 93% of mining exports and 41% of total exports(BCL, 2014). Foreign direct investment, closely related to mining investment, decreased by 35% to
USD 17 billion in 2013 owing to lower commodity prices (UNCTAD, 2015). Despite Chile’s economic
activity being highly correlated with final energy consumption, where the mining and industry sectors
accounted for 35% of final energy consumption in 2013 and represented around 25% of Chile’s economic
activity (BCL, 2015), the economy has shown a remarkable reduction in energy intensity. Almost 98% of
the total exports were under trade agreements with 60 economies, including the European Union, Mercosur(a regional trade group comprising Argentina; Brazil; Paraguay; Uruguay and Venezuela), India, China, Japan,
Korea, Mexico and the United States.
Despite the diverse geography and abundant natural resources, the territory is very limited in fossil fuelresources, making Chile a net energy importer; thus, one of its mainstay priorities revolves around a steadyenergy supply. Fossil fuel reserves are limited, so nearly the entire fossil fuel supply is imported (around 65%
of total primary energy supply (TPES) in 2013). Chile imports around 98% of its oil and 71% of its gas, but
despite high oil and gas import dependence, hydro and biomass contributed about 30% of TPES in 2013.
Oil production declined from 15 million barrels in 1981 to 1.1 million barrels in 2013 (Agostini andSaavedra, 2009; ENAP, 2014), maintaining proven oil reserves of 1.9 million cubic metres (mcm) in 2013.
The government is currently focusing on exploration investment through the National Petroleum Company(ENAP in Spanish), as evidenced by an increased exploration budget of USD 800 million annually until
2020.
Table 1: Key data and economic profile, 2013
Key dataa
Area (km2)

Energy reservesb, c, d
756 102

Oil (million barrels)

150

Population (million)

17.8

Gas (million cubic metres)

9.0

GDP (2010 USD billion PPP)

349

Coal (million tonnes)

171

GDP (2010 USD PPP per capita)

19 973

Uranium (kilotonnes of U)

3.7

Sources: a. EGEDA (2015); b. MEC (2014); c. EIA (2014); d. CCHEN (2013).

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E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

According to Expert Group on Energy Data Analysis 2015, APEC Energy Working Group (EGEDA),
Chile’s TPES increased by 3.9% from 2012 to 2013 to reach 38 649 kilotonnes of oil equivalent (ktoe).
Approximately 41% of this energy volume was supplied in the form of crude oil and its by-products, 17%
as coal, 11% as natural gas and the remaining 31% as other sources, particularly biomass 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 reduced by nearly 2% from2012 to reach 25 207 ktoe in 2013. Despite its small contribution to the TPES, Chile’s energy output fromnon-fossil sources increased by 8.6% from 2012 to 2013.
In regard to fossil energy resources, Chile’s proved crude oil reserves amounted to 1.9 mcm by theend of 2014, with most of it located in the southern Magallanes region. In light of the low domestic
production, nearly all of Chile’s crude oil supply of 15 844 ktoe in 2013 came from imports that also included
by-products such as diesel, gasoline and liquefied petroleum gas (LPG) (EGEDA, 2015). Eighty per cent ofChile’s demand of 4 055 ktoe for natural gas in 2013 was met by imports and the rest by domestic production(EGEDA, 2015). Chile’s domestic coal production is mainly located in the region of Magallanes, with total
recoverable coal reserves estimated at 171 million tonnes. By 2013, domestic production accounted for 25%of the total supply (EGEDA, 2015).
Chile is abundant in renewable energy (RE) resources, whose contribution to the TPES is high,totalling 12 106 ktoe and representing nearly 85% of the economy’s total domestic energy production in2013 (EGEDA, 2015). Chile’s primary supply of non-fossil energy in 2013 mainly comprised biomass andhydropower.
In 2013, Chile’s total net installed electricity capacity was 17 997 megawatts (MW), representing an
increase of 255 MW (1.5%) from 2012, with thermal power plants representing 65% of the total capacity.
The remainder was contributed mainly by hydropower (33%). It is important to mention the drastic change
in the contribution of hydro and thermal sources to the TPES since 2006, when they respectively comprised
54% and 46% of the total electricity capacity, respectively.
By 2013, Chile’s electric system was organised around the following systems:
Northern Grid (SING): 3 759 MW, 100% thermal (51% coal and 39% natural gas, and 10% oil anddiesel);

Central Interconnected System (SIC): 13 826 MW, 55% thermal (21% diesel, 18% natural gas, and
16% coal), 43% hydro and 2% wind;Aysen Grid: 50 MW, 51% thermal (100% diesel), 45% hydro and 4% wind;Magallanes Grid: 100 MW, 100% thermal (85% natural gas and 15% diesel); and

Los Lagos Grid: 6.2 MW, 88% thermal (100% diesel) and 12% hydro.
FINAL ENERGY CONSUMPTION

During 2013, Chile’s total final energy consumption was 26 581 ktoe, representing an increase of 6.4% fromthe previous year.
Energy demand was fairly balanced between the industrial (37%), transport (31%), and the residential,commercial and public sectors – jointly grouped as ‘other sectors’ – (30%), and the remaining 2.4%
represented non-energy use.
By energy source, more than half of Chile’s final energy demand was met by petroleum products (51%)
which were primarily consumed by the transport and industrial sectors, followed by electricity and othersources (43%), natural gas (5.4%) and a marginal share of coal. Oil consumption increased by 7.6%, while
gas and coal consumption decreased by 0.6% and 21%, respectively, and electricity consumption rose by
6.6% (EGEDA, 2015).

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Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

14 955 Industry sector

9 903 Total power generation 73 065

Net imports and others

25 207 Transport sector

8 148

Thermal46 841

Total primary energy supply

38 649 Other sectors

7 899

Hydro

19 737Coal

6 644 Non-energy

631

Nuclear–Oil

15 844 Total final energy consumption

26 581Others

6 487

Gas

4 055

Coal

151

Others12 107

Oil

13 541Gas

1 432

Electricity and others

11 456

Source: EGEDA (2015).
ENERGY INTENSITY ANALYSIS

Energy intensity has been declining since 2005, thus indicating more efficient use of energy sources. The
transport, and residential, commercial and public sectors showed a reduction of 4.2% in energy use since
2005.
Chile’s primary energy supply in 2013 was 106.9 tonnes of oil equivalent per million USD (toe/million
USD), down 0.3% from 107.3 toe/million USD in 2012. The energy intensity for the final energy demand
increased by 2.1% to 74 toe/million USD in 2013 from 72 toe/million USD in 2012. The final energy
demand for both the transport and industry sectors increased by 4.8%. Energy intensity reduced by 1.6% inthe ‘others’ sector, while non-energy use fall by 18% in 2013 compared to 2012.
Table 3: Energy intensity analysis, 2013
EnergyEnergy Intensity (toe/million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

107.3

106.9

–0.3

Total final energy consumption

72

74

2.1

Industry

26

27

4.8

Transportation

22

23

4.8

Other sectors

22.2

21.9

–1.6

Non-energy

2.1

1.8

–18

Source: EGEDA (2015).
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 andthe rules of the free market. It has reaped various benefits as the economy has grown significantly. Fromthe 1980s to 2013, 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. Chile is ranked 34
among 183 economies in the report Doing Business 2014.
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Being an open-market economy, Chile is highly integrated with the world markets. Its participation infree trade agreements has increased its options for sustainable development, as evidenced by increased tradeopportunities, reduction of its dependency on mineral exports and creation of trade products with higher
value-added.
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 to supply shocks and high dependence on imports.
The Chilean Parliament approved the creation of a Ministry of Energy in November 2009 and in
February 2010 the new Ministry of Energy started operations. It 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 and development of public policy instruments.
In December 2015, the Chilean Ministry of Energy presented the Energy 2050: Chile’s Energy Policy toguide energy policy in the economy in the long term (MEC, 2015a).
FISCAL REGIME AND ENERGY PRICES

Since 2001, Chile’s fiscal policy has been guided by the rule of cyclically adjusted balance, also known as the
Structural Balance Rule. This policy aims to maintain medium-term equilibrium in fiscal accounts, adjusting
the government’s incomes by the economic cycle and approving the government spending according to thisincome. The 2006 Fiscal Responsibility Law introduced new rules on the investment of accumulating assets.
In addition, it covers central government agencies, but not the central bank, public non-financial enterprises,
the military sector or municipalities.
PETROLEUM-BASED FUELSIn Chile, prices for petroleum-based fuels are set by international market conditions and across all stages ofthe value chain, including retail sales at service stations. However, specific excise taxes (IEC in Spanish) arecharged on transport fuels (gasoline, diesel, liquid petroleum gas (LPG) and compressed natural gas (CNG)).
In February 2011, the government introduced the Consumers’ Protection System for Volatility inInternational Oil Prices (SIPCO) to reduce uncertainty over domestic prices for oil products. This system
was replaced in July 2014 by a new mechanism called the Fuel Prices Stabilisation Mechanism (MEPCO in
Spanish), which changes the previous SIPCO mechanism by reducing the price’s band and setting a limit on
the weekly variation of fuel prices to no more than CLP 5 per litre per week. Finally, MEPCO converts theoil international price in local currency to assess the value of the final price protection on the consumer.
Under this system, a price band is determined around the average price between the historical andfuture prices of a fuel; if the price of the fuel rises or falls outside this band, the excise tax is adjusted tocounteract the price change. Thus, significant variations in price are absorbed into the IEC excise tax system,
and consumer risk is minimised.
ELECTRICITY

Costumers in the electricity market are divided into regulated and non-regulated customers.
Regulated customers: This term refers to customers with a power connection below 2 000 kilowatts(kW) and who are connected to the grid through a local distribution company. The regulated priceconsiders the distribution fee, node price based on the marginal cost of energy of the respective
tender, capacity charge and transmission charge.



Non-regulated customers: This term refers to customers with a maximum demand above 2 000
kW, who are free to negotiate directly with the power generation companies.

Chile has four different energy grid systems. The two most important are the SIC and SING. By law,they have to coordinate the operation of their power plants through the respective Economic Dispatching
Centres (CDEC-SIC and CDEC-SING). These centres are independent entities in charge of coordinating
and programing the dispatch of energy to meet the demand at the least possible cost, which is based on themarginal cost of generation.
ENERGY MARKETSThe electricity market in Chile encompasses power generation, transmission and distribution. The regulatory
framework for Chile’s electricity supply industry is based on the principle of competitive markets forgeneration and supply. Private companies wholly serve the electricity market, while the government remains
as a regulator, policy-maker and technical consultant to identify the requirements to meet the projected
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demand growth. The Ministry of Energy is the main regulator of the electricity industry in Chile and is
supported by the National Energy Commission (Comisión Nacional de Energía or CNE) and theSuperintendence of Electricity and Fuels (Superintendencia de Electricidad y Combustibles or SEC).
ENERGY EFFICIENCYEnergy efficiency 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 energy efficiency
measures.
In terms of energy efficiency, 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 meansof contributing to the achievement of this goal. Furthermore, in pursuing these objectives, the Ministry ofEnergy entrusts them to the Chilean Energy Efficiency Agency, which is responsible for implementing manyof these policies by promoting, disseminating and implementing dedicated programs, opening new markets
and exploring opportunities in the field of energy efficiency, and developing energy efficiency markets torecognise and reward leading energy efficiency companies. The current goal is to foster the efficient use ofenergy as an energy resource. The government has established a 20% savings goal by the year 2025 after
considering the expected growth in energy consumption for the economy.
The government promotes energy efficiency measures through the Action Plan on Energy Efficiency
2020, which aims to reduce final energy demand by 12% by 2020 (MEC, 2012). These measures areapplicable to industry and mining, transport, buildings, end-use devices and heating.
Table 4: Chile’s Action Plan on Energy Efficiency 2020
Industry and mining

Transport

Buildings
End-use devices
Heating
















Promote energy management systems.
Promote energy cogeneration.
Encourage efficient technologies.
Improve energy efficiency standards for light- and heavy-duty
vehicles.
Use new transport technologies in heavy-duty vehicles.
Promote public transportation.
Promote electric vehicles.
Encourage efficient technologies.
Promote building labelling.
Enhance appliance labelling.
Establish minimum efficiency standards.
Promote minimum lighting efficiency standards.
Encourage new technologies in the use of firewood.
Improve firewood quality.

Source: MEC (2012).

The government is implementing the Action Plan for Energy Efficiency 2020. Since 2012 theSuperintendency of Electricity and Fuels certifies security, emission levels and energy efficiency standards
on firewood home appliances, which have been part of the institutional framework for energy efficiency
policies owing to the importance of firewood residential consumption in Chile (MEC, 2012). In addition, in
2014, the Chilean government approved the Minimum Energy Efficiency Standards Act that applies torefrigerators and lamps, and new regulations on vehicle labelling and water heating were also approved.
RENEWABLE ENERGYIn April 2008, Law 20.257 (Law of Non-Conventional Renewable Energy) was enacted. It added toprevious amendments to the Electricity Law introduced through Law 19.940 (2004) and Law 20.018 (2005).
It mandates that electricity companies include a percentage of non-conventional RE (RE excluding largehydropower plants, NCRE) as a share of the total energy sold.
Specifically, the law requires that between 2010 and 2014, 5% of the total annual withdrawals ofelectricity generators that obtain energy from electric systems with an installed capacity greater than 200
MW must be sourced from non-conventional renewable sources. Beginning in 2015, the required level of
non-conventional energy sources is slated to rise by 0.5% annually, to reach 10% of the total energy
production by 2024.

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In October 2013, the government of Chile enacted Law 20.698 to promote the expansion of NonConventional RE. This law doubles the goal previously set by Law 20.257 and specifies that 20% of theelectricity sold by 2025 must come from non-conventional renewable energies. In addition, it requires the
Ministry of Energy to conduct annual public procurement of energy blocks generated from nonconventional RE, which will serve to fulfil the required NCRE quotas. These actions would occur only if it
is foreseen that the market will not meet the requirement by itself.
At the end of March 2016, Chile’s energy matrix had an installed capacity of 2 864 MW of NCRE,
with solar and wind representing 37% and 32%, respectively. Similarly, an additional 2 693 MW is underconstruction, 18 907 MW worth new projects have secured the required environmental permissions and 7
328 MW are under environmental evaluation.
Table 5: Chile’s NCRE capacity
Operation(MW)

Construction(MW)

EQR-approved(MW)

Under Evaluation(MW)

Biomass

417

0

112

47

Biogas

48

0

8

0

Wind

910

428

5 966

1 905

Geothermal

0

48

120

0

March 2016

Mini hydro

433

25

455

75

Solar – PV

1 056

2 082

11 266

4 826

Solar – CSP

0

110

Total
2 864
2 693
Note: EQR = Environmental Qualification Resolution.
Source: CIFES (2016).

980

475

18 907

7 328

The rising demand for electricity and policy incentives make renewables 3, especially solar energy, an
attractive option for increased domestic power generation, because of high solar radiation in the north. The
capacity potential of solar photovoltaic (PV) and concentrated solar power (CSP) is about 1 200 gigawatts(GW) and 548 GW, respectively, which is sufficient to cover local electricity demand. Additionally, windpotential is estimated at 37 GW and hydro at 12 GW (MEC, 2014).
After the publication of the Energy Agenda in 2014, the Chilean government established the National
Centre for the Innovation and Development of Sustainable Energies (CIFES) to provide support to the
Ministry of Energy and the Chilean Economic Development Agency (CORFO) in the design,
implementation and evaluation of strategic projects in sustainable energy. CIFES replaces the former Centre
for Renewables Energies.
CIFES is a government institution that aims to strengthen the development of non-conventionalenergy sources in Chile by providing financial and technical support.
The main objectives include:Promoting the use of RE sources by reducing financial and technical barriers against theirimplementation.



Facilitating the development of a local energy industry through technological transfer anddevelopment of capabilities and knowledge in sustainable energies.

Promoting demand for technologies based on renewable energies.

Encouraging the local development of scientific and technological knowledge in renewableenergies.

CIFES runs the following programs to support the development of renewable energies:

3 ‘Renewables’ include hydro, solar, wind, geothermal, biomass and marine energy. The term ‘other renewables’ excludes

hydropower.

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

The Solar Strategic Program, which focuses on developing projects based on solar technologies,
including generation, storage and technological services.



The Sectorial Self-sufficiency Program, which aims to reduce production energy costs and provide
energy independency to projects without a constant energy supply or with high levels ofcontamination.

Support program for the development of mini hydro projects, which promotes and develops theuse of mini hydro projects aligned with the 100 Mini Hydro Plan led by the Ministry of Energy.

Program to develop and promote the use of marine energy with assistance from the Marine Energy
Research and Innovation Centre (MERIC). MERIC has a budget of USD 20 million, of whicharound 80% is from CORFO.
NUCLEAR ENERGY

In 1964, Chile created the Commission on Nuclear Energy (Comisión Chilena de Energía Nuclear or
CCHEN) to address problems related to the production, acquisition, transfer, transport and peaceful usesof atomic energy. Further, the CCHEN is in charge of the operation and regulation of the two reactors
located in the Santiago metropolitan region, which have been used for research and civil purposes. In 2007,
the Nuclear Power Working Group was created to assess the potential advantages and risks associated withthe use of nuclear energy for power generation. Its duties are as follows:

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

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
implementation 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 (MEC, 2007).
In 2010, the study Nuclear Electricity: Possibilities and Challenges (MEC, 2010) stated that the developmentof nuclear energy in Chile should aim to close the identified gaps: ‘…technological, institutional andfundamental knowledge such as a complete geological information of the economy, modify the current legal
and regulatory 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 to solve before considering nuclear power as an energy alternative.
If these problems are solved by the mid-2010s, the study estimates that nuclear power plants may be included
as part of Chile’s energy matrix by the year 2024.
The Presidential Advisory Commission for Electricity Development was established in 2011. One of
the main conclusions of a study undertaken by it is that nuclear power would be a ‘strategic insurance thatwould ensure sustainable energy supply in the long term’. The study predicted that nuclear energy could
become part of 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 (MEC, 2011).
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 (MEC, 2015b). 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, and that the possibility of using nuclear energy
should not be discarded without a ‘rational and comprehensive analysis and considering all relevant aspectsof this technology and the feasibility of its use in Chile’. Finally, the report concludes that social approval iscrucial 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
additional studies related to technology, location, waste management and public approval has beenrecognised. Energy 2050 notes that nuclear energy is not an option for Chile at the present time, and its
uptake depends on further research regarding security and economic rationality as well as community
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acceptance. Moreover, the Chilean government established the Nuclear Energy Power Committee in 2015
to undertake comprehensive research on these issues.
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. This action plan assigns institutional responsibilities for adapting, mitigating
and strengthening Chile’s response to climate change (CONAMA, 2008). According to the results ofvulnerability studies conducted by the Ministry of the Environment (MMA in Spanish), the effects of climatechange can summarised as follows:

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



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

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

While Chile’s contribution to global carbon emissions is very low, at around 0.2% of the total carbon
dioxide emitted globally in 2010 (UN Stats, 2013), its territory is highly vulnerable to the effects of climatechange. Glacial melting, shifts in rainfall patterns, expanding deserts and the greater frequency of El Niño
weather patterns will have an impact on the economy’s water supply, food production, tourism industry andmigration, as well as on its socio-economic 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 areas most vulnerable to climate change, where adaptation would be required.
In July 2014, the Plan for the Adaptation to Climate Change in Biodiversity was approved. This plancontains 50 measures that aim to reduce and mitigate the effects of the climate change on biodiversity in thefour areas most vulnerable to climate change.
The government’s Intended National Determined Contribution (INDC) is to reduce greenhouse(GHG) intensity by 30% by 2030, based on 2007 levels. The INDC goals are established on intensity-basedtargets. To reach the targets outlined in the INDC and to ensure the sustainability of Chile’s energy future,
the government is preparing the National Action Plan for Climate Change 2016–21. This document contains thefollowing thematic axes and strategies.
THEMATIC AXESSTRATEGY

Adaptation

Strategic guidelines for determining vulnerability,
disaster risk reduction and strengthening crossadaptation.

Mitigation

GHG inventories; implementation of mitigation
actions, accounting actions mitigation andcompliance with international commitments.

Creation and capacity building

Communication, education and outreach;
institutional strengthening; scientific investigation;
development of trading strategies for Chile;development, transfer and adoption of technology;
and funding sources to implement the Plan.

Source: MMA (2015).
N OTA B L E E N E RG Y D E V E L O P M E N T S

Energy 2050 is an effort to establish a long-term vision on energy policy. The main goal of Energy 2050 is
to document Chile’s long-term energy policy, which will be approved by Chilean citizens. The policy
addresses the citizens’ concerns as well as aims to work towards improving energy security and reliability.
The creation of this document is envisaged across the following stages and goals (MEC, 2015a):
1. Energy Agenda (May 2014): The aim here is to design and execute a long-term energy policy with technical,
political and social support. The Agenda considered the development of regulations, energy standards and48

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the legal framework required to have a sustainable and reliable energy matrix by 2025. The goals andpurposes of the Energy Agenda 2014 can be summarised as follows:- Reduce the electricity marginal cost by 30% in the Central Interconnected Grid (SIC);- Reduce the prices of the electricity supply bids by 25%;
- Lift existing barriers for Non-Conventional Renewable Energies to increase the participationof renewal energies up to 45% of the new electric generation capacity by 2025;- Foster the efficient use of energy as an energy resource, establishing a 20% savings goal by
the year 2025, considering the expected energy consumption growth in the economy as ofthat date;- Set up a fuel price stabilisation system to reduce the volatility of internal fuel prices;- Turn ENAP (National Oil Company) into a main actor to tackle the energy challenges of themember economy government; and- Develop by 2015 a long-term energy policy that will be validated by the Chilean citizens.
2. Energy Road Map: This road map is oriented to create agreements and build a shared long-term vision
for the sector under the concepts of sustainability and inclusion. According to the Energy Road Map, theeconomy’s future energy policy needs to consider the following features:- Compatibility with the environment and communities;- Universal and equitable access;- Essential condition for development;- Opportunity for innovation;- Efficient production and consumption; and- Energy security.
3. Energy 2050 – Chile’s Energy Policy: released in December 2015, describes the four pillars of Chile’s
energy policy: 1) energy security and energy supply quality; 2) energy as a development engine;3) environmental compatibility; and 4) energy efficiency and education. Nuclear energy is not a short-term
option under the Energy 2050, but it is proposed that further research be considered in the next review of
the Energy Policy.
The main goals of Energy 2050 are summarised in following table.
Table 6: The main goals of Energy 2050 by 2035 and 2050
By 2035

By 2050

Interconnection
with
other
AndeanElectric
Interconnection System members (Peru, Ecuador,
Colombia and Bolivia) and with other South American
economies, particularly Mercosur economies (Brazil,
Venezuela, Paraguay, Uruguay, Argentina, Bolivia and
Venezuela).
Energy disruption reduced to less than four hours per
year.
Continuous and reliable access to energy services for all
new vulnerable dwellings.
All projects developed have associativity mechanisms
between project developers and communities to foster
local development and better performance.
Be among the five economies having lowest residential
and industry energy costs.
At least 60% of electricity generation from renewablesources.
Thirty per cent emissions intensity reduction incomparison with 2007.
All large energy consumers (industry, mining andtransport) to apply energy efficiency measures.

Energy sector GHG emissions below limits
established in the economy-wide goals.

49

Energy disruption reduced to less than one
hour per year.
Universal and equitable access to reliable
and modern energy services.
Territorial, regional and local planning andmanagement tools conforming to the energy
policy are in place.
Be among the three economies having
lowest energy costs.
At least 70% of electricity generation fromrenewable sources.
Energy consumption decoupled from GDP
growth.
All new buildings will be constructed as per
the Organisation for Economic Cooperation and Development (OECD)
standards of efficient construction andsmart systems of energy management.

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All municipalities to adopt regulations declaring
traditional biomass as solid fuel, thus including it incalculations of GHG emissions levels.
All new passenger vehicles to be evaluated under energy
efficiency standards.

Hundred per cent of the main categories ofappliances in the Chilean market are energy
efficient.
Energy efficiency practiced at all levels ofsociety.

Source: MEC (2015a).

REFERENCES

Banco Central de Chile (BCL) (2014), Cuentas Nacionales 2008-2014.
–– (2015), website, ‘Base de datos estadísticos’, page,
http://si3.bcentral.cl/Siete/secure/cuadros/home.aspx.
CCHEN (Comisión Chilena de Enérgia Nuclear) (2013), Uranium and Thorium Resources in Chile Prospection
and Recovery Experiences. July 2013,www.unece.org/fileadmin/DAM/energy/se/pp/unfc_egrc/unfc_ws_IAEA_CYTED_UNECE_Sa
ntiago_July2013/10_July/2_Orrego_Uresources_Chile.pdf.
CIFES (Centro para la Innovación y Fomento de las Energías Sustentables). Reporte Cifes (2016)www.cifes.gob.cl/documentos/reportes-cifes/reporte-cifes-marzo-2016/
Claudio A. Agostini and Eduardo Saavedra (2009), La Industria del Petroleo en Chile. Estudios Publicos 114.
www.cepchile.cl/1_4431/doc/la_industria_del_petroleo_en_chile.html#.Vm-MRUp96Uk.
CONAMA (Comisión Nacional del Medio Ambiente) (2008), Plan de Acción Nacional de Cambio Climático
2008-2012, www.mma.gob.cl/.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), website,‘APEC Energy Database’ page, www.ieej.or.jp/egeda/database/database-top.html.
EIA (United States Energy Information Administration) (2014), Chile,www.eia.gov/countries/country-data.cfm?fips=CI.
ENAP (Empresa Nacional del Petróleo) (2014), website, ‘Memorias 2014’ page.
www.enap.cl/pag/547/886/memoria.
INE (Instituto Nacional de Estadística) (2013a), Compendio Estadístico,
www.ine.cl/canales/menu/publicaciones/compendio_estadistico/compendio_estadistico2013.php/.
–– (2013b), Demograficas y Vitales, www.ine.cl/canales/chile_estadistico/familias/demograficas_vitales.php.
MEC (Ministry of Energy of Chile) (2007), La Opción Núcleo Eléctrica en Chile,www.minrel.gob.cl/minrel/site/artic/20110826/asocfile/20110826141156/informe_2_.pdf.
–– (2010), Núcleo Electricidad en Chile: Posibilidades, Brechas y Desafíos,www.energia.gob.cl/sites/default/files/nucleo_electricidad_en_chile.pdf.
–– (2011), Informe Comisión Asesora para el Desarrollo Eléctrico, http://generadoras.cl/wpcontent/uploads/111100-Informe-Comisi%C3%B3n-Asesora-para-el-Desarrollo-El%C3%A9ctricoCADE.pdf.
–– (2012), Plan de Acción de Eficiencia Energética 2020,www.amchamchile.cl/UserFiles/Image/Events/octubre/energia/plan-de-accion-de-eficienciaenergetica2020.pdf.
–– (2014), El Potencial Eólico, Solar e Hidroeléctrico de Arica a Chiloé,
www.minenergia.cl/archivos_bajar/Estudios/Potencial_ER_en_Chile_AC.pdf.
–– (2015a), Energy 2050. Energy Policy of Chile, www.energia2050.cl/uploads/libros/libro_energia_2050.pdf.
–– (2015b), Generación Núcleo - Energética en Chile: Hacia una decisión racional,
www.cchen.cl/index.php?option=com_content&view=article&id=1038:generacion-nucleoelectricaen-chile&catid=2:uncategorised&Itemid=179.
MMA (Ministry of the Environment) (2015), Propuesta de Estructura y Contenidos Para el Plan de Acción
Nacional de Cambio Climático 2016-2021, http://portal.mma.gob.cl/wpcontent/uploads/2015/08/Propuesta-contenidos-PANCC-2016-2021-Fase-II-Licitacion_conanexos.pdf.
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UNCTAD (United Nations Conference on Trade and Development) (2015), Conference on Trade and Development World Investments Report 2015,
http://unctad.org/en/Pages/DIAE/World%20Investment%20Report/World_Investment_Report.
aspx.
UN Stats (United Nations Statistics Division) (2013), Millennium Development Goals Indicators - Carbon Dioxide
Emissions (CO2), http://mdgs.un.org/unsd/mdg/SeriesDetail.aspx?srid=749.
USEFUL LINKS

Chilean Commission of Energy (CNE)—www.cne.cl
Chilean Energy Efficiency Agency (AChEE)—www.acee.cl
Economic Load Dispatch Centre of Central Interconnected System—www.cdec-sic.cl
Economic Load Dispatch Centre of the Northern Interconnected System—www.cdec-sing.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
National Centre for Innovation and Development of Sustainable Energy (CIFES)—www.cifes.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.clSuperintendence 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 isbordered by the East China Sea, the Yellow Sea and the South China Sea. Its population of 1.4 billion isapproximately one-fifth of the world’s population. China has a land area of approximately 9.6 million square
kilometres (km2), with diverse landscapes, which consist of mountains, plateaus, plains, deserts and river
basins. Its total maritime area is 4.7 million km2 and the length of its coastline is 32 000 km (NBS, 2015).
After reforming and opening up its economy in 1978, China entered a new period of high-speed
growth. Its entry to the World Trade Organization (WTO) in 2001 contributed further to its prosperity inthe first decade of the twenty-first century. In 2004, China overtook Japan as the leading Asian exporter andin 2009, surpassed Germany to become the world’s leading exporter. By 2014, China’s merchandise exports
accounted for 12% of the world’s trade exports (WTO, 2015). In 2013, China’s gross domestic product(GDP) was 13 246 billion (2010 USD purchasing power parity [PPP]), with the primary, secondary andtertiary industries accounting for 4.8%, 47% and 48% respectively (EGEDA, 2015; NBS, 2015).
Because of its huge population and booming economy, China plays an increasingly important role in
the world’s energy markets. According to BP, despite the slowing consumption and production growth from
historical averages, China still dominates the world energy market as the world’s largest energy consumer,
producer and net importer (BP, 2015). In 2014, China accounted for 23% of the world’s total primary energy
consumption (BP, 2015). However, its per capita primary energy supply, at 2.2 tonnes of oil equivalent in2013, is far lower than that of many developed economies and below APEC’s average of 2.9 tonnes of oil
equivalent (toe) (EGEDA, 2015).
China is rich in energy resources, particularly coal. According to BP statistics published in June 2015,
China had recoverable coal reserves of approximately 114 500 million tonnes, proven oil reserves of
18.5 billion barrels and proven natural gas reserves of 3.5 trillion cubic metres (tcm) (BP, 2015). In addition,
China has 400 gigawatts (GW) of economic hydropower potential, more than any other economy. Coal andoil resources have been utilised more extensively than natural gas and hydro for power generation andindustrial development.
The reserves per capita of coal, oil and gas are all well below the worldwide average levels. The
limitations of its energy reserves per capita force China to conserve its resources. From 2000 to 2013, thecompound annual growth rate (CAGR) of final energy demand is 6.9% and the CAGR of GDP is 6.1%
(EGEDA, 2015).
Table 1: Key data and Economic Profile, 2013
Key dataa, bEnergy reservesc, dArea (million km2)

9.6

Oil (billion barrels)

18.5

Population (million)

1 363

Gas (trillion cubic metres)

3.5

GDP (2010 USD billion PPP)

13 246

Coal (million tonnes)

GDP (2010 USD PPP per capita)

9 722

Uranium (kilotonnes of U)

114 500
181

Sources: a. EGEDA (2015); b. NBS (2015); c. BP (2015); d. OECD-NEA (2014).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

China’s primary energy supply has expanded sharply since 2001. This expansion has been driven mainly by
rapid economic growth, especially in energy consumption by heavy industry. In 2013, the total primaryenergy supply increased 2.5% compared with 2012, reaching 2 856 million tonnes of oil equivalent (Mtoe),including net imports and other. Of this, coal was the dominant source, accounting for 71%, followed byoil (24%), gas (7.9%) and others (9.5%) (EGEDA, 2015).

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Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Indigenous production

2 456 051 Industry sector

Net imports and others

461 545 Transport sector

Power generation (GWh)

1 054 350 Total power generation

5 431 637

227 499

Thermal

4 247 009

2 856 420 Other sectors

448 188Hydro

920 291

2 018 271 Non-energy

71 921

Nuclear111 613

Oil

487 563 Total final energy consumption 1 801 957

Others152 724

Gas

159 218

Coal

753 027

Others191 368

Oil

451 443

Gas

107 615

Electricity and others

489 872

Total primary energy supply
Coal

Source: EGEDA (2015).

Since the 1990s, Chinese authorities have encouraged fuel switching (for example, from coal to cleaner
fuels), introduced energy-efficiency initiatives in order to reduce pollution and emissions from energy use
and optimised the existing energy structure. However, with lean oil and gas resources, the share of coal in
total domestic energy production is still at a comparatively high level. In 2014, coal production reached 1
845 Mtoe, 2.6% lower than 2013. Total coal consumption reached 1 962 Mtoe, 0.1% higher than 2013. This
figure also represented 51% of global coal consumption in 2014 (BP, 2015).
China has been the world’s second-largest economy in terms of electric power generation capacity
since 1996. Its electric power industry experienced a serious oversupply problem in the late 1990s, duelargely to lower demand after the closure of inefficient state-owned industrial units that were major
consumers of electricity. Subsequently, however, a power supply shortage developed because of rapid
economic expansion after 2001. From 2000–13, electricity generation output increased quickly from 1 356
terawatt-hours (TWh) to 5 437 TWh, of which thermal power generation accounted for 77% of total power
generation. In 2013, installed generation capacity reached 1 342 GW (EGEDA, 2015).
The power supply structure has diversified, with wind power and nuclear energy generation increasing
rapidly. In 2013, total power generation in China was 5 432 TWh. Thermal power accounted for 78% (4247 TWh of total generation, hydropower 17% (920 TWh), nuclear energy 2.1% (112 TWh) and others 2.8%
(153 TWh) (EGEDA, 2015).
FINAL ENERGY CONSUMPTION

Final energy consumption in China reached 1 802 Mtoe in 2013, 1.1% higher than in 2012. The industrial
sector was the largest consumer, accounting for 58.5% of total final energy consumption, followed by thetransport sector (13%). Other sectors, including residential, commercial and agricultural, totalled 25%, andnon-energy use was 4% (EGEDA, 2015). By energy source, coal accounted for 42% of total final energy
consumption, following by electricity and others (27%), oil (25%) and gas (6%).
ENERGY INTENSITY ANALYSIS

China has reduced energy intensity in the last two decades. The intensity of primary energy supply and final
energy demand in 2013 have been reduced by 53% and 61% respectively compared with 1990. These are
the biggest reductions among the APEC economies. However, energy intensity is still very high and there isa lot of room for improvement (EGEDA, 2015).
In 2011, China eliminated more than 3 GW of small thermal power plants and 24 million tonnes (Mt)of backward cement production capacity (MEP, 2012). With all these efforts, the intensity of final energy
demand has decreased 1.2% year-on-year in the industry sector. However, because of the booming economy
and transportation needs, car purchases are high, which has resulted in increased energy intensity in thetransportation sector.

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Table 3: Energy intensity analysis, 2013
Energy intensity (toe/million USD)

Change (%)

Energy2012

20132012 vs 2013

Total primary energy supply

191

182

–4.8

Total final energy consumption

122

115

–6.1

Industry

74

67

–9.8

Transportation

15

14.5

0.2

Others

28.5

28.6

0.1

Non-energy

4.9

4.6

–5.5

Source: EGEDA (2015).
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 to economic restructuring, which is also an important indicator of social progress. Achieving thegoal of a low-carbon 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 increased by factors of 1.4, 2.6, 4 and
168 fold respectively.
The Thirteenth Five-Year Plan for National Economic and Social Development (2016–20) wasapproved at the National People’s Congress in March 2016. It has five 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.

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
in energy security. In March 2013, the State Electricity Regulatory Commission (SERC) merged into the
National Energy Administration (NEA) under the administration of the National Development and Reform
Commission (NDRC). The NEA is currently composed of 12 departments and has an authorised staffing
complement of 240 civil servants. It is responsible for developing and implementing energy industry
planning, and industrial policies and standards. In addition, it is in charge of administering the energy sector,
which includes coal, oil, natural gas, other forms of power such as nuclear energy, and new and renewablesources of energy. The NEA has also assumed responsibility for the Office of the National Energy
Committee. 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 in order toprovide 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.
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LAW

The laws relating to energy in China include the Coal Law (issued in 1996 and revised in 2013), the Electricity
Law (issued in 1995 and revised in 2015), the Renewable Energy Law (issued in 2005 and revised in 2009),
the Energy Conservation Law (issued in 1997 and revised in 2007) and the Environmental Protection Law(issued in 1989 and revised in 2014). A comprehensive legal basis for the energy sector, the Energy Law, iscurrently under consideration. The Standing Committee of the National People’s Congress endorsed theamended version of the Renewable Energy Law on 26 December 2009. It came into effect on 1 April 2010.
It more clearly defines the responsibilities of the power grid and power generation enterprises. It alsoemphasises the completely secure purchase of power from renewable energy sources and the establishmentof 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, came 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 patrolsof 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 came into effect on 1 March 2011. This regulation clarified the responsibilities and duties of gas
operators, unified gas market management into a regular channel and set the basis for local governments’
activities.
ENERGY SECURITY

On 13 June 2014, the Chinese leader Xi Jinping presided over the sixth meeting of the Leading Group forCentral Financial Work, stressing that energy security is a global and strategic issue that is related to national
economic and social development. In order to secure national energy security, Xi Jinping proposed thepromotion of a revolution in energy production and consumption. This revolution is a long-term strategy
with five major requirements as follows.


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 anenergy-saving priority principle, energy saving throughout the whole process of economic andsocial development and the adjustment of the industrial structure, significant emphasis on urban
energy-saving, the establishment of the concept of thrifty consumption, and the acceleration of theformation of an energy-saving society.



The promotion of an energy revolution and the establishment of a multi-supply system. These arebased 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. These are based on
China's national conditions and follow the new trend of the international energy technology
revolution. The goals are to be guided by the principle of green, low carbon energy; promotetechnological, industrial and business model innovation; promote high-tech fields vigorously; andcultivate technology and related industries in order 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 has effective
competition, ensuring that the formation of the market structure and system is mainly determinedby the market mechanism of energy price, transforming government energy regulation, andestablishing and improving the energy law system.

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

CHINA

All-round strengthening of international cooperation in order to achieve energy security inaccordance with the foregoing requirements. On the precondition that the energy production ismainly domestic, to strengthen international cooperation in all aspects of the energy production
and consumption revolution and make effective use of international resources.
ENERGY MARKET

Because energy market reform is a driving force behind the acceleration of China’s steps towards a market
economy, 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 those prohibited by laws and regulations. In 2010, the State Council issued
Several Opinions of the State Council on Encouraging and Guiding the Healthy Development of Private Investment. These
encourage private capital to participate in the exploration and development of energy resources, oil and gas
pipeline network construction, power plant construction, coal processing, energy conversion, the refining
industry and a comprehensive, new renewable energy industry.
COAL MARKET

Owing to the abundant domestic reserves and lower cost, coal has always been the primary energy fuel in
China. However, because of the seriously deteriorating air quality in recent years, China is acting to reducecoal consumption in order 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 aims to develop acomprehensive 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 shareof coal 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 presents recommendations forcontrolling and reducing China’s coal use to below 3.8 billion tons and 3.4 billion tons by 2020 and 2030
respectively. In addition, the report recommends that the economy’s total energy consumption should be ator lower than 4.7 billion tons of standard coal equivalent by 2020, and the share of coal within primaryenergy consumption during this period should be reduced to less than 57%.
Further, in December 2015, the Chinese State Council pledged to upgrade coal-fired power plants inorder to cut pollutant discharge by 60% before 2020, thereby saving approximately 100 Mt of raw coal andreducing carbon dioxide emissions by 180 Mt annually. In addition, China aims to cut total coal consumption
to below 65% of total primary energy consumption by 2017 as part of an energy supply structuraltransformation (SCC, 2015).
OIL MARKETIn April 2015, China surpassed the United States as the world’s largest oil importer. 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 UnitedStates imports of 7.2 Mbbl/D. Larger shipments from Iran, Oman and Abu Dhabi partly contributed to thesoaring increase in oil imports in China.
Although China faces a challenge of slow economic growth, oil consumption is still increasing insteadof decreasing. Thus, China’s state-owned oil traders such as Unipec and China Oil have a much more visible
presence in the global crude oil market.
However, with China’s increasing dependence on overseas oil imports of more than 60%, it must
establish strategic oil reserves in order 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 prices in order to stockpile crude.
According to the Statistics Bureau, the reserves are stored in seven above-ground facilities at Zhoushan,
Zhenhai, Dalian, Huangdao, Dushanzi, Lanzhou and Tianjin, and one underground facility at Huangdao
with a total capacity of 29 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
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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 3.8% year-on-year to 66 bcm.
Securing the energy supply is one of China’s energy strategies. Thus, China has been striving toencourage the transportation of gas from west China and countries around China, such as Russia and theCentral Asian countries where there are significant resources, to east China where demand is at its strongest
and where an energy shortage is apparent.
China’s first West-East Gas Pipeline was built by the China National Petroleum Corporation (CNPC)
and completed on October 2004. At 2 722 miles, this is China’s longest natural gas pipeline, with one trunkline and three 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 capacityof 1.1 trillion cubic feet per year (Tcf/y) and a length of more than 5 480 miles, including the trunk line andeight main 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 firstWest-East Gas Pipeline to Zhongwei in north-central China. The eastern section transports natural gas from
Zhongwei to southern Guangdong province and Shanghai in the East.
In order to meet the rising gas demand in China, the CNPC began constructing the third West-East
Gas Pipeline with a capacity of 1.1 Tcf/y. The western section of the pipeline was launched in 2014. The
eastern section was in operation by the end of 2015. This pipeline runs parallel to the second West-East Gas
Pipeline for most of its length and ends in the south-eastern province of Fujian (EIA, 2015; Primeline, 2015).
Apart from the demand issues, 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 approximate average of 0.1
USD (or approximately 28%) per cubic metre. This reduction has been 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 forindustrial users, power generation companies, concentrated heating suppliers, taxi drivers, commercial
entities, service providers and others in the downstream.
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 ‘ceilingcity station gate prices’ (China, 2015).
ELECTRICITY MARKETIn the Thirteenth Five-Year Plan, the main objectives for electricity market development are to accelerate
structural reformation and innovation, transform to green energy and relax the regulations regarding
electricity supply. In order to reach these objectives, there are five major strategies (FE Group, 2015).


The innovation of the electricity market structure. In 2015, the Chinese government finalized the
Deepening Reform of the Power Sector, a policy document co-signed by the Central Committeeof the Communist Party and the State Council, in order to accelerate the innovation of the electricity
market structure. Further, an investment regime must be established by opening public bidding ina specific orderly manner, thereby developing innovation for the electricity market and its businessmodel.



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



The 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 withhydropower 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 in order tosecure a stable and economic supply of electricity in the long term.

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

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CHINA

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

Further, on 30 November 2015, China announced reforms of its electricity sector in order to improve
competition in the marketplace. These reforms will end the monopoly of electricity distribution by stateowned enterprises (SOEs). The government will expand pilot programs that are related to the cost ofbuilding transmission lines, thereby allowing electricity consumers to negotiate directly with electricity
generators (OilPrice, 2015).
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, 2015).
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, provincial-level
NDRCs launched implementation plans. Meanwhile, the central government has made plans todevelop large-scale power plants and combine heat and power stations in order 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 region.
Instead, large-scale coal power plants in central and western China will play a more significant rolein power production and transmission.

Establish a market-oriented energy pricing mechanism. Energy inefficiency in China is mainly
caused by governmental control of energy pricing and the monopolies of SOEs. In order toencourage competition and weaken the power of SOEs, the Chinese Government will invite moreprivate companies into the sector 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 in order to attract private investment
to national infrastructure projects. These projects include hydropower, wind power, photovoltaic (PV)power, oil and gas pipelines, energy storage facilities, the modern coal chemical industry and thepetrochemical industry. The State Council said that these projects would be put out to public tender in order
to attract private capital through joint venture, sole proprietorship or franchise arrangements. With regard
to the next step, the government will release more projects from other sectors. These will include oil andgas exploration and water conservancy.
Carbon-trading schemes are also being used by central government to promote market-based energypricing structures. In February 2014, the NDRC decided to promote a carbon-trading system further byintroducing it across the economy. As of 12 July 2015, Hebei was the sixth city in China to open a carbon
emissions trading market after Shenzhen, Shanghai, Beijing, Guangdong and Tianjin.
RENEWABLE ENERGY

China is the world’s leading producer of renewable energy. It is also the largest investor in clean energy witha record USD 89.5 billion invested in renewable energy in 2014. This figure is 32% higher than the USD
60.8 billion invested in 2013. Consequently, renewable electricity generation investment in China exceeded
investment in fossil fuel and nuclear energy.
In 2013, China had a total of 399 GW of renewable energy capacity (including hydro). This is morethan double the capacity of renewable energy in the United States. 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 ofrenewable energy, an amount which is equal to the size of the entire current US electricity grid.
WINDWind offers one of the greatest opportunities for renewable energy growth in China. During 2007–14,
China’s wind energy increased nearly twentyfold, growing from 5.9 GW to 116 GW, and is expected tocontinue to grow. Since 2010, China has been the largest wind power producer in the world. In 2013, theelectricity generation output of wind reached 141 TWh, making it the third most popular energy source inthe economy after coal (4 111 TWh) and hydro (910 TWh) (EGEDA, 2015).

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However, the wind power industry faces the challenge of abandoning wind power because of thelimitations of wind farms and grid capacity. The abandonment of wind power has occurred in China since2010 and reached a peak in 2012 with a total of 21 billion kWh of wind power electricity. This accounted
for 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 abandonment rate fell to 11% and decreased
further to 8.5% in 2014. However, in the first half of 2015, the abandonment rate rose to 15% (NEA, 2015).
SOLAR

The solar PV industry in China has long depended on subsidies and is expected to experience a crucial
period of 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 in order 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, 43 GW,
in the world (PV Magazine, 2016). Indeed, China has been the world’s largest market for solar PV since2013, when it had 17.5 GW.
In December 2015, the NEA issued the draft of a suggestion for solar energy in the Thirteenth FiveYear Plan, setting a target for solar PV capacity to reach 150 GW by 2020. The basis of this target is thatthe economy will continue to expand solar PV generation in the next five years.
In addition, the NDRC is currently soliciting opinions on reducing the benchmark on-grid price ofelectricity generated by wind and solar PV power. The opinions requested are those of local governments
and power companies. The intention is that a lower price will help the industry to expand (Xinhua FinanceAgency, 2015).
HYDRO

Hydropower is a big 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 2013 was 281
GW, making it by far the economy’s single largest renewable power source. Although China has set a goal
to increase capacity to 350 GW over the next five years, the potential for new large and small hydro capacities
is not infinite. Thus, the proportion of hydropower in China’s renewable energy mix is likely to decrease in
the near future. (EGEDA, 2015)
NUCLEAR ENERGY

Because China is striving to reduce air pollution from coal-fired power plants, it is aiming to construct more
nuclear power plants. Currently, 30 nuclear power reactors are in operation with 24 under construction andmore to be constructed. In 2015, the electricity generation output of nuclear was 169 TWh, which wasapproximately 3% of total power generation. The installed capacity was 26 GW, which was approximately
1.75% of total capacity. 2015 also saw the beginning of the greatest number of nuclear power projects in asingle year in China since the 2011 crisis, with eight new units being approved for construction.
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 prioritise safety and quality in Chinese regulations and set a target of 58 GW
nuclear capacity by 2020 (WNA, 2015). The Chinese Government has said that it will approve a small
number of plants along the coast in accordance with new stricter safety rules, and no plants were approved
for inland areas during the period of 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).
China now pays significant attention to 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.
Fourth-generation reactors (such as 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 for commercial construction in approximately 2030. Then, the fourth-generation reactors
will gradually replace the current PWRs. By 2040, new technology will play an important role in China’s
energy supply (World Nuclear, 2016).

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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 agreed with the United States in November
2014. It also pledged to reach a total emissions peak by approximately 2030 and to 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 areto reduce carbon intensity by 60% to 65% of the 2005 level and to restore approximately 4.5 bcm of forested
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 US and China also came to a joint bilateral agreement
to work through existing Montreal Protocol and UNFCCC mechanisms in order to reduce the use ofhydrofluorocarbons (HFCs), which are potent greenhouse gases emitted through a variety of industrial
processes.
N OTA B L E E N E RG Y D E V E L O P M E N T S
STRUCTURAL CHANGE AND GREEN LEAP FORWARD

To reduce greenhouse gas (GHG) emissions and address air quality impacts, China needs to move its energy
structure from fossil 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 five-year 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 inelectricity 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 74% and 34%
respectively in 2015, while coal consumption dropped by 3.7%. China broke two new records in 2015,
installing a record 32.5 GW of wind and a record 18.3 GW of solar, both of which were higher than initial
estimates.
NUCLEAR POWER RENAISSANCE

Nuclear power has been recognised as a key part of China’s plan to reshape its energy mix away from coal,
to clean up its skies and to limit carbon emissions. At the beginning of 2015, the State Council approved
construction of its first nuclear power project, the Hongyanhe Nuclear Plants located in the north-west of
China, since the Fukushima disaster almost four years ago. The State Council then approved the firstindigenous nuclear plant and two Hualong-one units to be built in southern Fujian province. In December
2015, the State Council gave its approval for the construction of two more nuclear units at each of the
Tianwan and Fangchenggang nuclear power plant sites. At present, China’s nuclear reactors underconstruction account for almost 40% of the world’s total.
NEW ENERGY VEHICLESA proposal in the Thirteenth Five-Year Plan, issued on 3 November 2015, states that the Chinese
Government will implement a neighbourhood electric vehicle (NEV) popularisation program. It will also
upgrade the industrialisation level for electric car manufacturing in order 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 which will produce three million NEV units each year.
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 accounting for 10% of total sales; andAutomobile industry advances through NEV development while foreign automobile makers
remain inactive in promoting NEV.
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REFERENCES

BP (British Petroleum) (2015), BP Statistical Review of World Energy June 2015,
www.bp.com/content/dam/bp/pdf/energy-economics/statistical-review-2015/bp-statisticalreview-of-world-energy-2015-full-report.pdf
China (2015), China Boosts Pricing Reforms in Natural Gas Sector, www.china.org.cn/business/201511/21/content_37123349.htm.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
EIA (U.S. Energy Information Administration) (2015), China,
https://www.eia.gov/beta/international/analysis.cfm?iso=CHN.
FE Group (Far East Holding Group Co., LTD.) (2015), 十三五电力规划：加快体制改革和绿色转型,
www.fegroup.com.cn/index.php?m=view&a=index&aid=5984.
FT (Financial Times) (2015), ‘China Oil Imports Surpass Those of US’, May 10, 2015,
www.ft.com/intl/cms/s/0/342b3a2e-f5a7-11e4-bc6d-00144feab7de.html#axzz3xn6Bpmbr.
MEP (Ministry of Environmental Protection) (2012), 2011 Report on the State of the Environment in China,
http://english.mep.gov.cn/standards_reports/soe/soe2011/.
NBS (National Bureau of Statistics) (2015), http://www.stats.gov.cn.
NEA (National Energy Administration) (2015), ‘Grid-connected Wind Power Data in the First Half of 2015’,
http://www.nea.gov.cn/2015-07/27/c_134451678.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.
OECD-NEA (Organisation for Economic Co-operation and Development, Nuclear Energy Agency)(2014), Uranium 2014: Resources, Production and Demand, https://www.oecdnea.org/ndd/pubs/2014/7209-uranium-2014.pdf.
OilPrice (2015), China Reshapes Energy Sector, Shifts Towards Market Economy,
http://oilprice.com/Energy/Energy-General/China-Reshapes-Energy-Sector-Shifts-TowardsMarket-Economy.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).
–– (2015), New Standard to Reduce Pollutant Emissions,
http://english.gov.cn/premier/news/2015/12/02/content_281475246642991.htm.
USCBC (US-China Business Council) (2015), Three Reform Strategies Behind Xi’s Energy Revolution,
https://www.uschina.org/three-reform-strategies-behind-xi%E2%80%99s-energy-revolution.
World Nuclear (2016), Nuclear Power in China, www.world-nuclear.org/info/country-profiles/countries-af/china--nuclear-power/.
WTO (World Trade Organization) (2015), International Trade Statistics 2015,
https://www.wto.org/english/res_e/statis_e/its2015_e/its2015_e.pdf.
X. Qiu and H. Li (2012), ‘Energy Regulation and Legislation in China’, Environmental Law Reporter, Vol. 42,
September 2012.
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 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

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H ON G K ON G , C H I N A

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 of some 7.2 million people located at the south-eastern tip of China.
Hong Kong, China has no natural resources and thus all of its energy demand is imported. The energy sector
consists of investor-owned electricity and gas utility services.
In 2013, the per capita gross domestic product (GDP) of Hong Kong, China was 50 611 (2010 USD
purchasing power parity [PPP]), among the highest of the APEC economies, and GDP increased 9.9% in
real terms after 2010 to 364 billion (2010 USD PPP). The services sector remained the dominant driving
force of overall economic growth, accounting for 90% of GDP in 2013 (EGEDA, 2015). 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 ofthe challenges posed by globalisation, but also due to its closer integration with mainland China. The
Mainland and Hong Kong Closer Economic Partnership Arrangement (CEPA) is a manifestation of theadvantages of ‘one country, two systems’. As part of the liberalisation of trade in goods under CEPA, allproducts 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
an international centre for financial services, trade and shipping, as well as an advanced global manufacturingand modern services base. The central government has announced that it will actively liaise with Guangdong
to identify favourable treatment and implement opportunities for Hong Kong’s people and enterprises in
the planning and development of Nansha, Qianhai and Hengqui. It will also increase the number of
Economic and Trade Offices in Asia to help business and investors tap Asian markets. Moreover, thegovernment has invited the submission of proposals to complement the National 13 th Five-Year Plan (Policy
Address, 2015).
Table 1: Key data and economic profile, 2013
Key data
Area (km2)

Energy reserves
1 104

Oil (million barrels)–

Population (million)

7.3

Gas (billion cubic metres)–

GDP (2010 USD billion PPP)

364

Coal (million tonnes)–

GDP (2010 USD PPP per capita)

50 611Uranium (kilotonnes of U)–

Source: EGEDA (2015).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

Hong Kong, China has no domestic energy reserves or petroleum refineries; it imports all of its primaryenergy 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 tonnesof oil equivalent (Mtoe) in 2013, 0.3 Mtoe higher than 2012. Coal maintained the highest share of the total
primary energy supply (55%), followed by oil (23%), gas (16%) and other sources (6%) (EGEDA, 2015).
In 2014, the total installed electricity generating capacity in Hong Kong, China was 12 645 megawatts(MW) (EGEDA, 2015). All locally generated power is thermal fired. Electricity is supplied by CLP Power
Hong Kong Limited (CLP Power) and The Hong Kong Electric Company, Limited (HKE). CLP Powersupplies electricity from its Black Point (2 500 MW), Castle Peak (4 108 MW) and Penny’s Bay (300 MW)
power stations. Natural gas and coal are the main fuels used for electricity generation at the Black Point andCastle Peak power stations. CLP Power has arrangements with China National Offshore Oil Corporation
and PetroChina International Company to procure gas supplies from the Mainland. HKE’s electricity is63

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supplied 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 liquefied naturalgas (LNG) terminal in Guangdong, mainland China. HKE has also operated wind turbines (capacity
800 kilowatts [kW]) since 2006, and a photovoltaic (PV) system (1 MW) since 2010 (CLP, 2015; 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 manufactured locally using
naphtha and natural gas as feedstock, is being distributed by The Hong Kong and China Gas Company
Limited (Towngas, 2013).
FINAL ENERGY CONSUMPTION

In 2013, the total final energy consumption in Hong Kong, China was 6 746 kilotonnes of oil equivalent(ktoe), a decrease of 1.3% from the previous year. The residential and commercial sectors accounted for thelargest share of energy used (63%), followed by the transport sector (31%) and the industry sector (5.2%).
By energy source, electricity and ‘others’ made up 55% of end-use consumption, followed by petroleum
products (35%) (EGEDA, 2015).
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 generationand town gas production.
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

64 Industry sector

348 Total power generationa

Net imports and others

28 640 Transport sector

2 121

Thermal

Total primary energy supply

14 118 Other sectors

4 276

Hydro

1

Coal

7 769 Non-energy0

Nuclear–Oil

3 189 Total final energy consumption

6 746

Others

41

Gas

2 307

Coal

–

Others

853

Oil

2 366

Gas

682

Electricity and others

39 10339 061

3 698

Note: ‘Total’ does not include electricity generated by hydro and nuclear energy facilities located in the mainland.
Source: EGEDA (2015).
ENERGY INTENSITY ANALYSISIn terms of primary energy or final energy demand, the energy intensity of Hong Kong, China is the lowest
among APEC economies. The primary energy intensity in 2013 was only 38.8 tonnes of oil equivalent per
million USD (toe/million USD) compared with the median value of 168 toe/million USD for APEC
economies, while the final energy demand was only 18.5 toe/million USD compared with the median valueof 111 toe/million USD (EGEDA, 2015).
Hong Kong, China endeavours to develop sustainably and fully supports APEC’s Honolulu
Declaration in 2011, seeking to reduce 45% of energy intensity by 2035. To step up energy efficiency andconservation, various policies are implemented, such as the Mandatory Energy Efficiency Labelling Scheme,
Energy Efficiency Registration Scheme for Buildings, Building Energy Efficiency Ordinance as well as the
Scheme on Fresh Water Cooling Towers (GHK, 2015a).

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Table 3: Energy intensity analysis, 2013
EnergyEnergy Intensity (toe/million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

39.2

38.8

0.9

Total final energy consumption

19.4

18.5

4.3

Industry

1.0

0.96

3.9

Transportation

6.2

5.8

5.4

Others

12.2

11.8

3.8

–

–

–

Non-energy
Source: EGEDA (2015).

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 the energy needs ofthe community are met safely, efficiently and at reasonable prices, while minimising the environmental
impact of electricity generation. The government also promotes efficient use and conservation of energy. In
combating climate change, reducing greenhouse gas (GHG) emissions and developing a low-carbon
economy, Hong Kong, China’s emissions reduction strategy emphases the wider use of cleaner and lowcarbon 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 theenvironment. The government works with the oil companies to maintain strategic reserves of gas, oil andnaphtha. It monitors the performances of the power companies through the Scheme of Control Agreements(SCAs) (the present SCAs were signed in 2008) to encourage energy efficiency, quality services andrenewable energy (RE) use.
Specifically, Hong Kong, China proposes to optimise the fuel mix for power generation. The
government conducted a public consultation on the future fuel mix for electricity generation in Hong Kongin 2014 to solicit the public’s views on the subject. Two fuel mix options were put forward for public
consultation. They are, firstly, to import more electricity through purchase from the Mainland power grid,and, secondly, to use more natural gas for local generation. Having considered the public’s views, thegovernment plans to increase the percentage of natural gas generation to around 50% by 2020, and maintainthe current interim measure of importing 80% of nuclear output from the Daya Bay Nuclear Power Station,
so that nuclear import would account for around 25% of the total fuel mix. Subject to public views on thetariff implications, the government 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 achieve theenvironmental 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 basedon the 2005 level. The actions are:

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
the statutory requirements under the Buildings Energy Efficiency Ordinance, the Building (Energy
Efficiency) Regulation, and the Energy Efficiency (Labelling of Products) Ordinance;Updating schools and public education programmes and strengthen Government energy saving
efforts by appointing Green Managers and Energy Wardens, and encourage public sector
institutions to save energy; and65

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

H ON G K ON G , C H I N A

Supporting community campaigns through government funding schemes, and collaborate 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 built environment leaders
to accelerate green building adoption in the private sector.
ENERGY 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 theprosperity and stability of Hong Kong, the Central Government of China will continue to support energy
co-operation between the mainland and Hong Kong, China over the long term, which will include efforts
to provide a stable supply of nuclear electricity and natural gas to Hong Kong. The inter-governmental
MOU contemplates the delivery 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 on-going supply of nuclear-generated electricity to Hong Kong,
China. An extension of the Guangdong Daya Bay Nuclear Power Station joint venture and supply contracts
was approved 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 a further term of 20 years
from 2014, and CLP 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 about 80% from late 2014 to 2018 (CLP, 2014a, 2014b).
ENERGY EFFICIENCY

Buildings consume about 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 made to improve publicawareness of 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 demand situation, including the energy consumption
patterns, trends and usage characteristics of each sector and segment. A basic data set is publicly available
on the internet. The government is able to analyse the current system based on the data and develop policy
and strategy revisions for future implementation, while the private sector can use the data to benchmark
their own energy efficiency while seeking improvements in their energy consumption systems (EMSD,
2015a).
BUILDINGS

To strengthen its efforts toward 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 thatthe four key types of building services installations (air conditioning, lighting, electrical, and lift andescalator installation) comply with the design standards of the Building Energy Code (BEC);When carrying out ‘major retrofitting works’, responsible persons of prescribed buildings (i.e.
owners, tenants or occupants, etc.) should ensure that the four key types of building services
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 services installations inaccordance with the Energy Audit Code (EAC) every 10 years. The first energy audit should be
carried out within four years of the commencement of the Ordinance in accordance with thetimetable set out in Schedule 5 to that Ordinance.

The BEC is reviewed once every three years to meet public aspiration, the international trend and thelatest technology development. The first comprehensive review completed in 2015 and the new standards
require a further 10% improvement in energy efficiency. It is estimated that up to 2025, energy savings from66

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all new buildings in Hong Kong will be about 5 billion kilowatt-hours of electricity, equivalent to a reduction
in carbon dioxide (CO2) emissions of about 3.5 million tonnes (Mt).
The government continues to utilise government buildings to demonstrate state-of-the-art energyefficient designs and building 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 metresshould aim to obtain not lower than the second-highest grade under the Hong Kong Building
Environmental Assessment Method (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% saving in the electricity
consumption of government buildings in the next five years from 2015-16 to 2019-20 under comparable
operating conditions, using the electricity consumption in 2013-14 as the baseline. In April 2009, thegovernment introduced Buildings Energy Efficiency Funding Schemes worth HKD 450 million in total tosubsidise environmental performance reviews and upgrades for communal areas in residential, commercial
and industrial buildings. The Schemes also cover energy/carbon audits and upgradation of the energy
efficiency performance of building services installations. The subsidy can cover up to 50% of theexpenditure. 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 include
the WACS using fresh water cooling towers for individual buildings, WACS using seawater cooling forindividual buildings and the large-scale District Cooling System for numerous buildings (EMSD, 2015b).
The government implements a District Cooling System (DCS) at the Kai Tak Development to supply
chilled water for centralised air conditioning to buildings in the new development. The DCS is the firstproject of its kind implemented by the government. It is an energy-efficient air conditioning system as it
consumes 35% and 20% less electricity as compared with traditional air-cooled air conditioning systems andindividual WACS using fresh water cooling towers, respectively. The project would be implemented in threephases: Phase I and II were completed in 2013 and 2014 respectively and the construction of Phase III
commenced in 2013 and is expected to be completed by 2022 (EMSD, 2015c).
ENERGY CONSUMPTION INDICATORSIn 2011, the government reviewed and updated 68 groups of energy consumption indicators covering theresidential (6 groups), commercial (32 groups) and transport (30 groups) sectors. The energy consumption
indicators and benchmarks assist the energy-consuming groups to understand their energy consumption
levels and performance with respect to their corresponding peers. They help foster the concept of efficientenergy consumption and promote general awareness (EMSD, 2014).
ENERGY EFFICIENCY LABELLING

Hong Kong, China has a voluntary Energy Efficiency Labelling Scheme that covers 22 types of household
and office appliances, including 13 types of electrical appliances (refrigerators, washing machines, nonintegrated type compact fluorescent lamps (CFLs), dehumidifiers, electric clothes dryers, room coolers,
electric storage water heaters, televisions, electric rice cookers, electronic ballasts, light-emitting diode (LED)lamps, induction cookers and microwave ovens), 7 types of office equipment (photocopiers, fax machines,
multifunction devices, printers, laser crystal display (LCD) monitors, computers and hot/cold bottled water
dispensers) and 2 types of gas appliances (domestic instantaneous gas water heaters and gas cookers). The
scheme was extended to cover passenger cars running on petrol (EMSD, 2015d).
To further assist the public in choosing energy-efficient appliances and to raise public awareness ofenergy 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 typesof products, namely room air conditioners, refrigerating appliances, CFLs, washing machines anddehumidifiers. Under the MEELS, energy labels must be displayed on the products being supplied to Hong
Kong, China to inform consumers of their energy efficiency performance (EMSD, 2012b).

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H ON G K ON G , C H I N A
TRANSPORTLand transport accounts for about 17% of the total GHG emissions in the economy and is the second mostsignificant contributor of emissions. In order to reduce carbon emissions from the transport sector, Hong
Kong, China, has undertaken the following efforts.
EXTENSION OF THE PUBLIC TRANSPORT SYSTEM

An extensive and energy-efficient public transport system in Hong Kong, China is instrumental in helping
to maintain low levels of GHG emissions. Some 90% of commuter trips each day are made 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 wider use of electric vehicles. The FRT for electric vehicles has been
waived until the end of March 2017. The government liaised with the EV manufacturers and dealers toencourage them to introduce EVs into Hong Kong; as a result, Hong Kong is one of the leading APEC
economies in EV use. The government has been working with the private sector to expand the charging
infrastructure for EVs in Hong Kong. There are about 1300 different types of public EV chargers, including
over 200 medium chargers and 157 quick chargers.
The government’s ultimate policy objective is to have zero emission buses running across 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. If the trial results are
satisfactory, the government will encourage the franchised bus companies to use these green buses on alarger scale, taking into account 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
more transport means and technologies, and the transport sector to carry out trials with subsidies from theFund. At the end of February 2016, 87 trials have been approved under the Fund, including 67 electriccommercial vehicles (taxis, light buses, buses and goods vehicles), 63 hybrid commercial vehicles (goods
vehicles and light buses), 1 solar air-conditioning system, 4 electric inverter air-conditioning systems, andretrofitting a ferry with a diesel-electric propulsion system and a seawater scrubber.
PROMOTION OF BIODIESEL AS A MOTOR VEHICLE FUEL

In order to facilitate the use of biodiesel in motor vehicles, the government has adopted a duty-free policy
for biodiesel since 2007. In 2010, it introduced regulatory control 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 about 200 kW on Town Island in late 2012. The system now consistsof 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) 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 at a capital cost of
about HKD 3 billion and a total generation capacity of around 100 MW, producing 175 gigawatt-hours(GWh) of electricity and offsetting 150 000 tons of CO2 emissions annually after completion. In 2012, HKE
commenced a wind monitoring station at its offshore wind farm site to collect meteorological andoceanographic data for detailed design purposes (HKEI, 2015d).
In 2007, a landfill gas processing plant at the North East New Territories Landfill started operation,with a peak supply of 8 000 square metres per hour of synthetic natural gas (SNG) from landfill gas. As a68

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H ON G K ON G , C H I N A

result, the consumption of naphtha at the town gas production plant in Tai Po was reduced by approximately
40 000 tonnes, in turn reducing CO2 emissions up to about 135 000 tonnes annually (Towngas, 2013).
The government has taken the lead in using RE by installing a 350 kW PV system on the roof of theElectrical and Mechanical Services Department headquarters. The installation of an 850 kW PV system has
been planned by the Drainage Services Department at Siu Ho Wan Sewage Treatment Works and isscheduled for completion in mid-2016. The government also installed large-scale solar water heating devices
on government buildings, including those with swimming pools, to save power in heating water.
In its effort to convert waste to energy and to reduce GHG emissions, the government is planning toconstruct an integrated waste management facility, two organic waste treatment facilities and a sludge
treatment facility, expecting them to meet about 1% of the total electricity demand by 2020. Phase 1 of the
Sludge Treatment Facility has been operating since 1 April 2015.
NUCLEAR ENERGY

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 to help
meet the long-term demand for electricity in its supply area. This arrangement meets some 22% of theelectricity 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 for another 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 ensure that more clean and cost-competitive energy is provided to Hong Kong, an agreement
has been reached, whereby Daya Bay will increase its electricity supply to Hong Kong from 70% of its
output to approximately 80% for late 2014–18 (CLP, 2014a, 2014b).
CLIMATE CHANGE

Hong Kong, China is committed to working closely with the international community to combat climatechange. The government is pursuing measures set out in the Hong Kong’s Climate Change Strategy andAction Agenda (EPD, 2010) to reduce the territory’s carbon intensity by 50% to 60% by 2020, with reference
to the 2005 level. The government also published in November the Hong Kong Climate Change Report
2015, which outlines the work and joint efforts of the government and the key private-sector stakeholders
in responding to climate change. It also provides an account of Hong Kong's climate change actions so thatthe public can have a more complete picture of Hong Kong's contributions to concerted global action.
The major contributors of GHGs in Hong Kong, China are the power generation and land transport
sectors, accounting for about two-thirds and one-fifth of the territory’s GHG emissions, respectively. In
addition, energy consumption in buildings contributes about 90% of 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 emissions reduction measures can be classified as follows.
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. The government promulgated in 2015 the fuel mix for 2020, which is to increase the proportionof natural gas for power generation from around 20% in 2014 to around 50% in 2020 with a view to reducing
the territory’s carbon intensity by 50 to 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 demand of air
conditioning and other major electrical equipment. Specific measures include:

Expanding the scope and tightening the requirements of the Building Energy Codes, so that by2020 major electrical equipment in all new commercial buildings will be up to 50% more energy
efficient compared with buildings in 2005;

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

Reducing energy demand in new buildings by various means, such as tightening overall thermaltransfer value standards and promoting the wider adoption of green roofing, so that by 2020 all
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H ON G K ON G , C H I N A

new commercial buildings will reduce their energy demand by up to 50% compared with newbuildings in 2005;


Improving energy efficiency in commercial buildings through good housekeeping, information
technology products and intelligent building environmental management systems, so that by 2020
up to 25% of existing commercial buildings will be 15% more energy efficient compared with 2005;
and

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

GREENING ROAD TRANSPORT

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

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

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

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



Allowing enterprises to have 100% profits tax deduction for the capital expenditure in the first yearof EV procurement;Implementing importers’ average fleet efficiency standards, so that new vehicles will be 20% moreenergy 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:

Developing and fully operating one integrated waste management facility, two organic waste
treatment facilities and one sludge treatment facility; andFully utilising recovered landfill gas and gas generated from wastewater treatment.

LONG-TERM CLIMATE STRATEGYWith the positive outcome of the 21st session of the Conference of the Parties to the United Nations
Framework Convention on Climate Change (UNFCCC), the HKSAR Government recognised the need tostep up climate actions and to 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
is composed of members from 10 policy bureaux and 3 departments. It seeks to, among others, steer theoverall direction of the HKSAR Government in combating climate change, including the setting of post2020 carbon reduction target as well as our long-term climate strategies, having regard to the UNFCCC andthe 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 will expire in 2018. Hong Kong
needs to consider how to further develop its electricity market, regarding to its four energy policy objectivesof safety, reliability, affordability and environmental protection, as well as its goal to introduce competition
when the requisite market conditions are present. The government therefore launched a three-month-longpublic consultation on 31 March 2015 to solicit the public’s views on the future development of theelectricity market. The consultation document put forward questions on various major issues regarding(ENB, 2015b) the following.
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H ON G K ON G , C H I N AIntroduction of competition: The public held different views on the subject of introducing
competition. The majority of the respondents considered that the current power supply in Hong
Kong 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 the regulatory arrangement, while almost all respondents considered that the current
contractual arrangement by SCAs had worked well by and large and allowed the economy to achieve
the energy policy objectives. It was generally agreed that improvements should be made to thecurrent SCAs in respect such areas as the level of permitted rate of return, mechanism to promoteenergy saving and RE etc.

Development of RE: The community’s views on the development of RE were generally positive.
Around half the respondents supported 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 connection to the power grids.
REFERENCES

CLP (CLP Power Hong Kong Limited) (2014a), Annual Report 2014,www.clpgroup.com/en/Investors-Informationsite/Documents/Financial%20Report%20PDF/e_Annual%20Report%202014%20(full%20version).pdf.
–– (2014b), Sustainability Report 2014, www.clpgroup.com/en/Sustainabilitysite/Report%20Archive%20%20Year%20Document/SR_Full_2014_en.pdf.
–––(2015), Infrastructure & Fuel Mix, www.clp.com.hk/en/about-clp/power-generation/infrastructure-andfuel-mix.
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,www.energylabel.emsd.gov.hk/en/mainpage.html.
–– (2014), Energy Consumption Indicators and Benchmarking Tools,
www.emsd.gov.hk/emsd/eng/pee/ecib.shtml/.
–– (2015a), Hong Kong Energy End-use Data,
www.emsd.gov.hk/emsd/eng/pee/edata_1.shtml.
–– (2015b), Water-cooled Air Conditioning System,
www.emsd.gov.hk/en/energy_efficiency/water_cooled_air_conditioning_system/index.html.
–– (2015c), Voluntary Energy Efficiency Labelling Scheme,www.emsd.gov.hk/en/energy_efficiency/voluntary_energy_efficiency_labelling_scheme/index.html.
–– (2015d), District Cooling System at Kai Tak Development,www.emsd.gov.hk/en/energy_efficiency/district_cooling_system_at_kai_tak_development/index.ht
ml.
ENB (Environment Bureau, Government of the Hong Kong Special Administrative Region of thePeople’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_devel
opment_electricity_market.html.
EPD (Environment Protection Department, Government of the Hong Kong Special Administrative
Region of the People’s Republic of China) (2010), Hong Kong’s Climate Change Strategy and Action
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APEC E N E RG Y O VE R VI E W 2015

H ON G K ON G , C H I N AAgenda Consultation Paper,
www.epd.gov.hk/epd/english/climate_change/files/Climate_Change_Booklet_E.pdf.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/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, www.hkelectric.com/en/our-operations/lamma-wind-powerstation.
–– (2015c), Solar Power Station, www.hkelectric.com/en/our-operations/solar-power-system.
–– (2015d), Offshore Wind Farm, www.hkelectric.com/OffshoreWindFarm/introduction.
Policy Address (2015), www.policyaddress.gov.hk/2015/eng/.
Towngas (Hong Kong and China Gas Company Ltd) (2013), Overview,www.hkcg.com/eng/corp/abttg/newenergybus/eco.aspx/.
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/en72

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I N D ON E S I A

INDONESIAI N T ROD U C T I ON

Indonesia is a large archipelago located south-east of mainland South-East Asia, between the Pacific Ocean
and the Indian Ocean. Indonesia’s territory encompasses 17 508 large and small islands and large bodies ofwater at the equator over an area of 7.9 million square kilometres (km 2). This constitutes Indonesia’s
exclusive economic zone. Indonesia’s total land area (25% of its territory) is about 1.9 million square
kilometres. The population was 251.3 million in 2013.
Indonesia had a gross domestic product (GDP) of around USD 2 381.8 billion and a per capita GDP
of USD 9 479 in 2013 (2010 USD purchasing power parity [PPP]). Excluding the oil and gas sector,
manufacturing industries accounted for the largest component of GDP in 2013 (21%), followed byagriculture, forestry and fishing with a combined share of about 13.4%. In terms of exports, the main export
products of the economy are mineral fuels, lubricants and related products, which together account for
about 31% of total export value, followed by machinery and transport equipment at 12%. In 2013, Indonesia
attained economic growth of 5.6%, a decrease of 0.4% from 2012 (BPS, 2015)
Domestic oil, gas and coal reserves have played an important role in Indonesia’s economy as sourcesof energy, industrial raw materials and foreign exchange. In 2013, oil and gas exports contributed 14% andcoal exports contributed 14% of Indonesia’s total exports. Overall, tax and non-tax revenue from oil, gas
and minerals including coal accounted for 31% of the Indonesian Government’s budget in 2013 (ESDM,
2014a).
Indonesia’s proven fossil energy reserves at the end of 2013 consisted of 7.6 billion barrels of oil, 4.3
trillion cubic metres of natural gas and 31 billion tonnes of coal.
Table 1: Key data and economic profile, 2013
Key dataa

Energy reservesb, c

Area (million km2)

1.9

Oil (billion barrels)

7.6

Population (million)

251.3

Gas (trillion cubic metres)

4.3

GDP (2010 USD billion PPP)

2 382

Coal (billion tonnes)

31

GDP (2010 USD PPP per capita)

9 479

Uranium (kilotonnes U)

6.3

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

In 2013, Indonesia’s total primary energy supply (TPES) was 191 920 kilotonnes of oil equivalent (ktoe) ofcommercial energy, consisting of oil (46%), coal (30%), natural gas (18%), other energy (mainly hydropowerand geothermal) (5.9%) and 44 834 ktoe of biomass. Indonesia is a net exporter of energy; overall energy
exports of crude oil, condensates, natural gas, liquefied natural gas (LNG), petroleum products and coal
totalled 224 060 ktoe in 2013. Total energy exports in 2013 slightly increased by 1.9% from2012 (4 340 ktoe), a decrease driven primarily by a decrease in the price of exported coal.
OIL
In 2013, Indonesia produced 47 752 ktoe of crude oil and condensates; of this, 17 945 ktoe (38%) was
exported, an increase of 1.8% compared to 2012. Because oil production has declined significantly over the
past decade (in 1997 Indonesia produced 72 474 ktoe of crude oil and condensates), the economy imported
18 091 ktoe of crude oil and 31 660 ktoe of petroleum products in 2013 in order to meet its domestic oil
requirements. This represents an increase of 23% from a total of 50 ktoe in 2012 (EGEDA, 2015).
Most crude oil is produce onshore from two of Indonesia’s largest oil fields: the Minas and Duri oil fields
in the province of Riau on the eastern coast of central Sumatra. Because these fields are considered mature,
the Duri oil field in particular has been subject to one of the world’s largest enhanced oil recovery efforts.

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I N D ON E S I ANATURAL GAS

Indonesia produced 66 955 ktoe of natural gas in 2013, a decrease of 3.6% from the 69 435 ktoe produced
in 2012 (EGEDA, 2015). Of total natural gas production, 51.6% was converted to LNG for export. The
economy produced 32 384 ktoe of LNG in 2013, an increase of 19.6% from 27 077 ktoe in 2012. In 2013,
Indonesia also exported 23 307 ktoe of natural gas (35% of its total natural gas production) through pipelines
to Singapore and Malaysia (ESDM, 2014b). Overall, 45.6% of Indonesia’s natural gas production is exported.
The balance is made available for domestic requirements.
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 and Papua, with smaller gas reserves offshore in Westand East Java. LNG exports from Tangguh, Papua began in 2009 with gas supplied from the onshore andoffshore Wiriagar and Berau gas blocks, which are estimated to have reserves of 14 trillion cubic feet (Tcf).
COAL

In 2013, Indonesia produced 264 059 ktoe of coal, an increase of 16.3% from 226 909 ktoe in 2012. Mostof Indonesia’s coal production in 2013 (193 301 ktoe, or 73%) was exported. Domestic demand (135 499
ktoe in 2013) originated from power generation (82%) and industrial uses (19%) (EGEDA, 2015).
About 57% of Indonesia’s total recoverable coal reserve is lignite, 27% is sub-bituminous coal, 14% isbituminous coal and less than 0.5% is anthracite. Most of Indonesia’s coal reserves are in South Sumatra
and East Kalimantan. Relatively small deposits of coal are in West Java and in Sulawesi. As a result, although
Indonesian coal’s heating value can range from 5 000 to 7 000 kilocalories per kilogram, it is generally
distinguished by its low ash and sulphur content (typically less than 1%).
ELECTRICITY

Indonesia had 50 898 megawatts (MW) of electricity generation capacity in 2013. This was held by the stateowned electricity company (PLN) and independent power producers (IPPs). In 2013, 216 terawatt-hours(TWh) of electricity were generated, of which 24% was supplied by IPPs and 1.5% was imported from
Malaysia. In 2013, several types of power plant produced electricity; namely, coal-steam power plants (52%),
gas power plants (combined gas-steam power plants, gas turbine power plants and gas engine power plants)(24%), renewable energy power plants (geothermal, hydro, biomass, solar and wind) (12%) and oil power
plants (diesel power plants and oil-powered thermal plants (12%) (DJK, 2015a).
FINAL ENERGY CONSUMPTION

Total final energy consumption was 140 029 ktoe in 2013, an increase of 6.3% from 131 763 ktoe in 2012.
The share of final energy consumption by sector in 2013 was 43.4% for industry, 35% for transport, 17%
for other sectors and 5.5% for non-energy use. Indonesia’s economy is highly dependent on oil: final energy
consumption of oil in 2013 was 81 149 ktoe (58% of the total final energy consumption) (EGEDA, 2015).
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (MW)Indigenous production

389 764 Industrial sector

60 705 Total power generation

216 146

Net imports and other–193 983 Transport sector

48 483

Thermal

189 567

Total primary energy supply

191 920 Other sectors

23 111Hydro

16 930Coal

57 479 Non-energy

7 730

Nuclear–Oil

88 612 Total final energy consumption 140 029

Others

9 649

Gas

34 571Coal

25 054

Others

11 259Oil

81 149Gas

17 697

Electricity and others

16 129Note: Indigenous production excludes biomass.
Source: EGEDA (2015).
ENERGY INTENSITY

In 2013, Indonesia’s primary energy intensity was 80.6 tonnes of oil equivalent per million USD (toe/million
USD), a slight decline of 0.5% from the level of the year before. This indicates Indonesia’s primary energy
intensity has improved in recent years; however, there remains scope for the economy to improve its energy
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efficiency. In terms of final energy consumption, energy intensity amounted to 59 toe/million USD, a slightincrease of 0.7% from 2012. This was mostly driven by increasing energy consumption in other sectors.
Table 3: Energy intensity analysis, 2013
EnergyEnergy intensity (toe/million USD)
2012

Change (%)

20132012 vs 2013

Total primary energy supply

81.0

80.6

–0.5

Total final energy consumption

58

59

0.7

Industry

26

25

–0.7

Transportation

19.8

20.4

2.90

Others

9.4

9.7

3.2

Non-energy

3.6

3.3

–9.2

Source: EGEDA (2015).
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). This law 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 government and regional governments in planning, policy and regulation;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 tomeet the economy’s needs, energy development priorities, 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 to:

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 late 2008.
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 isintended to create energy security and resilience through an energy management strategy from 2014 to 2050.
The RUEN implements the KEN. By law, the RUEN is drafted by the government, namely the
Ministry of Energy and Mineral Resources, in a process that involves related ministries and othergovernment 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.
In order to give 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 and consideration of public opinion and input.

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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 in order 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 is currently undergoing regulatory changes. The industry was reformed in2001 under the Oil and Gas Law (Law No. 21/2001). The regulatory bodies, known as BP MIGAS andBPH MIGAS, were created to address oil upstream and downstream activities respectively. Exploration andproduction activities were conducted based on 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 governmentis drafting a new Oil and Gas Law that will determine a new industry structure. Until this law can be enacted,
an Interim Working Unit for Upstream Oil and Gas Business Activities (SKSPMIGAS) has been establishedunder the Ministry of Energy and Mineral Resources (MEMR) to assume all BP Migas roles andresponsibilities. Further, on 14 January 2013, the government issued Presidential Regulation Number 9 Year2013 as the umbrella regulation for the establishment of the Working Unit for Upstream Oil and Gas
Business Activities (SKKMIGAS), the job of which is to manage the upstream oil and gas business inIndonesia.
BPH MIGAS has supervisory and regulatory functions in the downstream oil and gas sector. Its aim
is to ensure the availability and distribution of fuel throughout Indonesia and the promotion of gas utilisationin the domestic 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 mineral and coal mining.
In essence, the new Mining Law ended the concession of work areas by contracts of work (COW) andby work agreements for coal mining businesses known as Perjanjian Karya Perusahaan Pertambangan
Batubara (PKP2B). Concessions are now based on permits issued from central government and regional
governments.
Prior to the new law, the government arguably had less regulatory control over its concessions. For
example, any changes to concession terms needed to be agreed by both the government and the investor.
By instituting permits, the government expects to be better positioned to promote investment and regulate
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 regulationson: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;
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I N D ON E S I A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.
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
Electricity Law replaced Law No. 15/1985, which the Constitutional Court had reinstated in December
2004 as a provisional law 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 inconsequence had made it responsible for providing electricity to all parts of Indonesia.
Under the new Electricity Law, the electricity industry comprises electricity business entities, which are
title-holders of electricity supply business licences or Izin Usaha Penyediaan Tenaga Listrik (IUPTL). The
IUPTL integrate 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 beestablished, where necessary) and private sector power systems, each operating within their respective
business areas. Licence holders of specific electricity supply types (such as the IPPs, which are licence holders
in power generation for the supply of electricity to the public) participate in the vertically integrated systems.
By law, the government and regional governments regulate the electricity industry within theirrespective jurisdictions 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 Electricity
Law, Indonesia had a uniform electricity tariff regime and applied cross-subsidies among regions. At thetime of writing, there was no ruling as to whether PLN will implement tariff differentiation over its extensive
power systems across Indonesia.
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 ofelectricity across Indonesia’s borders and GR No. 62/2012 on electricity support businesses.
GEOTHERMAL LAW

Geothermal development activities are defined as mining activities under the Geothermal Law No. 27/2003.
Further, according to the Forestry Law, no mining activities are allowed to occur in protected forest areas(protection and conservation forests). As a result, geothermal energy cannot be developed if it is located inprotected forest areas. This situation has been one of the major barriers to developing geothermal electricity
in Indonesia.
In order to remove the restriction to develop geothermal electricity in protected forest areas, thegovernment has 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 haschanged the permit scheme from that of a ‘Geothermal Mining Permit’ to a ‘Geothermal Permit’. This newlaw states that geothermal energy can be developed in production, protection and conservation forests after
obtaining a permit from the Ministry of Forestry under the category of an environmental service use permit.
The new regulation also states that the government sets the tariff on geothermal electricity. Thisapproach offers incentives to developers and affirms that central government holds the authorisation power
to conduct tenders for geothermal working areas (GWA) and then to control the projects. However, local
government is authorised to utilise geothermal energy for direct use (other than electricity generation).
Geothermal exploration and exploitation are based on the award of licences. The process involves
central government offering GWA for competitive bidding to prospective business investors. Public, private
and cooperative entities may submit bids on such GWA. Successful bidders are awarded GWA. The widthof the concession areas is determined according to the capacity of the individual geothermal system. The
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
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been approved by the government. The government can approve extensions to permission for the
exploitation of geothermal resources for an additional 20 years per extension approval. Working areas are
subject to tax, land rent and royalties determined by the government. Laws and regulations that govern theelectricity industry apply to the utilisation of geothermal energy for electricity generation.
FISCAL AND INVESTMENT REGIME

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

The PSC (production sharing contract) 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 producehydrocarbons now use PSCs (Johnston, 1994). Several types of PSC have since emerged internationally.
Technically, 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 PSC and royalty/tax systems and that the major difference is in the title transfer of oil or gas (Johnston
et al., 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 (TACs) and enhanced oil recovery (EOR)
contracts. A TAC is a variant cooperation contract or a PSC, and is typically used for established producing
areas; thus, it usually covers exploitation only. Operating costs are recovered from production and thecontractor 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 accord with the new Oiland Gas Law, existing TACs will not be extended. In addition, participants in PSCs, TACs and EOR
contracts may also enter into separate agreements known as joint operating agreements (JOA) and joint
operating bodies (JOB).
Since 2008, fifth generation PSCs have been introduced. The key differences between the later
generation PSCs and earlier generations are as follows:

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

PSCs now provide 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 which 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 (e.g. for 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 domesticgas 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 demand for gas or if
an agreement between the contractor and prospective buyers is not reached, the contractor may sell its entire
share to the international market.
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UPSTREAM

In 2013, the Directorate General of Oil and Gas, the Ministry of Energy and Mineral Resources signed 14
new PSCs. Apart from these, PSCs under the control of the upstream oil and gas implementing agency—
BP MIGAS (before becoming SKKMIGAS)—numbered approximately 317 by the end of 2013. Of these
317 PSCs, 79 were for oil and gas at the exploitation stage and 238 related to the exploration stage. Of the
238 PSCs, 160 PSCs were for conventional oil and gas, 55 were for shale gas and 23 were terminated.
(SKKMIGAS, 2013).
In order 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, namely (SKKMIGAS, 2013):
Banyu Urip—Mobil Cepu Ltd;Indonesia Deepwater Development (IDD)—Chevron Indonesia Company;Abadi—INPEX Masela Ltd.;

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

Bukit Tua—PC Ketapang II Ltd.;

Ande-Ande Lumut—AWE (north-west 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; and

Tangguh Train 3—BP Berau Ltd.

KEROSENE TO LIQUEFIED PETROLEUM GAS CONVERSION PROGRAMIn December 2009, Phase I of the government’s kerosene-to-liquefied petroleum gas (LPG) conversion
program was completed. The program distributed 23.8 million three-kilogram LPG cylinders to the densely
populated provinces of Jakarta, Banten, West Java, Yogyakarta and South Sumatra. The program eliminatedthe need for Pertamina to supply 5.2 billion litres of heavily subsidised kerosene for household use in theseprovinces.
In an extension of the program, 4.7 million three-kilogram LPG canisters were distributed by 2010. In
2011 to 2012, some 5.1 million three-kilogram LPG cylinders were distributed. In 2013, the program expects
to distribute 1.7 million cylinders with the same characteristics.
COAL-BED METHANE

Oil and gas laws and regulations also govern coal-bed methane. The Directorate General of Oil and Gas has
oversight of business activities with regard to coal-bed methane gas development. The MEMR issues
regulations, and establishes and offers coal-bed methane gas work areas. The Directorate General of Oiland Gas technically establishes and offers coal-bed methane work areas, with due consideration given to theopinion of BP MIGAS (which has now passed on its duties to SKKMIGAS).
Ministerial Regulation No. 36/2008 Regarding Business in Coal Methane Gas regulates coal-bed
methane development. The regulation covers exclusive rights and business related to coal-bed methane gas;
the method of determining and offering coal-bed gas methane work areas; the use of data, information,equipment and facilities; research, assessment and development of coal-bed gas methane; dispute resolution;
rulings on coal-bed methane gas as an associated natural resource; and the utilisation of coal-bed methanefor domestic needs.
MINERALS AND COAL MINING

Indonesia’s Minerals and Coal Mining Law (Law No. 4/2009) replaced the COW and PKP2B systems with
two forms of permit: specifically, 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.
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Under the new law, the mining fiscal regime includes corporate tax under the prevailing taxation law,a surtax of 10% and a mining royalty that is determined according to the level of mining progress, the levelof production 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 is yet to be formulated.
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) program by Presidential Regulation No. 67 of the Year 2005 Regarding Government Partnership with
Private Entities to Provide Infrastructure. The terms of the PPP include government investments andguarantees on PLN power purchases through a private guarantor established by Presidential Regulation No.
78 of Year 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 tocommence at the end of 2018.
GEOTHERMALIn order to promote geothermal development, the government has provided some fiscal incentives forincome 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 taxof 30% of the total investment (5% a year for six years); accelerated depreciation; 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 anddevelopment as long as the machinery, goods and materials have not been produced in the domesticarea, have been produced in the domestic area but their specifications do not meet the criteria andhave 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.
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 thefollowing:

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

The introduction of an energy manager, energy audits and an energy conservation program for final
energy users of 6 000 toe 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; and80

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I N D ON E S I AGovernment disincentives in the form of written notices to comply, public announcements ofnoncompliance, monetary fines and reduced energy supply for noncompliance.

In order 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 source users and energy users who use energy sources and/or energy of 6 000 toe per year
or greater shall carry out energy management and have an obligation to establish an energy
management team.

Energy source users and energy users who use energy sources and/or energy of less than 6 000 toe
per year shall carry out energy management and/or implement energy savings.

Energy conservation programs shall consist of short-term programs (improvements in operatingprocedures, maintenance and installation of simple device controls), medium- to long-term
programs (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 a minimum of 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 jurisdictions.



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
recommendation for priority access to energy supplies by ministers, governors and regents ormayors within their respective jurisdictions. Disincentives shall be imposed on energy source users
and energy users who have not implemented energy conservation through energy management.
These disincentives include written notices to comply, public announcements of non-compliance,monetary fines (calculated at 5% of the cost of energy used during the one-year reporting period)
and/or reduced energy supply for non-compliance (maximum 5% of contract capacity for a periodof one month, with an extension possible).

As part of the government commitment to increase energy efficiency and conservation, the MEMR
has developed an energy conservation project as one of the Nationally Appropriate Mitigation Actions(NAMAs), namely the Smart Street Lighting Initiative (SSLI). The SSLI program aims to implement energy
efficiency in street lighting by replacing conventional lighting technology with energy efficient technology,
namely light emitting diodes (LEDs), in urban areas. The SSLI will be implemented in 22 cities in Indonesia
in order to promote transformational changes in this particular sector. This program will then be
implemented all over Indonesia. The SSLI has been registered with a NAMA of the United Nations
Framework Convention on Climate Change (UNFCCC) since May 2014 in order to seek international
support for implementation. Besides 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 (USAID) and the French Development Agency (AFD).
Moreover, with regard to energy efficiency, Indonesia has also issued standards and regulations forenergy efficiency in buildings, namely: 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 03-6196-2011:
Procedures for Energy Audits in Buildings. The implementation of the standards is carried out by local
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, in order to obtain or renew its building permit. Some buildings, new and existing, are also
participating in the Greenship Program of the Green Building Council Indonesia. The Greenship Program
has four criteria, which are:

Sustainable building materials;



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

Waste management.
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I N D ON E S I ACurrently, there are 41 new buildings and three existing buildings registered under this program.
BARRIER REMOVAL

Indonesia is participating in a United Nations Development Program-Global Environment Facility (UNDPGEF) 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), has
five major programs promoting energy standards and labelling: policy making, capacity building,manufacturing support, regional cooperation and pilot projects. The BRESL project was finished in 2014
but the government has continued implementing the projects.
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 2015 were as follows (UNDP, 2014):


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;

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.
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 renewableenergy will be at least 23% by 2025 and at least 31% by 2050.

As part of the government 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 program aims to promote on-grid
renewable energy, particularly bioenergy-based power plants, by increasing the institutional capacity offinancial 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 Other Fuel. This made biofuel consumption mandatory from 2009.
The regulation controls:

The utilisation priority of biofuels;

Biofuel categories;Standards and specifications of quality;

Price setting;82

APEC E N E RG Y O VE R VI E W 2015

I N D ON E S I ABiofuel commerce, as another fuel;

Directives and oversight; andSanctions.

In order to reduce fuel imports by accelerating the improvement and expansion of biofuels, thegovernment revised Ministerial Regulation No. 32/2008 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 4.
Table 4: 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, 2015).

Until the end of 2013, the realisation of biofuel (biodiesel and bioethanol) utilisation was 2.8 million
kilolitre (kL), an increase of 27% from 2.2 million kL in 2012.
GEOTHERMALIn 2013, Indonesia’s total geothermal capacity was 1 344 MW, which is 4.7% of the total geothermal
potential of 28 910 MW (EBTKE, 2014). Indonesia has identified 4 855 MW of geothermal power potentialfrom existing geothermal plants, through capacity expansion of productive geothermal resources and fromnew geothermal projects at 51 sites. Specifically, the latter are anticipated to produce 2 585 MW in Sumatra
at 18 sites, 1 920 MW in Java at 20 sites, 180 MW in Sulawesi at four sites, 105 MW in the Nusa Tenggara
at six sites and 65 MW in the Maluku islands at three sites (ESDM, 2014b).
This geothermal power potential will be developed under the 10 000 MW Accelerated Developmentof Electricity Generation—Phase II program as well as a 35 000 MW program. It is expected that theseprojects will commence operations between 2014 and 2022. Under PLN’s Electricity Power Supply Business
Plan 2013–22 (Rencana Usaha Penyediaan Tenaga Listrik, or RUPTL), a further increase in geothermal capacity
by 6 055 MW is expected between 2014 and 2022. Of the total capacity, 4 625 MW will be developed by
IPPs, 230 MW by PLN and 1 200 MW by organisations with unallocated status (PLN, 2014).
HYDROPOWER

In 2013, Indonesia’s total hydropower capacity was 4 338 MW (including 69 MW of micro- and mini-hydro).
This was 5.8% of the total hydropower potential of 75 gigawatts (GW) (ESDM, 2014a). Under the 10
000 MW Accelerated Development of Electricity Generation—Phase II program over 2014–22, Indonesia
is committed to developing additional hydropower with a total capacity of about 1 803 MW. Of this total
capacity, 424 MW will be developed by IPPs and 1 379 MW by PLN.
PLN’s RUPTL 2013–22 also includes the potential for an additional 12 352 MW of hydropower
capacity during 2014–23 (including mini-hydro and pump-storage plants). Of this capacity, 339 MW would
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I N D ON E S I A

be developed by PLN, 1 423 MW by IPPs and the rest of the project’s 10 590 MW is not yet decided;
however, private participation is still an option for the project. The additional hydropower capacity includes
two pump-storage power plants in Java—specifically the Upper Cisokan (1 040 MW) in West Java and the
Matenggeng (900 MW) at the border of West and Central Java. These pump-storage plants are considered
important for the technical performance and stability of the Indonesian electricity grid.
These hydropower plants would increase Indonesia’s total large hydropower capacity to 12 352 MW,
or 13% 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 demand centres.
SAVING ENERGY AND WATER

Presidential Instruction No. 13 of the Year 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 theArmed Forces of 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 takemeasures and innovate in order to save energy and water within their institutional domains and/or in thedomains of state-owned businesses and regional government-owned businesses within their jurisdiction.
The Presidential Instruction assigns an electricity savings target of 20% from the average electricity use
over the six months prior to the Presidential Instruction; fuel savings targets of 10% through regulations tolimit the use of subsidised fuels; and water savings 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 a member of the National Team; theMinister of Energy and Mineral Resources is Executive Chief and a member of the National Team; 11cabinet ministers are also members of the National Team. The National Team is supported by the Executive
Team 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 it is to take the necessary preparatory measures and create the plans to build Indonesia’s initial
nuclear power plants; however, to date the team has not conducted any significant activities or performed
relevant tasks. The legal basis of Indonesia’s nuclear power development includes Law 17/2007 on Long
Term Development, Years 2005–15 and Government Regulation 43/2006 on the Licensing of Nuclear
Reactors.
Indonesia has developed an indigenous nuclear fuel cycle, although certain stages are still at thelaboratory stage. The economy has a well-established nuclear research program, which spans nearly five
decades. The National Nuclear Energy Agency (BATAN) currently operates three nuclear research reactors,
specifically the GA Siwabessy 30 MW materials testing reactor (MTR) pool-type reactor in Serpong; theKartini-PPNY 100 kilowatts (kW) Triga Mark-II reactor in Yogyakarta; and the Bandung 1 000 kW Triga
Mark-II reactor in Bandung. A fourth 10 MW pool-type research reactor is planned for development in thenear 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 between
5 000–10 000 tonnes of uranium with a grade ranging between 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
between 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 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 power will be the last option used to achieve Indonesia’s energy demand,
which means prioritising renewable energy sources.
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. In order 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.
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I N D ON E S I A

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 participating in and cooperatingwith the global effort to combat climate change. This position was expressed by the President of the
Republic of Indonesia 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 toreduce GHG emissions from forestry and the energy sector by 26% through domestic efforts, and by up to
41% through cooperation with other economies.
In response to this commitment and the challenges of climate change, the Indonesian government has
set out a roadmap in order to integrate climate change issues into development planning. The climate change
roadmap will integrate mitigation and adaptation into policy instruments, regulations, programs, projects,
funding schemes and capacity building in all development sectors. Two initial phases of the roadmap are
the integration of climate change into the Mid-Term Development Plan 2010–14 (Rencana Pembangunan
Jangka Menengah 2010–14, RPJM) and the launch 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 researchand development. The Transformation Fund is used to finance low-emissions programs, projects andinitiatives 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.
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 AND PHASE II

The accelerated power development program, 10 000 MW Phase I, had completed 7 895 MW of new
generation capacity by the end of December 2014. With regard to project constraints, the MEMR has set a
new final completion date of 2016 for the 10 GW Phase I of the program.
In 2010, the government mandated PLN to implement Phase II of the program. In this second phase,
it is intended that PLN will add 11.1 GW of capacity based on 68% coal, 19% geothermal, 10% combined
cycle gas and 3% hydropower. The two-phase accelerated power development program is expected to
rapidly increase generating capacity, encourage renewable energy utilisation and at the same time 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
Program 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.
In order 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 Program for Indonesia
in May 2015. This project is expected to be completed in five years (2015–19). Taking into account 7.4 GWof power plants that are at construction stage, the total additional capacity of the power plants that will be
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I N D ON E S I A

developed is 42.9 GW (7.4 GW plus 35.5 GW) up to 2019. In the 35 GW program, 56.5% of capacity comesfrom coal-fired power plants, 36.2% from combined cycle gas, 6.1% from hydropower and 1.2% fromgeothermal.
In order to realise such an ambitious program, a policy breakthrough has been prepared by thegovernment. This involves initiatives such as land acquisition secured by the government according to theland law for projects of public interest; establishing a ceiling price for electricity purchase; shortening the
procurement process in order to select developers and contractors through direct appointment and direct
selection and conducting due diligence to assess the developer 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).
HYDROELECTRIC POWER

The project in West Java for the Upper Cisokan pumped storage hydroelectric power plant, with four 260
MW units, received loans from the World Bank/International Bank for Reconstruction and Development(IBRD) in late 2011. Completion of the project is expected in 2017. The Upper Cisokan plant will be thefirst of its kind in Indonesia.
PLN has also secured financing for construction of the Jati Gede hydroelectric power plant, with two
55 MW units, in West Java, the Baliem 50 MW hydroelectric power plant in the province of Papua, theAsahan III 174 MW hydroelectric power plant in the province of North Sumatera, and the Meranginhydroelectric power plant, with two 175 MW units, in the province of Jambi, Sumatra.
REGULATIONSPOWER PURCHASES FROM GEOTHERMAL POWER PLANTS AND GEOTHERMAL STEAM BY PLN

On 3 June 2014, the government introduced a ceiling price mechanism under Ministerial Regulation No.
17/2014 to replace the Feed-in Tariff (FiT) scheme, which was introduced in 2012 (Ministerial Regulation
No. 22/2012). Under this new ceiling price mechanism, the government, through the MEMR, assigns PLN
to purchase electricity from geothermal developers based on price auction results (a ceiling price has been
set ranging from USD 11.8 cent/kWh to USD 29.6 cent/kWh depending on the commercial operation dateof the project and the region where the project is located). Within six months after PLN has obtained theassignment to purchase electricity from the government, a power purchase agreement (PPA) must be signedby both parties.
If a delay in a PPA is caused by a disagreement over the geothermal price, an independent body must
be appointed by both parties to recalculate the geothermal price, taking into account the developer’s costs.
The calculation of the geothermal price by the independent body will be the final price in the PPA.
Moreover, under this regulation, there is an option to escalate the tariff after the developers carry out
exploration and feasibility study phases.
POWER PURCHASES FROM HYDROPOWER PLANTS BY PLN

On 29 June 2015, the government established a FiT for hydropower plants with a capacity of up to 10 MW
through Ministerial Regulation No. 19/2015. Under the new FiT mechanism, PLN is obliged to purchaseelectricity from hydropower plants with a capacity of up to 10 MW at a predetermined price. The FiT is set
at approximately USD 12 cent/kWh to USD 14.4 cent/kWh for the first year to the eighth year dependingon the location of the projects within Indonesia and the voltage connection points. The FiT will decreased
to approximately USD 4.5 cent/kWh to USD 5 cent/kWh for the ninth year to the twentieth year dependingon the location of the projects within Indonesia and the voltage connection points. Moreover, the FiT canbe higher if the project is located in different location areas or islands since there is a regional factor (F) withranges from 1.0 to 1.6.
POWER PURCHASES FROM BIOMASS AND BIOGAS-BASED POWER BY PLN

On 16 October 2014, the government established a Feed-in-Tariff (FiT) for biomass and biogas-based
power through Ministerial Regulation No. 27/2014. Under the FiT mechanism, PLN is obliged to purchasebiomass electricity and biogas electricity at a predetermined price (for biomass, from approximately USD
9.6 cent/kWh to USD 12.5 cent/kWh depending on the voltage connection point; and for biogas, fromapproximately USD 8.6 cent/kWh to USD 11.7 cent/kWh depending on the voltage connection point).
Moreover, the FiT can be higher depending on the location of the projects since there is a regional factor(F) with ranges from 1.0 to 1.6. In addition, there is an incentive to encourage investor interest in biomass
power plants and biogas-based power plants if they are operate as load followers.

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REFERENCESASEAN (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.
BPS (Statistics Indonesia) (2015), Statistical Yearbook of Indonesia, June 2015,
www.bps.go.id/booklet/Statistik _Indonesia_2015.pdf.
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 2014,
http://www.djk.esdm.go.id/pdf/Buku%20Statistik%20Ketenagalistrikan/Statistik%20Ketenagalistrikan%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) (2014), Statistik
EBTKE 2014, December 2014.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
ESDM (Ministry of Energy and Mineral Resources) (2014a), Laporan Akuntabilitas Kinerja Instansi Pemerintah(LAKIP) KESDM Tahun 2013, March 2014, http://prokum.esdm.go.id/Lainlain/Lakip/Lakip%202012%20Komplit.pdf.
–– (2014b), Handbook of Energy and Economic Statistics of Indonesia 2014,
http://prokum.esdm.go.id/Publikasi/Handbook%20of%20Energy%20&%20Economic%20Statistic
s%20of%20Indonesia%20/HEESI%202014.pdf–– (2015), 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.
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 June2014.
NEA (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) (2014), Rencana Usaha Penyediaan Tenaga Listrik 2015–24 (RUPTL).
PwC (Pricewaterhouse Coopers 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) (2013), Laporan Tahunan 2013,www.skkmigas.go.id/wp-content/uploads/2013/08/Laporan-Tahunan-2013.pdf.
UNDP (United Nations Development Programme) (2014), Barriers Removal to the Cost-Effective Development ofEnergy Efficiency Standards and Labeling BRESL Indonesia,
www.id.undp.org/content/indonesia/en/home/operations/projects/environment_and_energy/barr
iers-removal-to-the-cost-effective-development-of--energy-ef.html.
USEFUL 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.skspmigas-esdm.go.id
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Statistics Indonesia (Badan Pusat Statistik, BPS)—www.bps.go.id
UNDP Indonesia—www.id.undp.org

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J AP ANJ 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 2013 was approximately USD 4 448 billion (2010 USD
purchasing power parity [PPP]). In 2013, Japan’s population of 127.3 million people had a per capita incomeof USD 34 928. Japan’s GDP increased by 1.6% in 2013 compared to 2012. Since indigenous energy
resources are modest, Japan imports nearly all of its fossil fuels to sustain economic activity. As of the endof 2011, the proven energy reserves included 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, 2013
Key dataa

Energy reservesb

Area (thousand km2)

377.8

Oil (million barrels)

44

Population (million)

127.3

Gas (billion cubic metres)21

GDP (2010 USD billion PPP)

4 448

Coal (million tonnes)

350

GDP (2010 USD PPP per capita)

34 928Uranium (kilotonnes U)–

Sources: a. EGEDA (2015); b. BP (2012).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

In 2013, Japan’s total primary energy supply was about 472 million tonnes of oil equivalent (Mtoe), 4.7%
more than in 2012. By fuel type, oil contributed the largest share (48%), followed by coal (25%) and naturalgas (23%). In 2013, the net imports of energy sources accounted for 90% of the total primary energy supply.
In 2013, Japan was the third-largest oil consumer of the world and APEC (4.5 million barrels per day(Mbbl/D)), after the United States and China (BP, 2014), and almost all of the oil was imported. The bulkof the imports (73% in 2013) were from economies in the Middle East such as Saudi Arabia; the United
Arab Emirates; Qatar and Kuwait (BP, 2014). In 2013, the primary oil supply was 229 Mtoe, an increase of
7.8% from the previous year.
Japan is endowed with only limited coal reserves, 350 Mt, which is less than twice the annual
consumption in 2013. It is the world’s largest importer of coking coal for steel production and steam coalfor power generation, and pulp, paper, and cement production. Japan’s main steam coal suppliers are
Australia; Indonesia and Russia, while those for coking coal are Australia; Indonesia and Canada.
Natural gas resources are also scarce in Japan. Domestic reserves stand at 21 bcm, which is less than
one-fifth of the annual consumption in 2013, and are located in the prefectures of Niigata, Chiba andFukushima. In 2013, the domestic demand was met almost entirely by imports in the form of liquefied
natural gas (LNG) (BP, 2014), from Australia (21%); Qatar (18%); Malaysia (17%); Russia (9.8%); Indonesia(7.2%); the United Arab Emirates (6.2%); Brunei Darussalam (5.8%); Oman (4.8%) and other economies.
LNG imports to Japan comprised 37% of the total global LNG trade. Natural gas is mainly used forelectricity generation, followed by reticulation as city gas and use as an industrial fuel. The primary natural
gas supply was 105.9 Mtoe in 2013, an increase of 0.4% from the previous year.
Japan has 287 gigawatts (GW) (EGEDA, 2015) of installed generating capacity and generated 1 088
773 gigawatt-hours (GWh) of electricity in 2013. Electricity is generated from thermal fuels (coal, natural
gas and oil—84.7%), hydro (7.8%) and nuclear (1.3%). Geothermal, solar and wind technologies produce
the remainder (6.1%).

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Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)
Total power generation

Indigenous production

23 534

Industry sector

134 837

1 088 773

Net imports and others

422 497

Transport sector

75 945

Thermal922 158

Total primary energy supply

471 705

Other sectors

92 214Hydro

85 160Coal

117 673

Non-energy

3 532

Nuclear

14 603

Oil

228 505

Total final energy consumption

306 530

Others

66 851Gas

105 918

Coal

34 854

Others19 609Oil

155 400

Gas

29 611

Electricity and others

86 665

Source: EGEDA (2015).
FINAL ENERGY CONSUMPTION

In 2013, the total final energy consumption in Japan was 306.5 Mtoe, 1.7% less than in the previous year.
The industrial sector consumed 44% of the total, followed by the transportation sector at 25%. Final energy
consumption in the industrial sector decreased by 0.2% compared to the previous year. Consumption in thetransport and other sectors also decreased by 2.9% and 3%, respectively. By energy source, petroleum
products accounted for 51% of the total final energy consumption, followed by electricity and others (28%),
coal (11%) and gas (9.7%).
ENERGY INTENSITY ANALYSIS

Japan’s energy intensity shows different trends between final energy consumption and primary energy supply.
The energy intensity of the final energy consumption decreased by 3.2%, from 71 tonnes of oil equivalent
per million USD (toe/million USD) in 2012 to 69 toe/million USD in 2013. Transportation and othersectors especially improve, by about 4.4 to 4.5%, among the sectors in Table 3. On the other hand, in terms
of primary energy supply, Japan’s energy intensity increased by 3.1%, from 103 toe/million USD in 2012 to
106 toe/million USD in 2013. The different trends are partly because of various factors in primary energy
supply and energy conversion, including stock changes in crude oil and petroleum products, as well as
efficiency changes in the total transformation sector.
Table 3: Energy intensity analysis, 2013
EnergyChange (%)

Energy intensity (toe/million USD)
2012

2013

2012 vs 2013

Total primary energy supply

103

106

3.1

Total final energy consumption

71

69

–3.2

Industry

31

30

–1.4

Transportation

18

17

–4.4

Others

22

21

–4.5

Non-energy

0.88

0.79

-9.7

Source: EGEDA (2015).

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
policy of the economy. Within METI, the Agency for Natural Resources and Energy is in charge of the90

APEC E N E RG Y O VE R VI E W 2015

J AP ANrational development of mineral resources, securing stable supplies of energy, promoting efficient energyuse, and regulating electricity and other energy industries. Regarding nuclear safety, the Nuclear Regulation
Authority (NRA), which is an independent commission affiliated to the Ministry of the Environment (MOE),
is 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 the energy policy of Japan 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 and safety.
The Basic Law on Energy Policy 2002 presents the core principles of Japan’s energy policy (METI,2008)—assurance of a stable supply, adaptation to the environment and use of market mechanisms. The
Strategic Energy Plan was established in 2003.
In 2006, Japan launched the New National Energy Strategy in response to the global energy situation(METI, 2008). The strategy contains a program of action towards 2030, and significantly emphasises
achieving energy security. Its five targets are energy efficiency improvements of at least 30%; increasing theshare of electric power derived from nuclear energy to over 30% to 40%; reducing oil dependence in thetransport sector to about 80%; raising Japan’s investment in oil exploration and development projects; andreducing overall oil dependence to below 40%.
The Strategic Energy Plan based on the law was revised in 2007 (METI, 2008). It focused on
developing an international framework for energy conservation and countermeasures to global warming;
establishing a nuclear fuel cycle at an early stage; promoting new energy sources for electric power suppliers;
ensuring a stable supply of oil and other fuels; promoting international cooperation in the energy andenvironmental fields; and developing an energy technology strategy.
The Strategic Energy Plan was revised again in 2010. It is required to be reviewed at least every three
years and revised if needed. In this revision, two new principles—energy-based economic growth andreforming energy industrial structure—were added to the three existing principles of energy security,environmental suitability and economic efficiency (METI, 2010). The plan aims to fundamentally modify
the energy supply and demand system by 2030, and has set ambitious targets for achieving this. For example,
the plan targeted doubling the energy self-sufficiency ratio (18% in 2010) and raising the ratio of zeroemission power sources to about 70% (34% at that time), of which 53% is nuclear generation.
Following the Great East Japan Earthquake in March 2011 and the subsequent Fukushima Daiichi
Nuclear Power Plant Accident, the DPJ (Democratic Party of Japan) Government decided to review its
Strategic Energy Plan. In June 2012, the Energy and Environment Council of the Japanese Government
announced ‘Options for Energy and Environment’. The council showed three scenarios for the share of
nuclear energy in the power generation mix in 2030: (1) a 0% scenario, (2) a 15% scenario, and (3) a 20% to
25% scenario (NPU, 2012).
However, Prime Minister Shinzo Abe, who was formally elected on 26 December 2012, has stated thatthe coalition of the Liberal Democratic Party and Komeito Party would reconsider the Democratic Party’s
nuclear energy policy. In April 2014, the Cabinet decided to approve the revised Strategic Energy Plan
(METI, 2014). This fourth plan provides a direction to Japan’s energy policies for medium/long-term (about
the next 20 years). It reaffirms the importance of renewables as promising low carbon and domestic sources,
coal as a stable and cost-effective base-load power source, and natural gas as a main flexible middle-load
power source. The latest plan also reaffirms the importance of nuclear as a low carbon and quasi-domestic
power source. However, it states that dependency on nuclear generation will be lowered to the extent
possible by energy saving and introducing renewable energy, as well as by improving the efficiency of thermal
power generation, and so on.
In July 2015, the Long-term Energy Supply and Demand Subcommittee of METI concluded the Longterm Energy Supply and Demand Outlook of Japan (METI, 2015a). The Subcommittee projected energy
demand to 2030 using macroeconomic indicators, and calculated total energy savings with a bottom-up
estimation about the sectorial savings potential. The Outlook indicates an electricity mix, primary energy
demand and supply, and energy-related CO2 emissions, and aims to ensure the ‘3E+S’ policy where ‘safety’is the foremost condition. It has three steps: 1) increase energy self-sufficiency (including nuclear as a quasidomestic energy) to about 25% from about 6% in 2012; 2) reduce electricity costs from the current level;and 3) greenhouse gas (GHG) emission reduction comparable to the targets of Europe and the US. The
government’s outlook aims for a well-balanced power mix where nuclear accounts for 20% to 22% of thetotal generated electricity, renewables for 22% to 24%, LNG for 27%, coal for 26% and oil for 3%. Nuclear
dependence is lower than before the earthquake (when it was around 30%). Within renewables, the twolargest sources are hydro, accounting for 8.8% to 9.2%, and solar (7%).
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J AP ANENERGY 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 was
about 40% in 2010, and increased to about half in 2013 partly due to the loss of nuclear generation andincremental oil-fired generation after the earthquake. Securing a stable supply of oil is one of the majorenergy policy issues of Japan.
The oil supply structure of the economy is vulnerable to disruption because it imports almost all of its
crude oil. In preparation for possible supply disruptions, Japan has created emergency oil stockpiles andindependently developed resources, and promoted cooperation with oil-producing economies to manage
emergencies.
The Japan Oil, Gas and Metals National Corporation (JOGMEC) is responsible for the economy’s
stockpile business and also provides financial and technical assistance to Japanese oil industries for oil andnatural gas exploration and development, both domestically and abroad. The oil stocks of Japan are well inexcess of the International Energy Agency’s 90-day net import requirements. As of December 2015, Japan
held the equivalent of 213 days of net imports, including state-owned stocks, private sector stocks and joint
oil storage programs with oil-producing countries (PAJ, 2015).
Competition continues in the domestic oil product market. The major Japanese petroleum companies
are seeking to reduce their refining capacity to comply with the law on the Promotion of the Use of Nonfossil Energy Sources and Effective Use of Fossil Energy Materials by Energy Suppliers, which requires thatthe heavy oil cracking unit capacity at petroleum companies is raised to 13% of the total distillation capacity.
The number of service stations in the economy decreased from 59 615 in 1996 to 34 706 in 2013 due
to market liberalisation (NPA, 2014). The Provisional Measures Law on Importation of Specific Kinds ofRefined 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 an important role as the point of interaction with final consumers.
The number of oil refineries in Japan decreased from 40 in 1996 to 23 in October 2015, and the refining
capacity from 5.3 Mbbl/D to 3.9 Mbbl/D (PAJ, 2015).
NATURAL GAS

Demand for natural gas has been increasing rapidly over the past two decades, at an annual rate of
3.2% between 1990 and 2013 (EGEDA, 2015). Natural gas is supplied almost entirely by imports in theform of LNG. Since Japan prioritises a stable and secure supply of LNG, Japanese LNG buyers havegenerally been paying a higher price than those in Europe or the US under long-term ‘take or pay’ contracts
with rigid terms on volume and price. However, recently, Japanese gas and electric utilities seek to reduce
their costs because of the deregulation of the gas and electricity markets. The utilities have been striving tosecure LNG supply on flexible terms that enable them to quickly respond to changes in the market situationand supply gas at lower prices. Japan has also been seeking alternative gas supplies; for example, the economy
promoted technological developments in the production and processing of methane hydrate, which isabundant in the ocean areas surrounding Japan, and is considered a future energy resource.
Japan will reform the domestic gas market. The Fourth Strategic Energy Plan states that the period
from 2014 to 2018–20 is devoted to reforming the electricity and gas systems to build a more liberalised andcompetitive energy market. Accordingly, amendments to the Gas Business Act were enacted in June 2015
to fully liberalise the retail market by about 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 2013, coal accounted for 25% of the total primary energy supply. Coal will continue to play an importantrole in Japan’s energy sector, mainly for power generation and iron, steel, cement, and paper and pulp
production. Japan is the second-largest coal importer in the world, after China, accounting for about 14%of the total global coal imports in 2013 4 (IEA, 2015).

4 Note that in 2014, India’s coal imports exceeded that of Japan, making the latter the third-largest coal importer in theworld.

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J AP ANELECTRICITY MARKET

Electricity was the second-largest contributor, after the petroleum industry, to the total final energy
consumption in 2013. The increased use of electrical appliances in homes, widespread use of personal
computers and related information technology in offices and a shift in the industry structure to more
services-based sectors has driven the steady increase in electricity consumption in recent years.
Japan has been partially liberalised to ensure fair competition and transparency (METI, 2002).
However, after the earthquake and the subsequent Fukushima Daiichi nuclear power accident, the Japaneseelectricity sector faces a mounting pressure to further deregulate the market for more competitive andtransparent electricity supply. To reform the market, the Electricity Business Act was amended in 2013, 2014
and 2015 (METI, 2015b). This reform focuses mainly on three stages: 1) establishing the Organisation for
Cross-regional Coordination of Transmission Operators (OCCTO) in April 2015; 2) full retail competition
from April 2016; and 3) legal unbundling of the transmission/distribution sector from 2020 and transition
to overall liberalisation of retail price after the unbundling. In order to avoid a monopoly situation after retailliberalisation in 2016, retail tariffs of designated utilities will be regulated as a transitional measure, and thengradually deregulated at the same time as or after the legal unbundling.
FISCAL REGIME AND INVESTMENT

The Japanese Government recognises the necessity of 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 in the market with government
guarantees and building a flexible and effective finance system through JOGMEC, with the objective of
reducing geopolitical and technical risks for future projects.
ENERGY EFFICIENCYThe Energy Conservation Law 1979, established after the oil crises, is the basis of all energy conservation
policies in Japan. It requires improving the energy efficiency of the industrial, consumer (commercial andhousehold), and transport sectors. Japan has improved its energy efficiency by approximately 40% after thecrises. The Energy Conservation Law 1979 was partially amended in May 2013. The amendment includes
the expansion of the top-runner program. In addition to energy consuming items, those that do not consume
energy but rather contribute to high efficiency or energy conservation, such as building insulation materials,
were added to this program.
In 2014, the revised Strategic Energy Plan set the following initiatives (METI, 2014):
Enhancing Japan’s energy efficiency (already at the highest level in the world) by introducing themost advanced technologies for replacing equipment in the industrial sector;Enhancing support and regulatory measures (including the top-runner program) 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 as well as 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 a newly constructed public building by 2020, and all newly
constructed buildings on average by 2030;



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

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

Japan has a system of Feed-in Tariffs (FiT). In August 2011, the Act on Purchase of Renewable EnergySourced Electricity by Electric Utilities was passed by the Diet (the Japanese Parliament). This Act took
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J AP ANeffect on 1 July 2012. It obliges electric utilities to purchase electricity generated from renewable energy
sources (solar photovoltaic, wind power, small and medium-sized hydropower, geothermal and biomass)
based on fixed-period contracts with fixed prices. Table 4 shows the prices for the FiT in fiscal year 5 (FY)2015. Solar power prices were reduced from the FY 2014 levels (METI, 2015c).
Table 4: Prices for feed-in tariff in FY 2015
Renewable Energy
Solar

Onshore windPrices (JPY per kWh)a
Over 10 kW

31.3b/29.2c

20Less than 10 kW

33.0/35.0d

10Less than 10 kW (Double generation)

27.0/29.0d

10Over 20 kW

23.8

20

Less than 23 kW

59.4

20

38.9

20

From 1 000 kW to 30 000 kW

25.9

20

From 200 kW to 1 000 kW

31.3

20

Less than 200 kW

36.7

20

Over 15 000 kW

28.1

15

Less than 15 000 kW

43.2

15

Methane fermentation gasification

42.1

20

Unused woods

34.6

20

General woods

26.0

20

Waste (excluding woods)

18.4

20

Recycled woods

14.0

20

Offshore wind
Hydro

Geothermal

Biomass

Years

Note: a. 8% tax is included; b. From April to June 2015; c. After July 2015; d. Solar PV, approved for grid connectionin Hokkaido, Tohoku, Hokuriku, Chugoku, Shikoku, Kyusyu and Okinawa areas after April 2015, is obliged to beinstalled with suppression control system. Higher purchase prices are applied to this case.
Source: METI (2015c).

Costs incurred by the utilities in purchasing renewable energy-sourced electricity shall be transferred
to all electricity customers, who will pay a surcharge for renewable energy at a rate proportional to theirelectricity usage. Surcharge for renewable energy is calculated as follows since May 2015 (METI, 2015c):
Surcharge for renewable energy=Monthly electricity consumption (kWh) ×1.58 JPY/kWhFiT rates and contract periods are to be determined according to factors such as the type, form of
installation and scale of renewable energy sources. Contract rates and periods shall be reviewed and set every
year by METI, and are based on the recommendations of an independent committee in the ministry.
Table 5 shows the installed generation capacity for each renewable source of energy after the
introduction of the FiT (METI, 2013; METI, 2015d). Three years after the introduction of the FiT, in total,
88 023 megawatts (MW) of renewable capacity have been authorised, while the accumulated renewablecapacity by the end of June 2012, that is, before the introduction of the FiT, was 20 600 MW. This indicatesthat if all the authorised capacity is installed, the generation capacity based on renewable energy becomes
more than five times since the introduction of the FiT. Non-residential solar PV shows a boom in Japan; its
installed capacity and authorised capacity amounting to 17 453 MW and 78 527 MW, respectively, accounting
for 81% of the newly installed capacity after the FiT introduction, and 89% of the authorised capacity. Startup renewable capacity is 21 560 MW, only 24% of the authorised capacity.

5 Fiscal year starts from April in Japan.

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J AP AN

Table 5: Installed generation capacity by renewable energy after introduction of FiT (MW)Solar (Residence)

Introduced and Start-up Capacity

Authorised Capacity

Before FiT

After FiT

After FiT

Accumulated capacity
by the end of June 2012
4 700

July 2012–June 2015

July 2012–June 2015

3 324

3 952

900

17 45378 527

Wind

2 600

347

2 344

Medium hydro

9 600

106

662

Biomass

2 300

321

2 465

500

9

71

20 60021 56088 023Solar(Non-residence.
More than 10 kW)

Geothermal
Total
Sources: METI (2013, 2015d).

NUCLEAR ENERGY

There were 54 nuclear reactors in Japan in 2010, the most recent year before the Fukushima Daiichi Nuclear
Power Plant Accident. As of November 2015, the number of reactors decreased to 43 due to decommissionof the Fukushima Daiichi Nuclear Power Station 6 and other five reactors7: Tsuruga unit 1, Mihama units 1
and 2, Shimane unit 1 and Genkai unit 1. Owners of the five reactors decided the retirements due to theaging of the facilities and the large amount of additional costs to meet the new safety regulations enforced
in June 2013.
The year 2014 was the first year without nuclear generation since 1966, when commercial nuclear
operations started. After the Ohi units 3 and 4 ceased operations for periodic inspections in September 2013,no nuclear reactors were restarted until August 2015. The Sendai nuclear power plant became the firstreactor to restart under the new regulatory scheme. Units 1 and 2 started operations in August and October
2015, respectively. As of December 2015, the NRA has given the final safety approval to Takahama units 3
and 4 and Ikata unit 3.
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 achieved the commitment by reducing 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 fuelconsumption after the earthquake and the subsequent nuclear plant shutdown. However, the carbon sinkby 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).
For further emission reductions, Japan introduced the Tax for Climate Change Mitigation since
October 2012 (MOE, 2012). This tax is levied on crude oil/oil products, gas and coal. The tax has to beraised in phases; already accomplished in April 2014, and due in April 2016 (Table 5); the tax value will be
JPY 289 per tonne-CO2 for each kind of product from April 2016. Revenue from this tax is used for
implementing various measures to promote energy efficiency and renewable energy, as well as the use ofclean fossil fuels.

6 Total six reactors. The reactor owner (Tokyo Electric Power Company) decided to decommission units 1 to 4 in April

2012 and units 5 to 6 in January 2014.
7 Reactor owners announced in March 2015.

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J AP AN

Table 5 Tax for 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).

In July 2015, Japan submitted its Intended Nationally Determined Contribution (INDC) to the United
Nations Framework Convention on Climate Change (UNFCCC, 2015). The economy decided its emission
reduction level based on the government’s Long-term Energy Supply and Demand Outlook. Japan’s INDC
towards post-2020 GHG is at the level of a reduction of 26% by FY 2030 compared to FY 2013 (25.4%
reduction compared to FY 2005), equivalent to 1 042 million tonnes of CO 2 in 2030.

N OTA B L E E N E RG Y D E V E L O P M E N T S
LONG-TERM ENERGY SUPPLY AND DEMAND OUTLOOKAND SUBMISSION OF INDC

As mentioned in the ‘Energy Policy Framework’ section, in July 2015, the economy concluded its futureenergy mix in a quantitative manner. The government’s outlook aims to ensure the ‘3E+S’ policy where‘Safety’ is the foremost condition, and shows a well-balanced power mix. Based on the energy mix, Japandecided its INDC and submitted to UNFCCC (see the ‘Climate Change’ section).
REFERENCES

BP (British Petroleum) (2012), Statistical Review of World Energy,
www.bp.com/assets/bp_internet/globalbp/globalbp_uk_english/report.
–– (2014), BP Statistical Review of World Energy, https://www.bp.com/content/dam/bp/pdf/Energyeconomics/statistical-review-2014/BP-statistical-review-of-world-energy-2014-full-report.pdf.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, www.ieej.or.jp/egeda/database/database-top.html.
IEA (International Energy Agency) (2015), Coal Information 2015, http://www.iea.org/bookshop/667Coal_Information_2015.
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.

–– (2008), Energy in Japan s.l.
–– (2010), The Strategic Energy Plan of Japan-Meeting Global Challenges and Securing Energy Futures s.l.
–– (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), The Strategic Energy Plan (in Japanese),www.meti.go.jp/press/2014/04/20140411001/20140411001-1.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/.

–– (2015c), Prices for Feed-in Tariff,
www.enecho.meti.go.jp/category/saving_and_new/saiene/kaitori/kakaku.html.

–– (2015d), Authorised and installed capacity under Feed-in Tariff,
http://www.fit.go.jp/statistics/public_sp.html.
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APEC E N E RG Y O VE R VI E W 2015

J AP ANMOE (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 (inJapanese), www.sekiyu.or.jp/topics/data_a.html.
NPU (National Policy Unit) (2012), Options for Energy and the Environment,
www.npu.go.jp/policy/policy09/pdf/20120720/20120720_en.pdf.
PAJ (Petroleum Association of Japan) (2015), 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%20I
NDC.pdf.
USEFUL LINKS

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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R E P U B LI C OF K O R E A

R 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 is located in north-east Asia between China and Japan. It has an area of 99 538
square kilometres (km2) and a population of 50 million people as of 2013. Korea’s population density is very
high, with an average of more than 500 people per km2. Around 20% of the population lives in Seoul,
Korea’s capital and its largest city. The economy’s geography is largely made up of hills and mountains, withwide 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 buildings need to be heatedduring the bitterly cold winters.
During the last few decades, Korea has been one of Asia’s fastest-growing and most dynamic
economies. Gross domestic product (GDP) increased at a rate of 6.5% per year from 1980 to 2013, reaching
USD 1 643 billion (2010 USD purchasing power parity [PPP]) in 2013. GDP per capita (2010 USD PPP)
income in 2013 was USD 32 711, almost six times higher than in 1980. Korea’s major industries include thesemiconductor, shipbuilding, automobile, petrochemical, digital electronic, steel, machinery and parts andmaterials industries.
Korea has few indigenous energy resources. It has no oil resources except a small amount ofcondensate, only 320 million tonnes of recoverable coal reserves and 5.7 billion cubic metres of natural gas.
Thus, in order to sustain its high level of economic growth, Korea imports large quantities of energy
products. Korea imported about 84% of its primary energy supply in 2013. In the same year, it was theworld’s fifth-largest importer of both oil and liquefied natural gas (LNG) and the world’s third-largest
importer of coal.
Table 1: Key data and economic profile, 2013
Key dataa

Energy reservesb, c

Area (km2)

99 538Population (million)50

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

5.7

GDP (2010 USD billion PPP)

1 643

Coal (million tonnes)

320

GDP (2010 USD PPP per capita)

32 711Uranium (kilotonnes U)–

Sources: a. EGEDA (2015); b. EIA (2015); c. KEEI (2014).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

Korea’s total primary energy supply increased almost seven-fold between 1980 and 2013 from 38 million
tonnes of oil equivalent (Mtoe) in 1980 to 263 Mtoe in 2013. 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 1 tonne of oil equivalent (toe) in 1980 to 5.2
toe in 2013. This increase was similar to that of Japan and most European economies.
In 2013, Korea’s total primary energy supply was 263 Mtoe, a 0.1% increase from the prior year. In
terms of energy source, oil represented the largest share (37%), followed by coal (29%) and gas (18%). The
remaining 16% of the primary energy supply came from nuclear and hydro energy sources. Energy imports
accounted for about one-third of Korea’s total import value in 2013.
The oil supply in 2013 was 97 Mtoe, a 0.7% decrease from the prior year. In 2013, the economy
imported more than 80% of its crude oil from the Middle East. With regard to coal, the supply in 2013
totalled 77 Mtoe, a 1% increase from the prior year. Korea has modest reserves of low-quality, high-ash
anthracite coal, which are insufficient to meet its domestic demand. Thus, almost all of Korea’s coal demandis met by imports. Korea is the world’s fourth-largest importer of steam coal and third-largest importer of
coking coal after Japan. The main coal imports come from Australia, Canada, China, Indonesia, Russia andthe United States.
Since the introduction of LNG in 1986, natural gas use in Korea has grown rapidly. Gas supply reached
48 Mtoe in 2013. Its share of the primary energy supply was 18% in the same year. Most of Korea’s LNG
imports come from Qatar, Indonesia, Oman, Malaysia, Brunei Darussalam and Australia. Korea began
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R E P U B LI C OF K O R E A

producing natural gas domestically in November 2004 after a small quantity of natural gas was discoveredin the Donghae-1 offshore field in the south-east.
Korea’s electricity generation in 2013 was 538 terawatt-hours (TWh), a 1.3% increase from 2012.
Generation by thermal sources, including coal, oil and natural gas, accounted for 72% of the total electricity
generated, followed by nuclear at 26% and hydro and others at 1.9%.
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

43 423

Industrial sector

45 957

Total power generation

537 891

Net imports and others

233 575

Transport sector

31 343

Thermal389 095

Total primary energy supply

263 103

Other sectors

44 978

Hydro

4 289

Coal

77 320Non-energy

43 787

Nuclear138 784

Oil

96 570Total final energy consumption

166 065

Others

5 723

Gas

47 618

Coal

7 718

Others

41 595

Oil

84 923Gas

24 140Electricity and others

49 283

Source: EGEDA (2015).
FINAL ENERGY CONSUMPTION

Korea’s total final energy consumption in 2013 was 166 Mtoe, which is the same level as the prior year. The
industrial sector accounted for the largest share at 28%, while the transport sector accounted for 19%. The
remainder (53%) was used in the residential and commercial sector and as non-energy consumption by
agriculture and industry, such as for petrochemical feedstock. In general, demand in the industrial sector has
weakened since the late 1990s, and demand in the transport and commercial sectors has increased.
By energy source, petroleum products accounted for 51% of total energy consumption, followed byelectricity and other (30%), natural gas (15%) and coal (4.7%). Natural gas consumption has increased
significantly because of the economy’s policy measures.
ENERGY INTENSITY ANALYSISThe 2.9% growth of Korean GDP in 2013 resulted in a 2.7% decrease in the energy intensity of theeconomy’s total primary energy supply. This is an economy-wide energy intensity level decrease of 4.4 tonnesof oil equivalent per million USD. With regard to final energy demand, the energy intensity level decreasedby 2.8% from the 2012 level of 104 tonnes of oil equivalent per million USD to 101 tonnes of oil equivalent
per million USD in 2013. Using a per sector analysis, the industrial sector registered the largest reduction inenergy use per USD million of GDP from a level of 29 tonnes of oil equivalent per million USD in 2012 to
28 tonnes of oil equivalent per million USD in 2013, a fall of 5%. The transport sector in 2013 had a lower
intensity at 19 tonnes of oil equivalent per million USD, an increase of 0.7% from its prior year’s level. Theenergy intensities of the other sectors and for non-energy fell by 3.7% and 2.0% respectively from the 2012
levels.

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Table 3: Energy intensity, 2013
EnergyEnergy intensity (toe/million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

165

160

–2.7

Total final energy consumption

104

101

–2.8

Industry

29

28

–5.0

Transportation

18.9

19.1

0.7

Others

28

27

–3.7

Non-energy

27.1

26.7

–2.0

Source: EGEDA (2015).
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 in order to sustain
economic growth. The government is now seeking a new direction in energy policy with the aim ofsupporting 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 theMinistry of 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 thepresident 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 Planfor Energy, emergency preparedness, foreign energy resource development, nuclear energy policy, thecoordination of energy policies and projects, the prevention and settlement of social conflict related toenergy issues, the transportation of energy and the physical distribution plan, the effective execution of theenergy budget and energy issues within the United Nations Framework Convention on Climate Change(UNFCCC).
As part of its liberalisation efforts in the energy sector, in 2001 the government established theElectricity Regulatory Commission to take charge of regulations in the electric power sector and to manage
technical and professional 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 businesspractices in the energy sector.
The Korea Energy Economics Institute (KEEI) develops energy policies related to the production ofenergy statistics. It also considers policies with regard to demand and supply overviews, energy conservationand climate change, the petroleum industry, the gas industry, the electricity industry, and the new andrenewable energy industry among others. It is financed directly by the government.
The Korea Institute of Energy Technology Evaluation and Planning (KETEP), funded by thegovernment, is Korea’s major energy technology research institute. Its mission is to contribute to growthacross the economy by developing industrial core energy technologies and deploying outcomes.
The Korea Energy Agency (KEA) 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 will 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 up to 2035 (MOTIE, 2014a). According to the Second Energy Basic
Plan, total primary energy demand is projected to grow at an annual average rate of 1.3% between 2011 and2035. Final energy demand will grow at 0.9% per year. Energy intensity is expected to drop from 0.26 toe
per million KRW (toe/million KRW) in 2011 to 0.18 toe/million KRW in 2035 with an improvement of100

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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 proposes six major policy strategies as follows: A move to an energy management-oriented policy;
 Building a power generation system based on distributed generations (DGs);
 Pursuit of harmonisation between the environment and safety;
 Strengthening the 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 has led the economy to 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 situation by
operating oil stockpiling 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 there may be stages of restructuring and liberalisation during the outlook period,
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 the
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, as a holding company, was owned by the Korean Government. KEPCO isstill a dominant player in the electricity sector, controlling 87% of total power generation and 100% oftransmission and distribution in Korea (KEEI, 2014).
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 the import 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 in which to achieve the smooth succession of the existing import andtransportation contracts, the privatisation of import and wholesale businesses, the stabilisation of prices andthe balance of supply and demand, and the revision of related legislation and enforcement (KEEI, 2002).
With regard to competition in the import and wholesale sectors of KOGAS, a final decision onwhether to split the sectors from KOGAS or to 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 amonopoly system within each region, will be introduced in stages, in conjunction with the progress made in
the wholesale sector. As of the end of 2011, no decision on the liberalisation of the gas market had been
made.
OIL, GAS AND ELECTRICITY MARKETS
OIL

Because of Korea’s dependence on oil imports, the government has been trying to secure supplies for the
short and long terms. To ease short-term supply disruptions and to meet International Energy Agency (IEA)
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obligations, the Korean Government has been increasing its oil stockpile since 1980. At the end of 2013,
Korea held 187 million barrels in strategic reserves. This economy-wide stockpile capacity substantiallyexceeds the IEA’s 90-day requirement.
The state-controlled KNOC has been actively exploring and developing oil and gas, both locally andabroad, in order to improve energy security. As of the end of February 2011, it was conducting 191 projects
in 25 countries. Private companies (including SK, GS Caltex, S-Oil and Hyundai Oil Bank) are also activein the oil and gas sector, as well as the downstream market and wholesale import areas.
In order 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 Accountof Energy and Resources.
Korea has also been trying to diversify its crude oil supply sources. The number of source countries
increased from nine in 1980 to 29 in 2004; however, the economy’s dependency on oil imports from theMiddle East remains high (86% in 2013). Korea is also actively strengthening its bilateral relations with oilproducing 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 Forum and the Energy Charter in order to enhance its crisis management capabilities. In particular,
the government plans to play a leading role in energy resource development and trade in north-east Asia bycreating a collaborative framework on energy cooperation.
NATURAL GAS

In order to reduce the economy’s dependence on imported oil, Korea introduced natural gas-based city gas
to the residential sector in the 1980s. Since then, gas use has grown rapidly and has replaced coal and oil in
the 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 businessin each region of the economy. Not only is KOGAS the world’s largest LNG buyer, it also promotes thedevelopment of natural gas resources abroad in such countries 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 demand would decrease by 0.34% per year from 2014–29 (MOTIE, 2015b). By
sector, the city gas sector’s demand for natural gas is projected to increase by 2.1% per year, while thedemand for 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 in order to facilitate international tradingbusinesses.
ELECTRICITY

Because of Korea’s economic growth, electricity consumption has risen substantially over the past few
decades. Throughout the 1990s, the average annual growth rate was 9.5%. Then, between 1990 and 2013,
installed capacity increased by more than four from 21 gigawatts (GW) in 1990 to 87 GW in 2013.
The Seventh Electricity Demand and Supply Basic Plan (2015–29), finalised by MOTIE in July 2015,
projects that electricity demand will grow by 2.1% per year from 2015 to 2029 and that additional capacityof 49 GW will be required by 2029 (MOTIE, 2015a). When decommissioning is taken into account, thistranslates to about 137 GW of total generation capacity for this period.
Korea’s electricity industry is dominated by KEPCO. KEPCO 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.
In order to rectify an energy supply and demand structure that is overly dependent on oil, theconstruction of oil-fired power plants has been strictly controlled and the development of nuclear, coal andnatural gas electricity generation units has been promoted. Gas-fired power plants were first introduced in1986. During the period of the Seventh Basic Plan, 13 nuclear-energy power plants, 20 coal-fired power
plants and 14 gas-fired power plants are planned for construction. Korea has been building nuclear-energy
power plants since the 1970s because nuclear energy is a strategic priority for the government. The share of
total electricity production capacity in terms of nuclear-energy power plants is projected to increase to 24%
in 2029.

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FISCAL REGIME AND INVESTMENTIn December 2009, the Korean Government approved tax reforms in order to foster a business-friendly
environment and to promote investment. The tax changes included a reduction in corporate tax rates andan 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 forthe lower bracket was implemented as scheduled, while the implementation for the higher bracket wasdelayed. Since 2012, the corporate tax rate has been 22% on taxable income over KRW 20 billion, 20% on
between KRW 200 million and KRW 20 billion, and 10% on taxable income below that KRW 200 million.
In order 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 touniversities from 50% to 100%.
ENERGY EFFICIENCYThe Korean Government has introduced various policy measures in order to improve energy efficiency,
including energy-demand management schemes for end users, adjustment of the energy pricing system andthe provision of incentives for companies to invest in energy efficiency. These policy measures aim to
improve energy efficiency by 8.7% by 2017 compared with 2012 and to save 9.3 Mtoe in 2017. Announcedin 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 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 Korean government plans to provide 11%of total primary energy supply with new and renewable energy (NRE) by 2035. The development of solar
and wind power as main energy sources will also enable 13% of total electric energy in Korea to be supplied
by NRE by 2035.
CLIMATE CHANGE

On 15 August 2008, a new Low Carbon, Green Growth vision for Korea was announced. The vision aimed
to shift the traditional development model of fossil fuel-dependent growth to an environmentally friendly
model.
In order 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 tookeffect in April 2010. This legislation provided the legal and institutional basis for green growth. In order toimplement the vision of green growth 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.
The National Strategy for Green Growth calls for the construction of a comprehensive, long-term(2009–50) master plan in order to address the challenges caused by climate change and resource depletion.
The strategy consists of three main objectives and ten policy directions: Mitigation of climate change and achievement of energy independenceo Effective reduction of greenhouse gas emissions (MKE, 2009)o Reduction in fossil fuel use and the enhancement of energy independenceo Strengthening the capacity to adapt to climate change.
 Creation of new engines for economic growtho Development of green technologies (KEEI, 2010a)
o Greening of existing industries and the promotion of green industries
o Advancement of industrial structureo Engineering a structural basis for the green economy (KEEI, 2010b).
 Improvement in the quality of life and enhanced international standingo Greening the land and water, and building a green transportation infrastructure
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R E P U B LI C OF K O R E Ao Building the green revolution into people’s daily liveso 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 S
CLEAN ENERGY/ENERGY EFFICIENCYNEW BUSINESS MODELS IN ORDER TO RESPOND TO CLIMATE CHANGE

In July 2014, MOTIE introduced six new energy-related businesses, based on emerging business models, inorder to reduce CO2 emissions and increase energy efficiency (MOTIE, 2014b). MOTIE also establishedthe Energy Efficiency and Climate Change Bureau for more efficient policy support. Plans for R&D inrelated technology and regulation reforms were announced in December 2014 and April 2015 (Governmentof Korea, 2014 and 2015).
The six business models are:
1. A demand 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 also provides system maintenance for companies.
3. An independent micro-grid, which replaces diesel generators with NRE generators and anelectricity 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 demand for fossil-fuel electricity and on increasing R&D
investment in order 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 greenhousegas (GHG) emissions by 37% from the business-as-usual (BAU 850.6 MtCO2 eq.) level by 2030 across all
economic sectors, based on the BAU projection of the Korea Energy Economics Institute and Energy and
GHG Modelling System (KEEI-EGMS).
Korea accounts for approximately 1.4% of global GHG emissions, including land use, land-use change
and forestry (LULUCF), according to CAIT of the World Resources Institute (WRI). Korea’s mitigation
potential is limited because of its industrial structure, which comprises a large share of manufacturing (32%
as of 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 makeuse of nuclear energy, one of the major mitigation measures available to it.
REFERENCES

EIA (Energy Information Administration) (2015), Proved Reserves of Natural Gas 2013,www.eia.gov/beta/international/rankings/.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
Government of Korea (2014), ‘The 3rd Energy Technology Development Plan’, December 2014,www.motie.go.kr.
–– (2015), ‘Implementation Plan for New Energy-related businesses and Core Technology Development Strategy’, press
release, April 2015, www.motie.go.kr.
KEEI (Korea Energy Economics Institute) (2002), An analysis of policy issues in natural gas industry
restructuring.
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R E P U B LI C OF K O R E A–– (2010a), Ministers Urge Investors to Pursue Green Partnership, Press release, 10 September 2010.
–– (2010b), Cooperation on Smart Grids Vital, Press release, 4 February 2010.
–– (2014), Yearbook of Energy Statistics, www.keei.re.kr/keei/download/YES2014.pdf.
MKE (Ministry of Knowledge Economy) (2009), ‘Korea promises to cut carbon emissions’, press release, 18
November 2009, www.mke.go.kr.
MOTIE (Ministry of Trade, Industry and Energy) (2014a), ‘The Second Energy Basic Plan’, press release,
January 2014, www.motie.go.kr.
–– (2014b), ‘Facilitating new energy-related businesses as a climate change response’, press release, July 2014,www.motie.go.kr.
–– (2014c), ‘The Fourth New and Renewable Energy Basic Plan’, press release, September 2014,www.motie.go.kr.
–– (2015a), ‘The Seventh Electricity Demand and Supply Basic Plan’, press release, July 2015, www.motie.go.kr.
–– (2015b), ‘The Twelfth Plan for Long-Term Natural Gas Demand and Supply’, press release, December 2015,
www.motie.go.kr.
USEFUL LINKS

Korea Electric Power Generation 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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M AL AY S I A

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

Malaysia is located in South-East Asia. It has a total territory of approximately 330 803 square kilometres(km2), covering the states in the Peninsular Malaysia, Sabah and Sarawak on the island of Borneo, and theFederal Territories of Kuala Lumpur, Putrajaya and Labuan. Kuala Lumpur is the capital of Malaysia, while
Putrajaya is the seat of the federal government (EPU, 2013). In 2013, Malaysia’s population stood at 29.5
million, an increase of 1.5% from the 2012 level of 29.2 million (EGEDA, 2015).
Malaysia’s gross domestic product (GDP) reached USD 658 billion (2010 USD purchasing power
parity [PPP]) in 2013, an improvement of 4.7% from USD 628 billion in 2012. This represented a 3.2%
improvement in GDP per capita from USD 21 638 in 2012 to USD 22 321 (EGEDA, 2015). The largest
contributions to GDP were from services (55%) and manufacturing (25%) (MOF, 2015). In 2014, the main
export products were electrical and electronic (E&E) products (approximately 33% of total exports),
petroleum products (9.2%) and liquefied natural gas (LNG) (8.4%) (MATRADE, 2015).
When compared with other large economies in the Asia-Pacific Economic Cooperation (APEC),
Malaysia’s energy resources can be considered moderate in absolute terms. A 2013 survey shows that theEast Malaysian states hold nearly two-thirds of Malaysia’s energy reserves; the rest are located in Peninsular
Malaysia. The economy’s oil reserves (including condensate) were 5.9 billion barrels, 40% of which is foundin Peninsular Malaysia (the Malay basin). The abundant natural gas reserves of the economy are estimated at
approximately 98 trillion cubic feet (Tcf), with nearly half found in the Sarawak basin. The coal reserves,
assessed at 1.9 billion tonnes, are located mostly in Sarawak and Sabah (EC, 2014a).
Located near the equator, where sunshine is abundant, Malaysia has huge potential to develop solar
power albeit the cloudy appearance that constantly manifest the region. It also has huge potential for biomass
although the logistical network connectivity has been far from perfect. As of 2013, Malaysia accounts for
39% of world palm oil production and 44% of world palm oil exports (MPOC, 2015). The production creates
abundant agricultural residue, particularly empty fruit bunches.8
Table 1: Key data and economic profile, 2013
Key dataa, bArea (km2)

Energy reservesc
330 803

Oil (billion barrels)

5.9
2.8

Population (million)

29.5

Gas (trillion cubic metres)

GDP (2010 USD billion PPP)

658

Coal (million tonnes)

GDP (2010 USD PPP per capita)

22 321Uranium (million tonnes)

1 938
–

Sources: a. EPU (2013); b. EGEDA (2015); c. EC (2014a).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

Malaysia’s total primary energy supply was 81 100 kilotonnes of oil equivalent (ktoe) in 2013, an increase of
5.9% from the 2012 level of 76 621 ktoe. Natural gas contributed the largest share at approximately 41% (33223 ktoe), followed by oil with 39% share (31 648 ktoe) and coal with a 19% share (15 290 ktoe). Other
resources include hydro, which in 2013 provided a minimal share of approximately 1% (939 ktoe) to theprimary energy supply (EGEDA, 2015).
Among the primary energy sources, coal demand decreased by more than 3% over 2012–13. Gas
demand increased by more than 3% and oil showed significant growth of more than 16%. The completionof several oil storage facilities, which began operations in 2013, is responsible for the large growth in the
demand for oil. Oil storage is part of a government initiative to improve Malaysia’s position as an oil-trading

8 The process of palm oil production generates large amounts of residue, such as empty fruit bunches (EFBs) of palm.

EFBs are a type of woody biomass with a calorific value of 4 400 kilocalories per dry kilogram (kcal/kg-dry); they are
regarded as a safe and promising biofuel resource because they have a very low chlorine content (Asia Biomass, 2009).

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hub and to increase the level of energy security. It is expected that Malaysia will have cumulative oil storage
capacity of approximately 10 million cubic metres by 2020 (EC, 2014a).
Traditionally, Malaysia has been an energy exporter of mainly crude oil, LNG and natural gas. Malaysia
registered total energy exports of 27 323 ktoe in 2013, a decrease of 0.8% from the 2012 level of 27 541 ktoe.
Over the same period, total energy imports increased by nearly 30% from 20 493 ktoe to 26 601 ktoe (EC,2014a). Most of the increase occurred in the oil sector, probably because of the new oil storage facilities,
which were completed in 2013. Malaysia is the second-largest exporter of LNG in the world and the secondlargest producer of crude oil and natural gas in South-East Asia (EIA, 2014).
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. The bulk of the oil reserves
are located in the Malay basin, which produces light and sweet crude oil (EIA, 2014). Malaysia’s average daily
oil production was 575 thousand barrels per day in 2013, approximately 80% of which were crude oil while
the rest were condensates. In 2013, the Malay basin yielded almost 43% of total oil production, followed by
Sarawak with 32% and Sabah with approximately 25% (EC, 2014a).
Malaysia has five oil refineries with a combined capacity of 566 million barrels per day (Mbbl/D)(including condensate splitter capacity). Petroliam Nasional Berhad (PETRONAS), the state-owned nationaloil company, has three refinery facilities that provide more than 50% of total daily refinery production. Petroland diesel accounted for approximately 80% of total domestic sales of petroleum products in 2013. In thesame year, Malaysia imported a total of 19 383 ktoe of petroleum products, an increase of approximately
39% from the 2012 level, in order to meet the growing domestic requirement (EC, 2014a).
As aforementioned, the Malaysian Government, arising from the Economic Transformation
Programme, embarked on a large scale oil and gas project in the southern Peninsular Malaysia which is called
as Pengerang Integrated Petroleum Complex (PIPC). PIPC is divided into two mega-projects - Pengerang
Independent Deepwater Petroleum Terminal (PIDPT) undertaken by private companies and Refinery andPetrochemical Integrated Development (RAPID) Project that involves PETRONAS as the major developer.
Because of the size of the project, Platts, a provider of energy information that produced the Free on Board(FOB) Singapore oil benchmark price for the oil trade, will expand the price benchmarking scope to include
oil storage terminals from Malaysia and rename it FOB Straits (Platts, 2015a).
NATURAL GAS

Most of the gas reserves of Malaysia are offshore in Peninsular Malaysia in the eastern areas, Sarawak and
Sabah. Most of the gas reserves are non-associated (83%), while the remaining reserves are associated withoil basins (17%). Sarawak hosts slightly more than half of the total reserves, followed by Peninsular Malaysia
with 36% and Sabah with 13%. In 2013, the average daily natural gas production was 6 730 million standard
cubic feet per day (MMscf/D), an increase of approximately 3.2% from the 2012 level of 6 521 MMscf/D(EC, 2014a). Most of the production came from Sarawak with a 63%. Peninsular Malaysia had a 31% share
and Sabah had a 6.3% share. In order to meet local demand, Malaysia imported gas via pipelines from the
Malaysia-Thailand Joint Development Area (MT-JDA) and Indonesia (EC, 2013). Year of 2013 marked anhistorical year for Malaysia for the importation of LNG. Although Malaysia is one of the world's largest
LNG exporters, a geographical mismatch between where the gas is produced (Sabah and Sarawak) and theregions of highest demand (Peninsular Malaysia) prompted Malaysia to build a regasification terminal (RGT)
to facilitate the importation of LNG. In 2013, Malaysia imported approximately 1 450 ktoe of LNG (EC,2014a).
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 of six gas-processing
plants with a combined capacity of 56 million cubic metres per day (mcm/d) (2 000 MMscf), producing
methane, ethane, butane and condensate (Gas Malaysia, 2015a).
Malaysia has extensive LNG export facilities and contributed approximately 10% of the world’s LNG
exports, equivalent to 25 Mt per year. In 2013, Japan remained the largest importer of Malaysia’s LNG withapproximately a 61% share, followed by Korea, Chinese Taipei and China with export shares of 16%, 12%
and 11% respectively (IGU, 2015).

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In order to boost the oil and gas reserves, PETRONAS is intensifying efforts in deepwater exploration.
According to Bank Pembangunan Malaysia Berhad, Malaysia has approximately 615 100 km 2 of acreage
available for oil and gas exploration. In 2011, production-sharing contracts (PSCs) covered 36% of the total
acreage, leaving almost two-thirds of the area available for exploration (BPMB, 2012). This indicates thepotential for PETRONAS to expand existing proven hydrocarbon reserves. This was demonstrated in April
2015 with an oil discovery at the Bestari-1 exploration well in Deepwater Block R in Sabah (INPEX, 2015).
COAL

Malaysia’s coal resources mostly consist of bituminous and sub-bituminous coal. Estimated reserves areapproximately 1 938 Mt, which are found in Sabah and Sarawak. Even with substantial coal resources,
domestic coal production has not been that aggressive because most of the coal deposits are far inland, whichmakes extraction costs high. Likewise, some areas have been declared protected areas, such as the Maliau
Basin in Sabah, thereby prohibiting coal-mining activities. Only Sarawak has coal-mining activity. The areas
are Kapit (the largest producing coal basin) with 2 006 765 metric tonnes of production in 2013, Sri Aman
with 776 586 metric tonnes and Mukah with 110 611 metric tonnes (EC, 2014a).
Of total coal consumption, approximately 90% was consumed by the power generation sector, while
the remainder was consumed by the iron, steel and cement industries. Malaysia imports coal from Australia,
Indonesia, South Africa and, recent years, Russia in order to meet its growing requirements. (EC, 2013).
According to IEA Energy Statistics 2014, Malaysia ranked as the ninth-largest coal importer in theworld in 2013 with coal consumption reaching more than 20 Mt (IEA, 2014). This reflects a rapid expansionof coal generation capacity, especially during 2000–13 when coal consumption in the power sector increased
from 1.5 million tonnes of oil equivalent (Mtoe) to 14 Mtoe. Coal generation capacity expanded in order tomeet increasing electricity demand and reduce dependence on natural gas, which previously dominatedgeneration with a share as high as 70% in the 1990s (EC, 2014a). Although Malaysia has 1.9 billion tonnesof proven coal reserves, most deposits are of poor quality (high ash content etc.) and located in protectedareas such as national parks in Sabah and Sarawak. With limited options to extract sufficient domestic coalin order to meet demand, Malaysia has become highly dependent on coal imports.
ELECTRICITY

There are three major electricity grids in Malaysia. The national grid in Peninsular Malaysia and the Sabah
grid are both regulated by the federal government; the Sarawak grid is under the responsibility of state
government. The national grid is connected to Thailand’s grid to the north (with the capacity for powertransfer of 380 megawatts (MW)) and to Singapore’s main grid to the south (with the capacity for powertransfer of 450 MW) (HAPUA, 2015). The Sarawak grid is connected to the Kalimantan grid in Indonesia.
Capacity is expected to reach 50 MW by the end of 2015 (SEB, 2015).
Malaysia’s total installed power generation capacity in 2013 was recorded at 29 748 MW, an increase of
approximately 2% from the 2012 level of 29 143 MW. Such an increase in installed capacity was attributed
to the additional capacity of 600 MW from the Bakun hydro project in Sarawak (Bakun hydro project total
installed capacity is 2 400 MW). Approximately 60% of total installed capacity was owned by the independent
power producers (IPPs) and the rest by government-linked utilities, self-generation facilities andcogeneration facilities (EC, 2015a).
In the same year, total electricity generation was 138 330 gigawatt-hours (GWh), an increase of
approximately 3% from the 2012 level. Thermal generation, mostly from natural gas and coal, accounted for
91% of total power generation, while hydropower accounted for the remainder (EGEDA, 2015).

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M AL AY S I AFINAL ENERGY CONSUMPTION

Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

91 528Industry sector

13 638

Total power generation

138 330

Net imports and others–6 387

Transport sector

19 751

Thermal126 472

Total primary energy supply

81 100

Other sectors

8 450

Hydro

10 586Coal

15 290Non-energy

6 945

Nuclear–Oil

31 648

Total final energy consumption

48 784

Others

1 272

Gas

33 223

Coal

1 538

Others939

Oil

26 775Gas

9 886

Electricity and others

10 585

Note: For full details of the energy balance table, see www.ieej.or.jp/egeda/database/database-top.html.
Source: EGEDA (2015).

In 2013, Malaysia’s final energy consumption reached 48 784 ktoe, an increase of 9.3% from the 2012
level. The transport sector was the biggest energy consumer, overtaking the industrial sector and accounting
for a 41% share of the total final energy consumption or approximately 19 751 ktoe. It was followed by theindustry sector with a 28% share or 13 638 ktoe, the non-energy sector with a 14% share or 6 945 ktoe, andother sectors with a share of 17% or 8 450 ktoe (EGEDA, 2015).
In 2013, in terms of fuel type, oil was still the most consumed fuel, particularly for the transport sector,
accounting for approximately 55% of total energy demand. This was followed by gas with a 20% share,electricity with a 22% share and coal with a 3% share. Oil consumption increased by nearly 18% to 26 775
toe in 2013 from 22 716 toe in 2012. However, natural gas and coal consumption decreased by 2.5% and
12% respectively (EGEDA, 2015).
ENERGY INTENSITY ANALYSIS

Because the primary energy supply growth rate stood at 5.9% while the economy’s real GDP growth (2010
USD PPP) was 4.7% in 2013, primary energy intensity in Malaysia increased by 1.1% from 122 tonnes of oil
equivalent per million USD (toe/million USD) in 2012 to 123 toe/million USD in 2013. Final energy demandintensity increased 4.4% from 71 toe/million USD in 2012 to 74 toe/million USD in 2013 (EGEDA, 2015).
The transportation sector showed a large increase of nearly 25% from 24 toe/million USD in 2012 to
30 toe/million USD in 2013. At the same time, a large reduction of nearly 15% in final energy intensity canbe seen in the industry sector (EGEDA, 2015). One of the reasons behind the unusual high growth rate of
final energy intensity in the transportation sector is because the data collected from the oil companies werebased on sales, which may include sales for oil storage purposes.9
However, based on Malaysia’s National Energy Balance 2013, final energy consumption reached
51 583 ktoe, an increase of 10.4% from 2012 (46 711 ktoe). This led to a decrease in final energy
consumption intensity by 0.08% from 76.9 toe/million USD in 2012 to 76.8 toe/million USD in 2013 (EC,2014a).

9 Data from the Malaysian Automotive Association shows that total vehicle sales in 2013 increased by 4.5% from 2012,

while in 2012, total vehicle sales increased at a slightly higher rate of 4.6% from the 2011 level. A further check with
Malaysian officials confirmed that the data for final energy in the transport sector need to be readjusted in the future.

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M AL AY S I ATable 3: Energy intensity analysis, 2013
EnergyEnergy intensity (toe/million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

122

123

1.1

Total final energy consumption

71

74

4.4

Industry

24

21

–15

Transportation

24

30

25

Others

12.9

12.8

–0.6

Non-energy

9.6

10.6

9.7

Source: EGEDA (2015).
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 forthe development 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 ofenergy through the development of indigenous energy resources and the diversification of energy
supply from domestic and international sources.



The utilisation objective: To promote the efficient utilisation of energy and discourage wastefuland non-productive 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
are designed to support these objectives and their implementation.
In 1980, the National Depletion Policy was enacted in order to safeguard and preserve Malaysia’s energy
resources, particularly its oil and gas resources. Under this policy, the total annual production of crude oilshould not exceed 3% of ‘oil initially in place’. In effect, this limits the production of crude oil to 650
thousand barrels per day. The policy also extended to the production of natural gas, imposing a limit of
2 000 MMscf/D in Peninsular Malaysia (UNPAN, 1999).
A year later, Malaysia introduced the Four-Fuel Diversification Policy in order to expand the fuel mix
for power generation. Initially, the focus of the policy was to reduce the economy’s dependence on oil as thedominant energy source. The scope of the Four-Fuel Diversification Policy was further expanded in 2001
through the implementation of the Five-Fuel Diversification Policy, which incorporated renewable energy(RE) (e.g. biomass, solar and mini-hydro) as the fifth fuel (KeTTHA, 2015).
In support of the Five-Fuel Diversification Policy, the National Biofuel Policy was launched in 2006
and the National Renewable Energy Policy and Action Plan (NREPAP) was introduced 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).
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. 3 Six strategies are outlined in the
Eleventh Malaysia Plan. These include pursuing green growth for sustainability and resilience, andstrengthening the infrastructure in order to support economic expansion, both of which have implications
for energy initiatives (EPU, 2015).

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In the past, the focus for economic growth was on quantity over quality. The Eleventh Malaysia Plan
places greater emphasis on quality growth, taking into consideration the economy’s natural resources and theimpacts of their use on the environment. The Eleventh Malaysia Plan covers almost the entire spectrum ofenergy.
ENERGY SECTOR STRUCTURE

PETRONAS is Malaysia’s national petroleum corporation, wholly-owned by the Malaysian Government,
created under the Petroleum Development Act of 1974. PETRONAS is vested with the exclusive rights forthe exploration and production of petroleum whether onshore or offshore of Malaysia. It also has
responsibility for the planning, investment and regulation of the upstream sector. Any foreign and privatecompanies desired to explore and produce petroleum in Malaysia have to enter into a Production Sharing
Contracts (“PSC”) with PETRONAS.
However, 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
state and Sarawak Energy Berhad (SEB) in Sarawak state. These utilities undertake electricity generation,transmission, distribution and supply activities in their respective areas. TNB is the largest power utility in
Malaysia and is a publicly listed company. SESB is a subsidiary of TNB with 80% owned by TNB and theremaining 20% by the state government of Sabah. SEB is wholly owned by the state government of Sarawak(HAPUA, 2013). Various independent power producers (IPPs), dedicated power producers and cogenerators complement the three utilities. The key ministries and government agencies for the Malaysianenergy sector are as follows:

The Economic Planning Unit (EPU) sets the general direction and strategies for Malaysia’s energy
policies, through the formulation and implementation of the national policy on energy, and thedevelopment of the oil and gas industry.



The Ministry of Energy, Green Technology and Water (KeTTHA) is responsible for strengthening
energy resources to ensure electricity supply is of quality, reliable and cost effective. KeTTHA
formulates and implements the national policy on renewable energy and energy efficiency. In thisregard, KeTTHA plays a pivotal role in driving the development of renewable energy and thepromotion of energy efficiency programs. This is in line with the Ministerial Functions Act 1969;
Ministers of the Federal Government (No 2) (Amendment) (No 2), Order 2015.

The Energy Commission (EC) is a statutory body established in 2001 to serve as a regulator forelectricity and piped gas supply industries in Peninsular Malaysia and Sabah. The commission’s
main functions are to provide technical and performance regulations for the electricity and piped
gas supply industries; act as the safety regulator; and protect consumers by ensuring the quality ofservices, the supply of electricity and piped gas, and the maintenance of reasonable prices.
ENERGY SECURITY

The Tenth Malaysia Plan, launched in 2010, outlines the strategic approaches that are designed to improveenergy supply security. One of the measures identified is the diversification of energy resources, specifically,an increase in the contribution of RE to the primary energy and power generation mix. Nuclear energy has
also been considered as a possible energy supply option for Malaysia in the future (EC, 2014b).
During the Eleventh Malaysia Plan, energy security and RE will continue to be considered, while
demand-side management (DSM), a major paradigm shift, which incorporates energy efficiency andconservation measures, will be implemented in order to ensure the sustainable management of energy
resources. Several notable strategies, initiatives and targets to improve energy security in Malaysia under the
Eleventh Malaysia Plan can be simplified, as in Table 4.

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M AL AY S I ATable 4: Energy security measures and targets under the Eleventh Malaysia Plan
Security measures

TargetStrengthening gas supply security and connectivity for:Peninsular Malaysia

Supply a total of 2 500 MMscf/D

Operationalise RGT-2 by 2017

Provide additional buffer from:
10% supply from swing field;
15% supply storage in RGT-1

Sabah



Link Sabah-Sarawak Gas Pipeline (SSGP) to Federal
Territory of LabuanProvide alternative bypass between platforms

Installed capacity and reserve margin for:Peninsular Malaysia

24 943 MW with reserve margin of 20%

Sabah

1 782 MW with reserve margin of 34%

Sarawak

5 103 MW with reserve margin of 19%

SAIDI10 for generation, transmission and distribution
Peninsular Malaysia

50 minutes/customer/year

Sabah

100 minutes/customer/year

Sarawak

157 minutes/customer/year

Increase generation capacity in Peninsular Malaysia

7 626 MW from new generation capacity and 2 253 MW byextending retiring units

Apply a fuel diversity index, the Hirchmann–
Herfindahl Index (HHI),11 for the power sector

Achieve below 0.5

Strengthen the Sabah electricity grid for reliability

Transmission and distribution networks reinforcement

Subsidy rationalisation for electricity tariff

Tariff review in order to achieve market priceSource: EPU (2015).

Another measure to improve energy security is by diversifying LNG supply importation. The economy
is confronting the issue of the geographic disparity of the natural gas supply and demand among its regions.
The west of the Peninsular Malaysia requires a greater natural gas supply for power and industrial use, while
Sarawak and Sabah produce natural gas but lack local demand. In order to address these concerns, LNG
RGTs are being constructed in order to increase supply security through imports of LNG from the global
gas market (EIA, 2014). Malaysia has completed its first RGT in Malacca (Melaka), which commenced
operation in May 2013 with a capacity of 2 × 130 000 cubic metres and an annual storage volume of 3.8
million Mt (PETRONAS, 2012). The RGT will improve the security of the natural gas supply in Peninsular
Malaysia and can accommodate LNG importation. The building of a second RGT is planned for Johor in
the Peninsular Malaysia as part of the Pengerang Integrated Petroleum Complex (PIPC). The PIPC is seen
to be the next regional downstream oil and gas industrial hub in the Asian region (PETRONAS, 2014a).
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

10 The system average interruption duration index. This is commonly used as a reliability indicator by electric power

utilities. It measures the average outage duration for each customer served and is calculated as minutes/customer/year
or simply minutes of interruption.
11 The Herfindahl-Hirschman Index (HHI) is an economic concept which is widely applied in competition law and fromwhich an assessment about market share can be derived.

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in the ASEAN region. ASEAN members, through the Trans-ASEAN Gas Pipeline project (TAGP) and theASEAN Power Grid project (APG), have entered into interconnection cooperation agreements on power
and natural gas. The TAGP will provide the region with a secure supply of natural gas through theinterconnection of gas pipelines and associated infrastructure. Malaysia may serve as a hub in the TAGP
given its location and extensive natural gas infrastructure (EIA, 2014). The APG will integrate the power
grids of ASEAN members in order to enable regional sales of electricity. The APG will also optimise thedevelopment of energy resources in the region.
GREEN TECHNOLOGY POLICY

In its pursuit of a low-carbon economy, the Malaysian Government launched the National GreenTechnology Policy in July 2009. This serves as the basis for all Malaysians to enjoy an improved quality oflife by ensuring that the objectives of the national development policies continue to be balanced withenvironmental considerations. The policy is built on four pillars as follows.
Energy: seek to attain energy independence and promote efficient utilisation.

Environment: conserve and minimise the impact on the environment.



Economy: enhance the national economic development through the use of technology.

Society: improve the quality of life for all.

Four sectors have been identified as the primary focus of the policy as follows.
Energy. The application of green technology in power generation and in energy supply-side
management, including cogeneration by the industrial and commercial sectors, in all energyconsuming 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.

Transport. The incorporation of green technology into the transportation infrastructure andvehicles, relating in particular to biofuels and public road transport (KeTTHA, 2011).

Among the policy’s long-term goals is the intention to infuse green technology and a significant
reduction of energy consumption into Malaysian culture. Malaysia has joined the global endeavour by
earmarking the promotion of green technology through the establishment of the Ministry of Energy, GreenTechnology and Water in April 2009. This replaced the Ministry of Energy, Water and Communication. In
addition, the Malaysian Energy Centre was restructured into the Malaysian Green Technology Corporationand has become the lead agency of the Ministry for the promotion, development and implementation ofgreen technology.
The Green Technology Master Plan is being formulated to provide strategic directions for the
implementation of the green technology policy and to realise its aspirations and goals. The Green Technology
Master Plan also serves as guidance for the development of action plans, programs and projects for the
Eleventh and Twelfth Malaysia Plans.
The Green Technology Financing Scheme (GTFS) was established in 2010 in order to accelerate theexpansion of the green technology industry with an allocated government fund of MYR 3.5 billion (USD
825 million) until 2017. The objective of establishing the fund is to provide a special financing scheme forsoft loans to companies that produce and utilise green technology. As of the end of February 2016, 227
projects had been approved for loan under the GTFS amounting to MYR 2.07 billion (GreenTechMalaysia,
2016).
The introduction of the MyHIJAU Labelling Program is intended to ensure the availability of green
products and services in accordance with international standards and regulations. Currently, there are threeagencies in Malaysia that have been recognised to provide environmentally friendly certification schemes.
They are:(i) SIRIM Eco Labelling by SIRIM Berhad for certifying the environmental attributes of green
products and services;(ii) Energy Efficiency Labelling by the Energy Commission for energy-efficiency labelling of electricalappliances; and113

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M AL AY S I A(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 in order to promote green
technology in the building sector. It also intends to raise awareness among developers and building owners
about the design and construction of green and sustainable buildings. A GBI certificate is granted todevelopers and building owners who have satisfied the standards in six areas: energy efficiency, indoor
environmental quality, sustainable site planning and management, materials and resources, water efficiency
and innovation.
In order to encourage the adoption of green building design, the government intends to establish itself
as the market leader. All new government buildings will have to adopt green features and designs, while
existing government buildings will be gradually retrofitted. Under the Tenth Malaysia Plan, two governmentbuildings were chosen as pilot projects for retrofitting through the energy performance contracting (EPC)
concept. Data collected through these projects are promising: energy consumption in both buildings was
reduced to the required level with payback periods of 1.6 years and 4.7 years. Under the Eleventh Malaysia
Plan, the government aims to retrofit 100 government buildings (EPU, 2015). Other initiatives that are being
implemented are the Government Green Procurement (GGP) and Green Township projects. The GGP
integrates environmental considerations into the public sector procurement process in order to protect thenatural environment, conserve resources and lessen the harmful effects of human activities. By 2020, theGGP will be implemented in all government offices and will ensure that 20% of the public sector’s purchasesof products and services are green-labelled. The Green Township project advocates the adoption of a Low
Carbon Cities Framework and 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 the government flagship and on-going projects.
ENERGY MARKETSMARKET REFORM

Malaysia’s energy market is regulated. Further, the government provides subsidies to energy consumers.
However, Malaysia intends to embark on the implementation of energy market reforms, as suggested in the
Eleventh Malaysia Plan, through the gradual removal of energy subsidies. As a strategy to rationalise subsidies,
the plan states that gas prices for power and non-power sectors will be revised every six months in order togradually reflect market-based prices. The intention of this approach is to unbundle energy bills in order toitemise subsidy values. This will eventually delink subsidies from energy use.
The first round of subsidy reductions for the power sector’s natural gas prices has been in place since
1 June 2011. As a social safety net, government assistance in different forms is extended to low-income
households and other groups. In order to institutionalise greater market discipline, other measures will also
be pursued. These include separate accounting for generation, transmission and distribution activities;
performance-based regulations; and the review and renegotiation of power purchase agreements(EPU, 2015).
As part of the market reform initiative, and in order to move towards better regulation, the Energy
Commission imposed Incentive-Based Regulation (IBR) on the utility companies in 2013. The
implementation of IBR will continue in order 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 take into
account changes in fuel prices in order to increase the transparency and efficiency of electricity supply. New
power plants and extensions of existing power plants will continue to be undertaken through competitive
bidding in order to ensure greater transparency. This will create healthy competition among industry players,
resulting in more competitive tariffs and in turn benefitting end-consumers (EPU, 2015).
Besides IBR, 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 in order to create a level playing field forthird party gas players. Such players can then utilise the natural gas supply infrastructure, which is thePeninsular Gas Utilisation (PGU) pipeline and the RGT, at fair and transparent fees. The amended Act will
come into force in 2016 through the Energy Commission covering the economic regulation of the domestic
natural gas market. This will include the RGT, the PGU 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).
UPSTREAM ENERGY DEVELOPMENT

Because Malaysia’s oil and gas basins are becoming mature fields, the government, through PETRONAS,
has intensified exploration efforts in the more challenging areas of underexplored deepwater; ultradeepwater; high pressure, high temperature (HPHT); and high CO 2 fields. In 2013, 100 active PSCs were in
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operation as a result of a favourable upstream investment environment. This environment comprised a stable
fiscal environment, commercial and tax incentives, infrastructure support and the availability of locally based
service companies that supported upstream activities. A PSC is a form of public-private partnership modelin which PETRONAS has public responsibility and the contractors represent the private interest(PETRONAS, 2013a).
Under the Eleventh Malaysia Plan, with an average overall resource replenishment ratio (ORRR) of 1.9
achieved from 2011 to 2013, the government is cautiously optimistic that the lifespan of the reserves can be
prolonged.12 This ‘healthy’ ORRR is attributed to continuous investment by PETRONAS (EPU, 2015).
In order to encourage players aggressively explore and develop marginal fields, PETRONAS
introduced a variation of the PSC in 2011 known as the risk service contract (RSC). An RSC shares risk
among PETRONAS, the project owner and the contractor. Under this service contract model, the contractor
provides the upfront capital expenditure (capex); however, the capex is reimbursed upon first commercial
production. The contractor is also entitled to a remuneration fee per barrel based on a pre-determined
percentage of the field revenue. There are already three active RSCs. The first (the Berantai Field)
commenced gas production in 2012. The other two RCSs are the Balai Cluster, which was awarded a contract
in 2011 and achieved its first oil production in November 2013 (PETRONAS 2013b), and the Kapal, Banang
and Meranti fields cluster, which was awarded a contract in 2012 and achieved its first oil production in
December 2013 (PETRONAS, 2014b). However, based on the feedback from EPU, RSCs initiative are
currently underwent reviews due to current low oil prices environment.
ELECTRICITY AND GAS MARKETS

Malaysia’s electricity supply industry is monopolistic. It is vertically integrated whereby each of the utility
companies (TNB, SESB and SEB) undertakes the generation, transmission and distribution of electricity in
its respective region. However, IPPs provide nearly half of the electricity generation supply to the utility
companies. All electricity utilities have a government stake as either a government-owned entity or a main
shareholder. The 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, the Eleventh Malaysia Plan espouses the importance ofenhancing the productivity and efficiency of utility providers. The strategies that the plan has identified fora reliable and stable electricity supply industry include increasing and diversifying generation capacity,strengthening the transmission and distribution networks, restructuring the electricity supply industry, andimproving customer service delivery.
In order to increase and diversify its generation capacity, Malaysia intends to develop aggressively
alternative sources of energy, specifically hydro, and increase coal and LNG importation. There are plans to
expand the generating capacity of coal-fired power plants in Peninsular Malaysia and Sarawak using more
efficient coal technology, which includes supercritical or ultra-supercritical technology. This new technology
will reduce CO2 emissions from coal-fired power plants (EPU, 2010). Nuclear energy will also be exploredas a long-term option for electricity generation. Prior to the Fukushima incident in Japan, the economy
considered building nuclear power facilities by 2023 (EPU, 2015).
In order 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’s
plan is to remove the Special Industrial Tariff (SIT) for the power sector. This tariff was introduced during
the Asian financial crisis in 1997–98 in order to help manufacturers to stay competitive. Although launched
as a temporary measure, the SIT has remained in place. The SIT will be abolished in stages and fully 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 the period of 2016–20 (EPU, 2015).
However, transmission and distribution systems will be expanded and improved in order to minimise
losses. The SAIDI, used as a progress indicator in the Eleventh Malaysia Plan, has been given target
reductions of 50 minutes for Peninsular Malaysia (60.5 minutes in 2012), 100 minutes for Sabah (424 minutes
in 2013) and 157 minutes for Sarawak (168 minutes in 2013) by 2020.
It is intended that the gradual reduction of the subsidy for gas will eventually enable the adoption of amarket price level for gas. This is expected to have a significant effect on the electricity supply industry.
12 ORRR is an indicator to measure discovered reserves versus production. A ratio of one and above is considered‘healthy’.

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M AL AY S I ACurrently, gas for power generation supplied by the Peninsular Gas Utilisation (PGU) pipeline system isheavily subsidised by the government. Other reforms will also be implemented, such as the introduction of
performance-based regulation, the renegotiation of power purchase agreements, and separate accounting(unbundling) for the generation, transmission and distribution activities. In order to achieve these goals, theMalaysian Government plans to introduce IBR as an instrument to regulate the gas supply industry so that
it will be more efficient and competitive.
In addition, access to 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 ofthe electricity 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 energy efficiency is considered an
important element in Malaysia’s energy plan and policy. Energy efficiency initiatives are set to receive
renewed attention under the Eleventh Malaysia Plan through a reinvigoration of DSM. It is intended that
this will be achieved by formulating a comprehensive DSM master plan. EPU will initiate a study on DSM,
which covers the whole spectrum of the energy sector (EPU, 2015).
Table 5: Energy efficiency targets under the Eleventh Malaysia Plan
Item

TargetComprehensive long-term
DSM master plan

Formulating policy and action plan covering the entire spectrum of the energy sector
including electrical, thermal, and usage in the transport sector• Achieve a target of 700 registered electrical energy managers (REEMs)• Extend EPC to other government buildings

Buildings• All new government buildings to adopt energy efficient design• Retrofit 100 government buildings• Register 70 energy service companies (ESCOs)• Target 100 companies to implement ISO 5000113• Introduce enhanced time of use (EToU) with three different time zones• Abolish the Special Industrial Tariff (SIT)

Industries• Install 4 million smart meters• Increase on-grid cogeneration capacity of 100 MW or more by reviewing utility
standby charges

Households

Additional appliances with minimum energy performance standards (MEPSs) andlabelling program

Source: EPU (2015)

A notable highlight in the Eleventh Malaysia Plan is the initiative to retrofit government buildings. The
pilot programs in EPU and Ministry of Finance buildings has reduced electricity use ranging from 16% to19%, equivalent around USD 5 200 (RM21 000) to USD 32 000 (RM130 000) monthly savings. In addition,
the Malaysian Government intends to implement smart grid systems for the electricity industry byintroducing smart meters. This move will help customers to manage their electricity supply more effectively.
By 2020, a total of 4 million smart meters will be installed by the utility companies at an estimated cost of
RM 4 billion. The smart grid is expected to benefit customers by enabling them to obtain information on
their electricity usage.

13 ISO 50001 is a voluntary international standard to provide organisations with a recognised framework in order tomanage and improve their energy performance.

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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 period (2010–15), focus was given to implementing greenhouse gas (GHG) mitigation measures. Among the measures
undertaken was the introduction of the RE Act in 2011, and the implementation of the feed-in tariff (FiT)
mechanism. Sustainable Energy Development Authority (SEDA), an organisation established by thegovernment in order to promote RE, set a target of 415.5 MW of additional RE capacity by 2015. However,
the total installed capacity of RE was 332.76 MW in 2015 (EPU, 2015). As at the end of 2015, cumulative
RE installed capacities under the FiT that achieved commercial operation was 332.76 MW, of which biomass
was 74.9 MW, biogas 18.23 MW, small hydro 18.3 MW and solar PV 221.33 MW (SEDA, 2015)
The government identified challenges which 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 in orderto develop RE installations. Current RE sources focus on biomass, biogas, mini hydro and solar photovoltaic(PV), while new RE sources have not been explored extensively.
Under the Eleventh Malaysia Plan, the government has set a target for RE capacity to reach 2 080 MW,
thereby contributing 7.8% of total installed capacity in Peninsular Malaysia and Sabah. Strategies have also
been identified to boost RE capacity. For example, studies will be conducted to identify new RE sources
such as wind, geothermal and ocean energy in order to diversify the power generation mix. Currently, thenational wind mapping exercise is underway and is expected to be completed by 2016. The exercise will
provide data for a study on the feasibility of developing wind energy. Geothermal potential will also be
explored following the discovery of a 12 km2 geothermal field in Sabah. Further, the viability of ocean energy
will be considered in order to take advantage of the sea, which surrounds Malaysia.
In order 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 andencourage more RE generation by prioritising internal consumption before any excess electricity generated
is fed to the grid. NEM is anticipated to encourage manufacturing facilities and the public to generate
electricity without any restriction on their generation capacity. This will further assist the government’s effort
to increase the contribution of RE in the generation mix.
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.
This is 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.
At the 2015 United Nations Climate Change Conference in Paris, Malaysia’s prime minister made apledge to reduce by 45% the GHG emissions intensity of the economy’s GDP by 2030 relative to theemissions intensity of GDP in 2005. The 45% figure consists of 35% on an unconditional basis and a further
10% conditional upon receipt of climate finance, technology transfer and capacity building from developed
countries (UNFCCC, 2015). The sectors which will be covered under this emission intensity reduction target
are energy; industrial processes; waste; agriculture; and land use, land use change and forestry (LULUCF).
There are two significant policies approved in 2009 that support this goal: the National GreenTechnology Policy and the National Climate Change Policy. These policies strengthen the national agenda
on environmental protection and conservation. The National Climate Change Policy has three main
objectives. First, to mainstream measures to address climate change through the efficient management of
resources and enhanced environmental conservation, resulting in strengthened economic competitivenessand improved quality of life. Second, the integration of responses into national policies, plans and programsin order to strengthen the resilience of development from arising and potential impacts of climate change.
Third, strengthening institutional and implementation capacity in order to harness opportunities to reduce
the negative impacts of climate change 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.
In order to reduce the economy’s carbon footprint, development work will focus on creating green markets,
increasing the share of renewables in the energy mix, enhancing DSM, encouraging low-carbon mobility andmanaging waste holistically (EPU, 2015).

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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
NEW ENHANCED DISPATCH ARRANGEMENT (NEDA) LAUNCHED TO ENCOURAGE
HEALTHY COMPETITION IN THE POWER SECTOR

The Energy Commission, the power sector’s regulator for Peninsular Malaysia and Sabah, launched the newenhanced dispatch arrangement (NEDA) mechanism in order to create healthy competition among IPPs.
The mechanism, which came into effect in October 2015, is expected to result in savings in electricity
production costs, which is intended to benefit consumers in the long run. Under the new mechanism, IPPs
whose power purchase agreements (PPAs) have expired or will be expiring can apply for an operating licence
to enable them to continue generating electricity for sale to utility companies. The NEDA will allow these
IPPs to bid on the basis of their variable costs (fuel cost and operation and maintenance costs) rather thanthose stated in the PPAs. This can help enable Malaysia to embark on an open and competitive power market.
The mechanism is planned to be fully implemented by the first quarter of 2016 (EC, 2015b).
INTRODUCTION OF INCENTIVE-BASED REGULATION IN THE GAS SUPPLY SECTOR

Incentive-based regulation (IBR) is a form of economic regulation aimed at incentivising utility companies
in order to improve operational and financial performance, while simultaneously regulating the natural gas
tariff. IBR supports the liberalisation of the natural gas industry, which is gradually aligning current piped
gas towards market prices. In this regard, the introduction of IBR promotes the efficient allocation and usageof resources, and sustainable financial performance. There will be a trial period for IBR in 2016, following
which the first regulatory period will run from 2017 until 2019. IBR is expected to promote a cost-efficienttariff structure for customers (Gas Malaysia, 2015b)
PENGERANG INTEGRATED PETROLEUM COMPLEX (PIPC)The PIPC was declared a National Project of Strategic Importance during the Economic Council Meetingin February 2012 and was chaired by the Malaysian prime minister. The PIPC is being developed as part of
the Economic Transformation Program in order to establish a dynamic oil and gas downstream industry.
The project is located on a single plot of land (approximately 8 100 hectares) in Pengerang, Johor at thesouth-eastern tip of Peninsular Malaysia. This is strategically accessible to major international shipping lanes.
In order to manage and administer efficiently the different projects within the PIPC, a new federal
government agency has been created—the Johor Petroleum Development Corporation (JPDC).
The PIPC will house oil refineries, naphtha crackers, petrochemical plants, and LNG regasification
terminal. As of January 2013, two projects have been committed to the PIPC area. The first is the Pengerang
Independent Deepwater Petroleum Terminal (PIDPT), a deepwater oil terminal that is expected to becompleted by 2020 with planned total storage capacity of 5 million cubic metres. Oil refineries in PIPC will
be value added in order to import crude oil through PIDPT. Another project is PETRONAS’s Refinery andPetrochemical Integrated Development (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 whichmeets European specifications (MPRC, 2013)
In April 2014, as part of the final investment decision (FID), PETRONAS announced the developmentof the PIPC with a total investment of USD 27 billion inclusive of RAPID’s development and other facilities(PETRONAS, 2014a).
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. It is intended that the project will be completed in Q1
2019 and that commercial operations will begin in Q2 (Platts, 2015b).
ELEVENTH MALAYSIA PLAN (2016–20)

As aforementioned, in May 2015, the government launched the Eleventh Malaysia Plan 2016–20 as the final
stage in Malaysia’s journey towards realising Vision 2020, a long-term development plan launched in 1991,
which envisions Malaysia to be 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 in order to support economic expansion, both of which have
implications for energy initiatives. The Eleventh Malaysia Plan is a mid-term (five-year) national development
plan that supports the long-term (20 years) plan. The First Malaysia Plan started in 1966 and the Eleventh
Malaysia Plan will take effect in 2016 (EPU, 2015).
Under the Eleventh Malaysia Plan, two strategy papers, Climate Resilience Development and Energy,
were introduced. Among the ways forward which are outlined under the Climate Resilience Development
strategy paper are strengthening and enabling the environment, strengthening resilience against climatechange and natural disasters, and harnessing economic value through sustainable consumption and
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production practices. Two energy sectors are affected by this strategy paper. They are DSM and RE. With
regard to the Energy strategy paper, the way forward is divided into four categories, namely the overall energy
sector, the oil and gas subsector, the electricity subsector and DSM (EPU, 2015).
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APERC (Asia Pacific Energy Research Centre) (2014), Peer Review on Low Carbon Energy Policies (PRLCE) in
Malaysia, May 2014,
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EC (Energy Commission of Malaysia) (2013), National Energy Balance 2012,
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–– (2014b), Peninsular Malaysia Electricity Supply Industry Outlook 2014,
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–– (2015b), ST Introduces NEDA to Ensure Cost Effective Power Generation,www.st.gov.my/images/highlight/2015/media%20release-NEDA.pdf.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
EIA (US Energy Information Agency) (2014), Malaysia Country Analysis Brief, September 2014,www.eia.gov/beta/international/analysis_includes/countries_long/Malaysia/malaysia.pdf.
EPU (Economic Planning Unit) (2010), Tenth Malaysia Plan 2011–2015,
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–– (2013), Malaysian Economy in Figures 2013, www.epu.gov.my/documents/10124/1e9cd2e5-67a8-4b6cb530-b1448a6a1475.
–– (2015), Eleventh Malaysia Plan 2016–2020, http://rmk11.epu.gov.my/book/eng/Elevent-MalaysiaPlan/index.html.
Gas Malaysia (2015a), website ‘Peninsular Gas Utilisation Project’ page,www.gasmalaysia.com/index.php/gas-fundamentals/peninsular-gas-utilisation-project.
–– (2015b), Gas Malaysia to Implement Incentive-based Regulation Framework Effective 1 January 2016,www.gasmalaysia.com/images/download/bursaannouncements/2015/october/OTHERS_22%20Oct2015.pdf.
GreenTechMalaysia (Green Technology Corporation) (2016), Statistics (accessed on 20 January 2016),
https://www.gtfs.my/
HAPUA (Head of ASEAN Power Utilities/Authorities Council) (2013), Malaysia Country Report,
www.hapuasecretariat.org/doc2013/Country_Reports/05_Malaysia_Country_Paper_HAPUA_2013.
pdf.
–– (2015), APG 16 Project as of May 2015,
http://www.hapuasecretariat.org/#
IEA (International Energy Agency) (2014), Key World Energy Statistics 2014,
https://www.iea.org/publications/freepublications/publication/KeyWorld2014.pdf.
IGU (International Gas Union) (2015), World LNG Report—2015 Editionwww.igu.org/sites/default/files/node-page-field_file/IGU-World%20LNG%20Report2015%20Edition.pdf.
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INPEX Corporation (2015), INPEX Discovers Oil in Deepwater Block R Offshore East Malaysia,
www.inpex.co.jp/english/news/pdf/2015/e20150407.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_i
d=92#.VEih1fmUeNg.
–– (2015), National Energy Policy 1979,
www.kettha.gov.my/portal/index.php?r=kandungan/index&menu1_id=2&menu2_id=26&menu3_id=110#.
MATRADE (Malaysia External Trade Development Corporation) (2015), Top 10 Major Export Products,
2014, www.matrade.gov.my/en/malaysia-exporters-section/33-trade-statistics/3184-top-10-majorexport-products-2014.
MOF (Ministry of Finance) (2015), Economic Report 2013/2014,
www.treasury.gov.my/pdf/economy/er/1314/economy2014.pdf.
MPOC (Malaysia Palm Oil Council) (2015), Malaysian Palm Oil Industry,
http://www.mpoc.org.my/Malaysian_Palm_Oil_Industry.aspx
MPRC (Malaysia Petroleum Resources Corporation) (2013), Pengerang Integrated Petroleum Complex,
www.mprc.gov.my/our-businesses/pengerang-integrated-petroleum-complex-pipc
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-GASIFICATIONTERMINAL-REACHES-COMPLETION.aspx.
–– (2013a), ‘PETRONAS Celebrates 100 Active Production Sharing Contracts’, press release,
http://www.petronas.com.my/media-relations/media-releases/Pages/article/PETRONASCELEBRATES-100-ACTIVE-PRODUCTION-SHARING-CONTRACTS.aspx–– (2013b), ‘Balai Oil Field Commences Production’, press release, http://www.petronas.com.my/mediarelations/media-releases/Pages/article/BALAI-OIL-FIELD-COMMENCES-PRODUCTION.aspx–– (2014a), ‘PETRONAS Reaches Final Investment Decision for Pengerang Integrated Complex’, press
release, www.petronas.com.my/media-relations/media-releases/Pages/article/PETRONASREACHES-FINAL-INVESTMENT-DECISION-FOR-PENGERANG-INTEGRATEDCOMPLEX.aspx.
–– (2014b), ‘Kapal, Banang and Meranti Cluster Achieves another Significant Milestone’, press release,
http://www.petronas.com.my/media-relations/media-releases/Pages/article/KAPAL,-BANANGAND-MERANTI-CLUSTER-ACHIEVES--ANOTHER-SIGNIFICANT-MILESTONE.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.
SEB (Sarawak Energy Berhad) (2015), Power Across Borders,www.sarawakenergynewsroom.com/2015/03/18/power-across-borders/. SEDA (Sustainable
Energy Development Authority) (2011), National Renewable Energy Policy and Action Plan
http://seda.gov.my/gohome.php?omaneg=00010100000001010101000100001000000010100001000110&id=263.
–– (2015) FiT Dashboard – RE Capacity (data accessed on 20 January 2016),
http://seda.gov.my/
UNFCCC (United Nations Framework Convention on Climate Change) (2015), Intended Nationally
Determined Contributions (Malaysia),
www4.unfccc.int/submissions/INDC/Published%20Documents/Malaysia/1/INDC%20Malaysia%
20Final%2027%20November%202015.pdf.
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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.
USEFUL LINKS

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
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.my
Tenaga Nasional Berhad—www.tnb.com.my121

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M E XI C OMEXICOI N T ROD U C T I ON

Mexico, officially known as the United Mexican States (Estados Unidos Mexicanos in Spanish), is a North
American federal republic bordered 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 a Latin American economy, although its geographical location andeconomic integration are in North America.
Mexico is rich in biodiversity, with abundant fossil and renewable energy resources across its land areaof approximately 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, mild temperatures in the centre and a warm coast. The total population of Mexico by mid2014 was more than 125 million (World Bank, 2015). Mexico City is the political capital of the economy andis considered one of the largest urban centres in the world. It is home to more than 20 million people, withnine million living in Mexico’s federal district and more than 11 million in the 60 surrounding municipalities
in the states of Mexico and Hidalgo (INEGI, 2013). After Mexico City, the other most important cities ofthe economy are Guadalajara and Monterrey, which are located in the west-central and north-eastern sidesof 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 into Mexico, making it one of thelargest developing economies with a robust manufacturing industry. Despite these milestones, the growthof the Mexican economy between 2000 and 2013 has been modest, rising little more than 2% annually, withthe real GDP in 2013 reaching USD 1 900 billion (2010 USD purchasing power parity [PPP]) (EGEDA,
2015). The accomplishment of significant political, economic and energy reforms, was expected to underpin
a more robust economy, but partly due to the prevalent environment of low oil prices since 2014, the GDP
grew only 1.4% from 2012 to 2013. Despite the expectations and efforts in the last decade to create astronger economy, the growth of Mexico’s GDP on a per capita basis is meagre, with an annual rate lower
than 0.7% from 2000 to 2013 and nearly zero from 2012 to 2013 (EGEDA, 2015). In addition, by the endof 2014, around 46% of the Mexican population was deemed to live under poverty conditions, with thisshare being roughly the same as in 2010 and 2012 (CONEVAL, 2015).
Energy, particularly oil, is a central component of the Mexican economy, and is poised to become
more relevant through the structural changes approved in 2013. In 2014, the value of crude oil exports
represented 13% of Mexico’s total exports in the same year, yet they provided 31% of the government’s
total revenue, from which social development is funded (Banxico, 2015).
Table 1: Key data and economic profile, 2013
Key dataa, bEnergy reservesc, dArea (million km2)

2.0

Oil (billion barrels)

11

Population (million)

125

Gas (billion cubic metres)348

GDP (2010 USD billion PPP)

1 900

Coal (billion tonnes)

1.2

GDP (2010 USD PPP per capita)

15 355

Uranium (kilotonnes U)

2.9

Sources: a. World Bank (2015); b. EGEDA (2015); c. BP (2015); d. NEA (2014).

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E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

By the end of 2013, the net primary energy supply of Mexico amounted to more than 193 500 kilotonnes ofoil equivalent (ktoe), an increase of 2.3% over 2012. Fossil fuels constituted 90% of the primary energy
supply of the economy, with other non-fossil sources such as nuclear and renewable energy constituting theremaining 10% (EGEDA, 2015). An economy endowed with abundant fossil and renewable energy
resources, by the end of 2014, Mexico held proven reserves of fossil fuels amounting to 11 billion barrelsof crude oil, 348 billion cubic meters (bcm) of natural gas and 1.2 billion tonnes of coal. In terms of the sizeof the crude oil, natural gas and coal reserves, Mexico was ranked eighteenth, thirty-third and twenty-first in
the world, respectively, as well as the fifth, tenth and eighth in APEC, respectively (BP, 2015).
Mexico is a major oil producer, and by the end of 2014, it produced 2.4 million barrels per day(Mbbl/D) of crude oil, mostly the heavy type. This volume was 3.7% lower than that of the previous year,
mostly due to the decline in several major fields. In particular, Mexico faces the challenge of replacing theoutput 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 rapidly since then. By the end of 2014, Cantarell produced less than 0.4 million barrels,
representing only 15% of the economy-wide production (PEMEX, 2014). Consequently, in the last few
years, the biggest oil company in Mexico, Petróleos Mexicanos (PEMEX), has focused its strategy on the
discovery and development of new oil fields that can offset the natural decline of its major assets. Mexico isa net crude oil exporter with around half of its total indigenous crude oil production being exported,
especially to the US, making Mexico the third-largest oil supplier to that economy in 2014, after Canada andSaudi Arabia (EIA, 2015). Despite its robust production of crude oil and a domestic distillation capacity of
1.7 Mbbl/D in six refineries located across its territory, Mexico is a net importer of oil-based products,
especially gasoline.
As shown in Table 1, the proven natural gas reserves of the economy at the end of 2014 totalled 348
bcm, with production in the same year reaching 0.2 billion cubic metres per day (bcm/d), of which almost
three-quarters were associated with the production of crude oil. As a net natural gas importer, Mexico has
looked forward to boosting its domestic gas resources, including the development of its unconventional
resources such as shale gas. Nevertheless, the challenges in the early shale gas development in Mexico alongwith a rapidly growing demand in the industry due to the availability of cost-competitive natural gas flows
from the US have favoured a rising volume of imports and have prevented a more accelerated domestic gas
production.
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

218 104 Industry sector

34 724 Total

297 079

Net imports and others-21 228 Transport sector

51 125

Thermal245 594

Total primary energy supply

193 635 Other sectors

26 692Hydro

28 002

Coal

12 682 Non-energy

5 640

Nuclear

11 800Oil

98 863 Total final energy consumption 118 181

Gas

61 794

Coal

5 173

Others11 683

Others20 297

Oil

72 350Gas

12 131

Electricity and others

28 527

Source: EGEDA (2015).

By the end of 2014, the contribution of domestic gas production to the natural gas supply in Mexico
amounted to 63%, much lower than the 2007 level at 81%. Out of the 37% of the natural gas supply
provided by imports by the end of 2014, approximately 25% was from pipeline imports and 12% from
LNG. As a reference, in 2007, these sources represented 15% and 5% of the economy-wide natural gas
supply, respectively (CRE, 2015; SIE, 2015). Mexico has three LNG regasification terminals, two in its
Pacific Coast in Ensenada (in Baja California State) and one in Manzanillo (in Colima State). Anotherterminal is located in Altamira (the State of Tamaulipas) in its Atlantic Coast, facing the Gulf of Mexico.
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COALIn comparison to most other economies, coal is not as widely used in the primary energy supply of theeconomy, as it represented less than 7% of the total supply in 2013, equivalent to 12 682 ktoe (EGEDA,
2015). Most of Mexico’s recoverable coal reserves of 1.2 billion tonnes are located in the Coahuila State in
the north-eastern part of its territory, with some significant additional resources in the states of Chihuahua
and Sonora in the north-west, and Oaxaca in the south.
ELECTRICITYElectricity generation in Mexico amounted to more than 300 Gigawatt-hour (GWh) in 2013, mostly derived
from thermal power plants (EGEDA, 2015) largely fuelled by natural gas. Mexico’s electricity system is welldeveloped and comprises a main grid spread across most of its territory as well as two other grids in thenorth and south of its Baja California Peninsula. The interconnection between the main and north Baja
California grids is planned to be functional by 2018. It is expected to underpin the optimisation of
infrastructure and energy sources across the Mexican territory (CFE, 2014), and could have deeper effects
on the entire system’s configuration in the long term.
In 2014, the total installed power capacity was above 65 300 megawatts (MW), of which 54 375 MW
were used for public service. This installed capacity represented an increase of 936 MW over the 2013 level.
The bulk of the electricity generation infrastructure has been developed by the Comisión Federal deElectricidad (CFE), Mexico’s state-owned and largest utility, although the number of private generators has
also grown over the last two decades. Both for public service sales and different self uses, the capacity heldby the private sector represented approximately 37% of the economy-wide installed electricity generation
capacity in 2014 (SENER, 2015f). CFE and private generators alike predominantly rely on combined cycle
technologies fuelled by natural gas, although the use of renewable energy, particularly wind energy, hasgrown robustly in recent years.
FINAL ENERGY CONSUMPTION

In 2013, total final energy consumption in Mexico reached 118 181 ktoe, a slight increase of 1% from 2012.
By energy source, oil-based products accounted for 61%; electricity and others 24%; natural gas 10% andcoal 1.5% (EGEDA, 2015). This structure remained very similar to that of the previous year. By use, thebulk of the final energy consumption in 2012 was in the transport sector (43%), industry sector (29%), andthe residential, commercial and agriculture sectors together (23%).
ENERGY INTENSITY ANALYSIS

In the last decades, Mexico has undertaken several initiatives to improve its energy efficiency, with acumulative positive effect on its energy intensity levels. As shown in Table 3, from 2012 to 2013, the energy
intensity worsened by less than 1% when assessed by the economy-wide primary energy demand; althoughfrom a final energy basis it made a slight improvement. All final energy sectors reported improvements intheir respective energy intensities, with the exception of the industry sector, which has experienced an
unprecedented energy demand surge due to the availability of inexpensive gas imported from the US.
Consistent with the aspirations of APEC on energy intensity, the advance of the 2013 figures over those of2005 amounted to improvements of 6.1% on a primary energy supply basis and 7% for the final energy
demand, which confirm Mexico’s decreasing energy intensity trend.

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M E XI C OTable 3: Energy intensity analysis, 2013
EnergyChange (%)

Energy intensity (toe/million USD)
2012

2013

2012 vs 2013

Total primary energy supply

101

102

0.9

Total final energy consumption

62.4

62.2

–0.4

Industry

16

18

13

Transportation

28

27

–3.8

Other sectors

14.3

14.0

–1.9

Non-energy

4

3

–26

Source: EGEDA (2015).
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

Mexico’s energy policy is led by the Ministry of Energy (Secretaría de Energía, or SENER), which is requiredby law to develop an Energy Sector Program with the main energy goals and strategies to be enforced at the
beginning of every six-year presidential term. The current Energy Sector Program, in force until 2018, set
several short and medium-term actions to remove the hurdles towards ensuring a more vigorous energy
supply, to promote the development of energy infrastructure, and foster the efficiency and modernisationof regulatory institutions and state-owned companies. In alignment with these objectives, the milestonereform passed in 2013 introduced a new structure and institutional arrangement for the Mexican energy
sector.
SENER is strengthened as the strategist of the economy-wide policies on the subject. In the oil andgas industry, it adjudicates oil assignments to PEMEX and awards permits related to oil and natural gas
processing. Regarding exploration and production activities, SENER selects the areas to tender and designs
the technical guidelines to observe. The Ministry of Finance determines the fiscal and economic terms foroil and gas exploration and production contracts, while the National Hydrocarbons Commission (CNH)awards these contracts and authorises the working plans originating from them.
The reform reaffirmed the state ownership of all hydrocarbons in the subsoil while introducing morecompetition in the energy sector. To that end, and to foster larger investment inflows into the sector, in
addition to the status given to the state-owned companies as state productive enterprises to become morecompetitive, private companies are now allowed to participate across the entire value chain of the oil andgas industry. In the electricity industry, with the exception of nuclear energy, private parties can participate
in electricity generation and marketing activities under state regulation. Concerning transmission anddistribution, private parties may participate under contract with the Federal Electricity Commission, which
will be restructured with more transparent rules.
To strengthen the regulation of the energy sector, regulators had their mandates expanded in order toaddress the upcoming industry challenges more effectively. The CNH and the Energy Regulatory
Commission (CRE) became coordinated regulatory organisations with their own legal personality, technicaland management autonomy, and budgetary self-sufficiency. To ensure that assignments and contracts
granted to public and private enterprises contribute to the economy-wide industry, legislation will be
required to establish minimal percentages of domestic content. Private investment must promote theinclusion and development of domestic and local suppliers in the value chain of the entire industry.
To enhance transparency, several mechanisms include external audits and citizens’ participation withthe aim of verifying the payments made to companies. To facilitate the understanding of the new institutionalarrangement of Mexico’s public energy sector, and its areas of influence, a schematic representation is shownin Figure 1.

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Figure 1: Current institutional arrangement of Mexico’s public energy sector
LegalstatusAreas of influence
Oil

Gas

Electricity

Nuclear Energy

Energy Efficiency

SENER

Sector HeadCNSNSCONUEE

CRE*

Ministry’s
Deconcentrated
Entities

Regulatory
bodies

CNH**

PEMEX

CENAGAS

IMP

State Productive
Enterprises

CFE

Independent
Transmission
Operators

CENACE

ININ***

IIE

TechnologicalResearch
Institutions* 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.
*** Stemmed from the Energy Transition Law, ININ has six months starting from December 2015 to transform into
the National Institute for Electricity and Clean Energy.
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; IIE:
Electricity Research Institute; ININ: National Institute for Nuclear Research.
Source: APERC analysis.
OIL AND GASWith the reform enacted, Mexico can conduct hydrocarbon exploration and extraction activities throughassignments and contracts with PEMEX, private operators or both parties in association. Four types ofcombinable contracts for hydrocarbons are established: services, profit sharing, production sharing andlicenses. In particular, the last three will allow the transfer of the geological and financial risks involved in
the exploration and extraction activities, to contractors. To preserve PEMEX’s assets and value creation inthis new institutional arrangement, it was provided with a Round Zero, a new tax regime and best corporate
governance practices.
In terms of regulation, with its new capacities, the CNH aims to perform public biddings onhydrocarbons, determine winners and administer the incumbent contracts. The CNH is also responsible forthe quantification of Mexico’s oil and gas potential and geological records; for the announcement, tenderingand signing of exploration and production contracts, and overseeing the technical issues related to all thepermits awarded to maximise the economy’s rent perceived for its hydrocarbons. Consistent with thecompetition introduced, a National Centre for Natural Gas Control (CENAGAS) was created to administer,
coordinate and manage the pipeline grid and the storage of natural gas efficiently and independently.
CENAGAS is intended to act as an independent transmission operator.
The Mexican Fund of Petroleum for Stabilisation and Development is responsible for safeguarding,managing and distributing the revenues derived from hydrocarbons-related assignments and contracts, withthe exception of taxes. The Fund is constituted as a trust within Mexico’s Central Bank, with a technicalcommittee comprising four independent board members and three members from the state.
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ELECTRICITY

Since 1992, the private sector has participated in the electricity generation in Mexico, due to the industry’s
partial liberalisation at the time that allowed private companies to generate electricity, provided that theirpower was either sold to CFE or used for own purposes (self-supply). However, the 2013 Energy Reform
stresses the need to expand generation and retail segments so that CFE becomes more competitive and isable to regain major customers. Therefore, private generators will eventually participate along with CFE toserve medium-sized customers under a more competitive market.
As this Energy Reform retains state control over transmission and distribution activities, it is expectedthat CFE’s efforts to undertake the expansion and operation of Mexico’s transmission and distribution lines
will be strengthened with the aid of private companies that will enhance investment flows and market
technologies. The CRE now has its own legal personality, as well as technical and management autonomy,
and budgetary self-sufficiency to carry out its duties more effectively. These duties span the regulation of
the electricity industry, as well as the storage, transport and distribution of oil products through pipelines.
Finally, the National Centre for Energy Control (CENACE) has been withdrawn from CFE to become apublic decentralised entity responsible for operating the government’s power system and the wholesale
power market to ensure open and non-discriminatory access to the government’s transmission anddistribution grids.
NUCLEAR ENERGY

Mexico is experienced in the development of nuclear energy to generate electricity, with the only plant with
two nuclear reactors (Laguna Verde) being operated by CFE since 1990. Mexico has not explicitly ruled out
any nuclear development plans, but neither has its government clearly signalled any possible expansion of
the current capacity. Furthermore, even with the changes introduced to promote the participation of private
generators, nuclear energy development remained reserved to the Mexican State, most likely through CFE.
ENERGY EFFICIENCY

Mexico has organised energy efficiency programs since 1989. The institution in charge of promoting these
programs and providing technical advice is the National Commission for Efficient Energy Use (CONUEE).
Energy efficiency actions are framed by the National Programme on the Sustainable Use of Energy 2014–
18. The Programme was jointly created by SENER and CONUEE, with several objectives that include thedesign of programs and actions conducive to an optimal energy use across the energy sector; an effective
regulation of energy-based equipment and devices made and/or marketed in Mexico; and a strengthened
governance of energy efficiency systems at the federal, state and municipal levels including public, social,private and academic entities.
RENEWABLE ENERGY

To achieve the goal of reducing the dependency on fossil fuels while integrating sustainability principles into
the energy policy framework, a legal reform in 2008 allowed the development of new policy and regulatory
instruments that would promote the introduction and growth of renewable energy, biofuels and research
activities.
In 2008, the Mexican Government passed its Law for the Use of Renewable Energy and Financing ofEnergy Transition to reduce the dominance of fossil fuels in the economy-wide electricity mix throughrenewable and environmentally sustainable energy solutions. To that end, the Law mandated the maximum
share of fossil energy in Mexico’s total electricity generation at 65% by 2024, 60% by 2035 and 50% by 2050.
This Law was overridden by the Law for Energy Transition passed in December 2015. Nevertheless, thegoals were largely preserved, mandating the minimum share of economy-wide electricity generation basedon clean energy (renewables and nuclear) constituting 25% by 2018, 30% by 2021 and 35% by 2024.
These goals are also aligned with the guidelines of Mexico’s Law for Climate, which establishes anaspirational goal of at least 35% of the economy-wide electricity generation based on sources other thanfossil fuels and nuclear energy by 2024.
ENVIRONMENTAL SUSTAINABILITY

Mexico made significant efforts to decrease the carbon intensity of its economic development, despite its
emissions representing only 1.4% of the worldwide total (UNFCC, 2015). Mexico is one of the economies
most devoted to address climate change, having issued its first specific strategy in 2000 and becoming thefirst developing economy to have a law dedicated exclusively to this subject, issued in 2012. Since then,numerous other policies on emissions mitigation and adaptation to climate change have been implemented,
with several focusing on the energy sector and its most energy-intensive industrial processes. The energy
sector is the largest source of emissions, and according to the most recent official records, it accounts for127

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82% of the CO2 and 67% of the greenhouse gases (GHGs) emitted in Mexico during 2010 (SEMARNAT,2013).
With the structural changes achieved, the Mexican State promotes actions that protect the environment
through lower carbon intensity in its domestic energy demand and supply, as well as the reduction ofpolluting emissions from the electricity industry. Consistent with Mexico’s cross-sectorial public policies,
environmental sustainability is a major component of the economy’s energy planning.
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
Program for Climate Change 2014–18. The Program contains 38 action lines oriented to the adaptation andmitigation of climate change, from which eight have specific goals. According to the Program, the energy
sector’s impact on climate change is considerable, as it accounts for 61% of the mitigation commitments
established.
Additionally, the energy reform mandate to establish an agency responsible for industrial safety andenvironmental protection in the oil and gas industry resulted in the Agency of Security, Energy andEnvironment (ASEA), an organisation with technical and management autonomy, attached to the Federal
Ministry of Environment. 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 and abandonment of wells and facilities; and control of polluting emissions and waste. In doing so,
the Agency looks forward to complying with domestic and international technical standards.
RESEARCH AND DEVELOPMENTSENER, through its Vice-Ministry for Energy Planning and Transition, is responsible for fostering researchand development (R&D) policies, which are predominantly carried out by three public research bodies, as
explained in Figure 1. The Mexican Petroleum Institute supports the hydrocarbons sector; the Electricity
Research Institute supports electric power and the National Institute for Nuclear Research supports nuclearbased applications for electricity generation and other peaceful 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 andthe Trust Fund for Energy Sustainability. These trust funds are financed by fee payments collected fromPEMEX Exploration and Production as required by the National Income Law. Further, they are oriented
to fund scientific and applied research projects, as well as supporting the adoption, innovation, assimilationof technological development and training of specialised human resources.
While the Trust Fund for Hydrocarbons is oriented towards upstream and downstream hydrocarbon
activities, including basic petrochemicals, the Trust Fund for Energy Sustainability supports clean
technologies, diversification of energy sources, renewable energy sources and energy efficiency. The
objectives and budgetary resources of these Trust Funds have supported the creation of several centres toenhance Mexico’s research and training on their respective areas of influence. The Centre for Training in
Development Processes and the Centre for Deep Water Technologies stem from the Trust Fund for
Hydrocarbons, while five Mexican Centres for Innovation stem from the Trust Fund for Energy
Sustainability. Each of these fives centres is specialised in bioenergy, wind energy, geothermal energy, wave
energy and solar energy.
In addition, the Trust Fund for Energy Transition and Sustainable Use, which is financed through thefederal budget, aims to promote the use of renewable energy and energy efficiency. To that end, this TrustFund supports public research projects oriented towards the diversification of primary energy use and energy
savings in industrial and domestic activities.
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

As part of the energy reform, a ʻRound Zero’ mechanism was included, whereby PEMEX requested toretain certain strategic oil and gas assets prior to any public tenders for private competitors. The aim of thismechanism was to provide PEMEX a competitive advantage in the face of the increased competition. The
Round Zero resulted in PEMEX retaining 83% of the proven and probable reserves in Mexico and 21% of
the prospective oil and gas resources.
A subsequent ‘Round One’ followed Round Zero, to offer the oil and gas resources to privatecompanies in a series of consecutive tenders (Ronda Uno, 2015).
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M E XI C OBy December 2014, SENER announced the first tender (Licitación 1—Aguas Someras—
Exploración) for the exploration of several blocks in shallow waters in front of the Mexican statesof Veracruz, Tabasco and Campeche under a regime of production sharing contracts.



By February 2015, a second tender was opened for the development of hydrocarbons in five blocksof shallow waters in the states of Tabasco and Campeche (Licitación 2—Aguas Someras—
Extracción), again under a regime of production sharing contracts.



The third tender for 2015 was opened in May, targeting the development of hydrocarbons in 25
onshore blocks bordering the Gulf of Mexico (Licitación 3—Terrestre—Extracción), this time
under a licence regime.

Shortly after these tenders were announced, SENER released its five-year plan for the exploration andproduction of hydrocarbons. According to this plan, up to 2019, the Mexican Government expects to tender379 blocks for the exploration of conventional hydrocarbons, 291 for the exploration of unconventionalhydrocarbons, and 244 for production. The amount of oil and gas for each of these activities was estimatedat 15, 25 and 68 billion barrels of oil equivalent, respectively (SENER, 2015e).


The results of the oil and gas tenders were announced during the second half of 2015.
o In the first tender, out of the 14 blocks tendered, only two were awarded.
o In the second tender, three out of five blocks were awarded.
o The results for the third tender were announced in December 2015, with all 25 blocks awarded.

In the midst of a continued environment of low crude oil prices that posed major financial andoperational challenges, by December 2015, PEMEX announced that during that year, it had completed 30
exploratory wells with a commercial success of 45%, which resulted in several discoveries adding 1 billion
barrels of oil equivalent of possible (3P) reserves. Approximately 57% of these reserves are light crude oiland condensate, 20% heavy oil and 23% non-associated gas (PEMEX, 2015).
In order to guide the private investments in the downstream segment, SENER released the Five-year
Plan on Natural Gas Pipelines in October 2015. The plan considers the development of 13 projects spanning
12 pipeline systems and 1 compression station. These projects involve 5 000 km of additional gas pipelines,
with investments estimated at USD 10 billion (SENER, 2015c).
ELECTRICITY

Up to the first half of 2015, multiple projects were finished or commissioned to keep up with the rising
electricity demand in Mexico. Three power plants (Los Azufres III Phase I Geothermal, CC andCogeneration Salamanca Phase I, and Sureste Wind Energy Phase II) were built, adding a capacity of 529
MW with capital investments worth USD 514 million. Other major electricity projects for public service
were either completed or were in progress under different financing mechanisms. These included theupgrade and maintenance of three power plants for USD 839 million as well as several substations andtransmission lines projects (SENER, 2015f).
It is also worth noting that the electricity sector has been the major driver for natural gas demand in
Mexico, and as this trend continues, several gas pipeline systems were finished or commissioned tostrengthen the transmission and supply of natural gas for electricity generation plants across the Mexican
territory, particularly its northern and central parts. In June 2015, SENER and CFE announced the tenderof 24 projects for electricity and gas infrastructure. These projects are expected to add more than 2 300 km
to the economy-wide gas pipeline system and more than 3 000 circuit-kilometres, and involve investmentsof around USD 9.8 million (SENER, 2015a).
In September 2015, SENER released the Electricity Market Guidelines (Bases del Mercado Eléctrico)for explaining and disseminating the premises for the design and operation of the electricity industry under
the changes brought about with the 2013 reform. This instrument recognises the wholesale market figures,
which include generators, marketers, transmission and distribution operators, retailers and final consumers.
It also establishes the tradability of several products beyond electricity, such as effective capacity, clean
energy certificates, auxiliary services and financial rights on transmission.
ENERGY EFFICIENCY

Mexico was able to save more than 5 700 GWh of energy during the first half of 2015 due to several
efficiency programs, with many of them being implemented since a long time, including norms andstandards in the energy end-use sectors (industrial, residential and commercial), savings on facilities ownedby the federal government, public lighting and daylight savings (Horario de Verano) (SENER, 2015f).
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In January 2015, the Mexican Government issued the Energy Efficiency Guidelines for the Federal
Administration, and in March, CONUEE published specific administrative directions aiming to foster apermanent process of energy efficiency improvement in the buildings, vehicle fleets and industrial facilitiesof the federal government. These instruments clarify the energy savings criteria applicable to the projects,
acquisitions, works and services used or contracted by the federal government. During 2015, the federal
government continued implementing initiatives and programs related to the dissemination and training onenergy savings and efficiency measures at the federal, state and local levels, and across the end-use economic
sectors, mostly through CONUEE.
RENEWABLE ENERGY

Due to its favourable geophysical conditions, Mexico has a promising potential for renewable energy
development. The economy has promoted more intensively the development of renewable technologies for
power generation, cogeneration and biofuels. By the end of 2014, Mexico’s proven annual potential ofrenewable energy amounted to 1 932 GWh of geothermal, 4 457 GWh of hydro, 15 307 GWh of wind, 8
171 GWh of solar and 728 GWh of biomass (SENER, 2015b). This combined potential is 60% higher than
Mexico’s current electricity generated from renewable energy.
In June 2015, SENER granted 13 geothermal exploration permits to CFE to support a more advanced
use of this energy source in the economy’s electricity mix, and in November, the first concession wasawarded to a private company. This concession is expected to add between 25 to 50 MW of installed capacity
and significant capital investments. In order to provide electricity to 33 rural communities in several states
through a microgrid of solar photovoltaic panels, the Integral Energy Services Project under the guidanceof CFE continued to benefit 7 400 people. The project ceased operations in October 2015.
Regarding biofuels, in October 2015, a tender was announced for acquiring ethanol for a maximum
volume of 2.2 billion litres over 10 years, which is expected to create a relevant opportunity for the
production of this additive at a large scale from biomass sources. Up to June 2015, there were 20 permits
for its commercialisation and 18 special permits for its small-scale production and storage.
ENVIRONMENTAL SUSTAINABILITY

SENER issued the requirements for acquiring clean energy certificates up to 2018, which fundamentally
mandates those users with an intensive use of electric power to prove that at least 5% of their demandcomes from clean energy sources, starting from 2018. In March 2015, Mexico submitted its Intended
Nationally Determined Contribution (INDC), committing for an unconditional reduction of 22% of its
GHG emissions by 2030 in comparison with its Business-as-Usual Scenario 2013 baseline. On a conditional
basis, this share might increase to 36% if certain global measures to address climate change are in place(UNFCC, 2015).
In October 2015, PEMEX, along with other nine major oil companies, participated in the Oil and Gas
Climate Initiative and in preparation for the COP21 in Paris to discuss global actions on climate change.
They declared their collective commitment to support an effective climate change agreement by contributing
to decrease the environmental footprint in their operations. In the midst of the COP21, the Mexican
Congress hastened the work towards the approval of the long-delayed Law of Energy Transition. Onceapproved, this law will pave the way towards a more effective energy transition in Mexico, by streamlining
and enforcing several mechanisms to make operational the targets to promote a cleaner electricity
generation. Combining prior legal instruments, the Law establishes a rapid decoupling from the use of fossil
fuels, as it mandates a minimum goal of clean energy in Mexico’s total electricity generation at 25% by 2018,
30% by 2021 and 35% by 2024.
INTERNATIONAL COOPERATION

Given the momentum instilled by its energy reform, Mexico was particularly active during 2015 in several
international energy events other than APEC.
In compliance with the international policy established by its Ministry of Foreign Affairs, during 2015
SENER promoted bilateral strategic cooperation initiatives with several economies, across diverse energy
topics. These economies were Belize, Cuba, the Dominican Republic, Guatemala, the US and Venezuela in
the Americas; Denmark, Germany, the Netherlands and Norway in Europe; India and Japan in Asia; andQatar and South Africa.
On a multilateral level, Mexico participated in and led several dialogues, mainly through SENER. This
collaboration included several multilateral organisations, including the United Nations, the International
Atomic Energy Agency (IAEA), the Nuclear Energy Agency (NEA), the International Energy Agency(IEA), the International Renewable Energy Agency (IRENA), the International Energy Forum, the Energy
and Climate Partnership of the Americas, the Clean Energy Ministerial, the G20 and the Extractive
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M E XI C OIndustries Transparency Initiative being among the most important. The following are the other major
accomplishments during 2015 (SENER, 2015d):In late May, Mexico hosted several major energy events in its southern city of Mérida, in the Stateof Yucatán.
oMexico hosted the Second Ministerial Meeting of the Energy Climate and Partnership of theAmericas (ECPA). During the event, the Energy Ministers of Chile, Colombia, Costa Rica,
Mexico, Peru, Panama and the US announced the creation of a new initiative of the Western
Hemisphere to promote clean energy.
 Within this event, the Energy Ministers of Canada, Mexico and the US also establisheda trilateral Working Group on Energy and Climate, which supports the implementationof the clean energy and climate change goals of these three economies, in terms of the
dialogues in the North American Leaders 2014 Summit, which called for clean andreliable energy supplies to foster economic growth with a low-carbon intensity.

oMexico also hosted the Sixth Clean Energy Ministerial Meeting (CEM6), which contributed
to reach international agreements to implement energy saving measures in electricity systems
and strengthen the cooperation towards a more accelerated energy transition and use of clean
energy sources.

oWithin these events in the city of Mérida, the Mexican Federal Government and the IRENA
released the report ‘Renewable Energy Prospects’, which analyses the economy’s renewableenergy potential and its role to promote an energy mix less concentrated on the use of fossil
fuels. The report highlights that under a Business-As-Usual (BAU) scenario, the share of
renewable energy in Mexico’s final energy consumption would barely amount to 10% by 2030
(IRENA, 2015).

Consistent with the precepts of the energy reform to bolster the transparency and accountability
in the energy sector, particularly under the current institutional arrangement in which both private
and public investments are allowed, in June 2015, the Mexican Government formed an interministerial working group responsible for advancing the economy’s adherence to the Extractive
Industries Governance Initiative (EITI).

In November, the Mexican Government submitted a request to become a member of the IEA. If
accepted, Mexico would be the first Latin American economy to join this organisation.
REFERENCES

Banxico (Banco de México) (2015), Estadísticas, www.banxico.org.mx/estadisticas/index.html.
BP (2015), BP Statistical Review of World Energy, www.bp.com
CFE (Comisión Federal de Electricidad) (2014), Programa de Obras e Inversiones del Sector Eléctrico POISE
2014-2028, Mexico City: Comisión Federal de Electricidad.
CONEVAL (Consejo Nacional de Evaluación de la Política de Desarrollo Social) (2015), Medición de laPobreza, www.coneval.gob.mx/Medicion/MP/Paginas/Pobreza_2014.aspx.
CRE (Comisión Reguladora de Energía) (2015), Gas natural - Tablas de Importaciones,
www.cre.gob.mx/documento/2261.xlsx．
EGEDA (Energy Statistics & Training Office, Asia Pacific Energy Research Centre, The Institute ofEnergy Economics, Japan) (2015), APEC Energy Statistics 2013 and the APEC Energy Database,www.ieej.or.jp/egeda/database/database-top.html/.
EIA (Energy Information Administration) (2015), U.S. Imports by Country of Origin,www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_ep00_im0_mbblpd_a.htm.
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=Pr
od&ef=&f=2&cl=0&tg=80&pg=0&ct=106020000/.
IRENA (International Renewable Energy Agency) (2015), Renewable Energy Prospects: Mexico,
www.irena.org/menu/index.aspx?mnu=Subcat&PriMenuID=36&CatID=141&SubcatID=598.
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NEA (Nuclear Energy Agency) (2014), Uranium 2014: Resources, Production and Demand, www.oecdnea.org/ndd/pubs/2014/7209-uranium-2014.pdf.
PEMEX (Petróleos Mexicanos) (2014), Anuario Estadístico 2014, www.pemex.com.
–– (2015). Informa Pemex Sobre sus Resultados de Operación en 2015,
www.pemex.com/saladeprensa/boletines_nacionales/Paginas/2015-119-nacional.aspx.
Ronda Uno (2015), http://ronda1.gob.mx.
SEMARNAT (Secretaría de Medio Ambiente y Recursos Naturales) (2013), Informes del Inventario Nacionalde Emisiones de Gases de Efecto Invernadero 1990-2010.
SENER (Secretaría de Energía) (2015a), Anuncia la CFE Licitaciones de 24 Proyectos de Infraestructura Eléctrica yTransporte de Gas Natural, www.gob.mx/sener/prensa/anuncia-la-cfe-licitaciones-de-24-proyectos-deinfraestructura-electrica-y-transporte-de-gas-natural/.
–– (2015b), Inventario Nacional de Energías Renovables, http://inere.energia.gob.mx/.
–– (2015c), Plan Quinquenal de Expansión del Sistema de Transporte y Almacenamiento Nacional Integrado de Gas
Natural 2015-2019. http://www.gob.mx/sener/acciones-y-programas/plan-quinquenal-de-gasnatural-2015-2019–– (2015d), Prensa, www.gob.mx/sener/archivo/prensa.
–– (2015e), Programa Quinquenal de Licitaciones Para la Exploración y Extracción de Hidrocarburos 2015-2019．
Septiembre 2015. http://www.gob.mx/sener/acciones-y-programas/plan-quinquenal-delicitaciones-para-la-exploracion-y-extraccion-de-hidrocarburos-2015-2019-7652–– (2015f), Tercer Informe de Labores 2013-2015,www.gob.mx/cms/uploads/attachment/file/25591/3erInformeLabores.pdf.
SIE (Sistema de Información Energética) (2015), http://sie.energia.gob.mx.
The World Bank (2015), Population Total, http://data.worldbank.org/indicator/SP.POP.TOTL.
UNFCC (United Nations Framework Convention on Climate Change) (2015), INDCs as Communicated byParties [Online], www4.unfccc.int/submissions/indc/Submission%20Pages/submissions.aspx.
USEFUL 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—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
Ronda Uno—http://ronda1.gob.mx
Secretaría de Energía (SENER)—www.gob.mx/sener
Secretaría de Hacienda y Crédito Público (SHCP)—www.gob.mx/hacienda132

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M E XI C OSecretaría del Medio Ambiente y Recursos Naturales (SEMARNAT)—www. gob.mx/semarnat
Sistema de Información Energética (SIE)—http://sie.energia.gob.mx

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N E W Z E A L AN D

NEW ZEALANDINTRODUCTION
New Zealand is an island economy in the South Pacific, comprising the North Island, South Island andnumerous outer islands. While its land area is between that of Japan and the United Kingdom, its low
population of about 4.4 million is comparable to a medium-sized Asian city. Due to its remote location,
New Zealand has no electricity or pipeline connections to other economies. New Zealand has a matureeconomy with a per capita gross domestic product (GDP) of about USD 32 526 (2010 USD purchasing
power parity [PPP]) in 2013.
New Zealand is self-sufficient in all energy forms except oil. It has a vast renewable energy potential,
which in 2013 accounted for 74% of electricity generation, largely from hydro, geothermal and wind. For
fossil energy resources, the proven and probable (2P) reserves are more modest, including: 128 million
barrels (Mbbl) of oil and liquefied petroleum gas (LPG), 56 billion cubic meters (bcm) of natural gas and571 million tonnes of coal at the end of 2014 (BP, 2013; MBIE, 2015).
Table 1: Key data and economic profile, 2013
Key dataa, bEnergy reserves b, c, dArea (km2)

269 652

Oil (million barrels)

128

Population (million)

4.4

Gas (billion cubic metres)56

GDP (2010 USD billion PPP)

144

Coal (million tonnes)

571

GDP (2010 USD PPP per capita)

32 526

Uranium (kilotonnes U)–

Sources: a. Statistics New Zealand (2014); b. EGEDA (2015); c. MBIE (2015); d. BP (2013).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

In 2013, New Zealand’s total primary energy supply (TPES) was 19 178 kilotonnes of oil equivalent (ktoe).
Oil was the major contributor (33%), followed by geothermal, wind, solar and others (21%); gas (21%);hydro (10%); coal (8%) and biomass, biogas, waste heat, and others providing the remaining (7%). It is worth
noting that geothermal electricity generation has an efficiency of 13% in New Zealand (MBIE, 2015). As
such, the geothermal share of the total final energy demand (TFED) is significantly smaller than its primaryenergy supply share. New Zealand’s energy self-sufficiency (indigenous production/primary energy supply)in 2013 was 83%, same as that in 2012, but significantly lower than in 2011 (88%), due to the waning of oil
production in recent years. Since 2000, growth in New Zealand’s primary energy supply has been modest,
increasing at an average annual rate of 1% (EGEDA, 2015).
Coal is New Zealand’s most abundant fossil energy resource, predominantly available in the form oflower value lignite. However, almost all coal production comprises sub-bituminous and bituminous coals.
In 2013, coal production decreased by 5% on an energy-equivalent basis compared with 2012 as domestic
producers competed with cheap imports from Asia (EGEDA, 2015).
Oil is sourced from 19 fields in the Taranaki region in the North Island (MBIE, 2015). The productionof crude oil, natural gas liquids and condensate was down by 13% on an energy-equivalent basis in 2013
compared with 2012. Oil production peaked in 2008 underpinned by the coming on-stream of the newest
fields Pohokura, Kupe, Tui and Maari, and from the 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 at New Zealand’s only
refinery at Marsden Point and importing refined oil products. New Zealand is a net importer of oil, withindigenous production accounting for around 30% of the domestic oil demand in 2013.
Natural gas is sourced from 18 fields currently in production (MBIE, 2013). In 2013, natural gas
production increased by 6% compared with 2012 (EGEDA, 2015). The largest uses for gas are industrial
heat, electricity generation and in methanol and urea production. All the gas produced in New Zealand is134

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domestically consumed since there are no liquefied natural gas (LNG) terminals. In 2013, there was asignificant increase in gas and LPG remaining reserves (by 31%), with the reassessment of the reserves in
the Pohokura, Maui and Mangahewa fields contributing most of to this increase. In 2012, Methanex, which
produces methanol with natural gas as feedstock, signed a 10-year gas supply agreement with the Mangahewa
field operator.
New Zealand has a large renewable energy potential primarily in the form of hydro, geothermal andwind primarily. Currently the use of this potential is restricted to electricity generation (as explained below).
However, 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 biofuels production is being examined as
this technology advances. Finally, solar is also an area of future development as technology advances andbecomes cheaper for deployment and grid integration.
In 2013, New Zealand generated 43 256 gigawatt-hours (GWh) of electricity, a slight decrease from2012 (EGEDA, 2015). Hydro is the major source of electricity generation, accounting for 54% of total
generation in 2013. Hydro production is affected by climatic conditions that influence the amount of rainfall
to supply the hydro dams. Geothermal generation accounted for 14% (MBIE, 2015). More than two-thirds
of New Zealand’s hydroelectricity is generated in the South Island, while all the geothermal electricity is
generated in the North Island. It is worth noting that while most hydro generation is in the south island, themain sources of load are in the North Island, requiring significant investment in the inter-island link.
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

15 870 Industry sector

4 095 Total

43 256

Net imports and others

4 619 Transport sector

4 584

Thermal

11 101

Total primary energy supply

19 178 Other sectors

3 375

Hydro

23 044Coal

1 558 Non-energy

1 174

Nuclear–Oil

6 387 Total final energy consumption

13 228Others

9 111

Gas

3 980

Coal

620

Others

7 253

Oil

5 930

Gas

2 160

Electricity and others

4 517

Source: (EGEDA, 2015).
FINAL ENERGY CONSUMPTION

In 2013, New Zealand’s total final energy consumption was 13 228 ktoe, just over 2% higher than in 2012.
The transport sector consumed 35% of the final energy, while the industry sector consumed 31% the othersector 26% (which includes residential, commercial and agriculture), and the remaining 8.9% was used for
non-energy purposes. The final energy consumption was dominated by oil, accounting for 5 930 ktoe (45%),
followed by electricity and others (mainly biomass) at 4 517 ktoe (34%), gas at 2 160 ktoe (16%) and coal at
620 ktoe (5%) (EGEDA, 2015).
Industrial energy demand has been relatively flat in recent years at or near 4 000 ktoe for over 10 years,
as industry demand is dominated by a small number of large consumers, including: one aluminium smelting
plant, one steel mill, one oil refinery, two methanol plants, two cement plants, several pulp and paper mills,
and a very large dairy company with several plants. Each of these consumers has a unique consumption
profile, for example, the aluminium smelter uses around 15% of electricity demand, the methanol plants
consume 29% of natural gas supply as a feedstock, and the pulp and paper industry meets up to half of its
energy needs from wood and wood waste.
Transport energy demand has also remained relatively flat and is dominated by road transport in theform of the light passenger vehicle fleet with significant contributions from heavy freight transport, and airtransport, while rail and water transport have relatively small shares of consumption. As the fleet gradually
improves its efficiency, the savings are offset by an increase in vehicle numbers resulting in stable demand.

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The transport sector is the main consumer of petroleum products, accounting for 77% of domestic
oil consumption in 2013. Consumption of oil products in the other sectors was shared between industry(13%) and residential, commercial, and agricultural (10%), (EGEDA, 2015).
Energy demand in the others sector is also flat since 2000. In this case, a slowly decreasing population
coupled with improving efficiency counteract each other resulting in a flat demand.
ENERGY INTENSITY ANALYSISNew Zealand’s energy intensity of primary energy in 2013 was 133 tonnes of oil equivalent per million
USD (toe/million USD), a decrease of 2.5% from 136 toe/million USD in 2012. This is partly due to astable demand in the previous year while GDP grew by nearly 2.5%. Final energy consumption intensity
remained flat at 92 toe/million USD. The energy intensity of the industry sector increased by 0.6%, whilethat of the transport and other sectors, which includes the commercial and residential sectors, decreased by
1.5% and 3.9%, respectively.
Table 3: Energy intensity analysis, 2013
EnergyEnergy Intensity (toe/million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

136

133

–2.5

Total final energy consumption

91.8

91.6

–0.2

Industry

28.2

28.3

0.6

Transportation

32.2

31.7

–1.5

Others sector

24

23

–3.9

Non-energy

7.1

8.1

15

Source: EGEDA (2015).
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 it reports to the Minister of Energy
and Resources.
New Zealand’s oil and gas exploration and production activities are privately owned and open tocompetition. It welcomes investment in oil and gas exploration by foreign firms. 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 is also open to competition, although three of the five companies
that dominate the market are state-owned. During 2013 and 2014, the government privatised 49% of thethree remaining state-owned electricity generators, themselves retaining a controlling stake while enabling
private investment in the sector. Transpower is the transmission grid owner and operator, a state-owned
enterprise. The New Zealand Electricity Authority oversees the conduct of the electricity market, but does
not regulate electricity prices.
The coal mining industry in New Zealand is dominated by Solid Energy, a state-owned firm, with over
80% production in 2014 (MBIE, 2015). Several smaller private operators make up the remaining coal mining
industry.
In August 2011, the government released New Zealand’s current overarching energy policy framework,
the New Zealand Energy Strategy 2011–21: Developing Our Energy Potential (the Energy Strategy) (MBIE,
2012) to replace the 2007 New Zealand Energy Strategy. The new strategy focuses on four priorities: diverse
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resource development; environmental responsibility; efficient use of energy; and secure and affordable
energy. The Energy Strategy includes the New Zealand Energy Efficiency and Conservation Strategy 2011–
16 (NZEECS), which replaces the 2007 version.
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 aimed to improve 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 weredismantled by separating the natural monopoly and competitive elements; the former government-owned
and operated electricity and gas monopolies were either corporatized or privatised; and the electricity market
was deregulated.
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 streamlining 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 the management of supply emergencies.
The Electricity Industry Act 2010 has several provisions to promote competition. These include
provisions for swapping assets between the three state-owned electricity-generating companies to betteralign the generation assets of each firm with their market presence, a fund to encourage customers to switch
electricity providers and better electricity market hedging arrangements. The Act also has provisions toimprove the security of supply. These include rule changes to ensure that electricity retailers do not profit
from supply emergencies, and the requirement that a state-owned reserve power station, criticised for
distorting market incentives, be privatized so that it could 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 (Harris, 2004).
The New Zealand Petroleum & Minerals (NZP&M) business unit within the MBIE manages the New
Zealand Government’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, coaland mineral resources, consistent with the government’s objectives for energy and economic growth. Its role
is to efficiently allocate rights to prospect for, explore for and mine Crown-owned minerals, effective
management and regulation of these rights and ensuring a fair financial return to the Crown for its minerals.
NZP&M is also instrumental in promoting investment in the mineral estate. It replaces the former Crown
Minerals Group. The Resource Markets Policy team of the Resources, Energy and Communication Branchof 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 from 1 April 2011 (Inland Revenue, 2012).
Corporations are also required to pay other indirect taxes such as payroll tax and fringe benefits tax.
For petroleum production, companies must pay an ad valorem royalty of 5% (i.e. 5% of the net
revenues obtained from the sale of petroleum) or an accounting profits royalty of 20% (i.e. 20% of theaccounting profit of petroleum production), whichever is greater in any given year. For discoveries madebetween 30 June 2004 and 31 December 2009, an ad valorem royalty of 1% is applied to natural gas, or an

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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 will depend on when the initial permit
was awarded. For initial permits awarded between 1991 and 2008, an ad valorem royalty of 1% of the net
sales revenue is payable on the net sales revenue between NZD 100 000 and NZD one million. For
producers with net sales revenues exceeding NZD one million, the royalty payable is either 1% of the net
sales revenue or 5% of 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 hardand 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 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 resources potential, but is considered underexplored (Samuelson
2008, Section 5.3). Responding to this challenge, the government has developed an action plan for realising
the potential of New Zealand’s petroleum resources. The Action Plan for the Development of Petroleum
Resources, released in November 2009, aims to ensure that New Zealand is considered an attractive
destination for investment in petroleum exploration and production. The plan is based on several work
streams, including:

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

Investing in data acquisition to improve resource knowledge and foster more investment,
particularly in frontier resources;

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 explorationrights. 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 to develop them. The goal of this change is to attract significant
additional investment to New Zealand while providing the government with more control overwhere, 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. The RMA specifies that the guiding principle of decision-making is sustainable
management (MFE, 2014).
In December 2008, in response to concerns about the slow and costly consenting process under the
RMA, the government reviewed the RMA process. A major criticism of the RMA had been that decisionmaking was generally delegated to local governments, where local interests can take precedence overeconomy-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 of national significanceand to support the boards of inquiry (or the Environment Court) in making decisions regarding these
proposals (MFE, 2014).
The Resource Management (Simplification and Streamlining) Amendment Act 2009 also includes
provisions to streamline the consenting process. These provisions make it more difficult for competitors tochallenge a resource consent application, impose stricter deadlines for decisions by local governments andmake procedural changes.
There are also provisions for more effective enforcement and tougher penalties for non-compliance(MFE, 2014). An ongoing Phase 2 Review of the RMA takes on the more complex tasks of better aligning
the RMA with other environmental laws and exploring better approaches to urban planning and water
management (MFE, 2014).

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Further changes to the RMA have been proposed that will build on previous amendments, but may
also include more widespread changes primarily designed to address housing affordability concerns.


In response to the Deepwater Horizon massive oil spill incident in the Gulf of Mexico in June 2010,
the government initiated a review of offshore petroleum health, safety and environmental (HSE)
legislation. Consequently, in December of that year, the Comparative Review of Health, Safety andEnvironmental Legislation for Offshore Petroleum Operations Report was released. The reportconcluded that New Zealand’s HSE arrangements for offshore petroleum operations in New
Zealand do incorporate several key characteristics of international best practices but there are areas
for improvement in the regulatory framework (MED, 2010).

Responding to the recommendations of the review, in 2012 the government passed the Exclusive
Economic Zone and Continental Shelf (Environmental Effects) Act 2012. Currently, the RMA
regulates operations in New Zealand’s Exclusive Economic Zone (EEZ) up to 12 miles at sea, but
beyond 12 miles many activities have historically been unregulated. This legislation makes the EPA
responsible for the consenting, monitoring and enforcement of activities in the EEZ that have an
impact on the environment, including petroleum exploration and marine energy development(NZG, 2011a).



Since the EEZ Act came into force on 28 June 2013, the EPA has received six marine consent
applications: four for discretionary activities (seabed mining and petroleum development drilling)
and two for non-notified discretionary activities (petroleum exploration drilling).

Some stakeholders have raised concerns about these early experiences, particularly about whether
the consenting regime allows for an appropriate balance between managing environmental effects
in the EEZ and maximising economic opportunities. The government is currently considering theseconcerns.
ENERGY EFFICIENCYNew Zealand has been promoting 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 theestablishment of the Energy Efficiency and Conservation Authority (EECA) to spearhead the strategy’s
implementation (EECA, 2012a).
In August 2011, the government released the New Zealand Energy Efficiency and Conservation
Strategy 2011–16 (NZEECS) to replace the 2007 strategy. The overall goal of the new strategy is for New
Zealand to continue to improve its energy intensity (energy used per unit of GDP) by 1.3% per year to 2016.
In addition, New Zealand is part of the voluntary APEC-wide target to reduce energy intensity by 45%
from its 2005 levels, by 2035 (APEC, 2012).
Some of New Zealand’s major policies for promoting energy efficiency are as follows.


In transport, the key policy is fuel efficiency labelling for light vehicles but there is also a programfor driver education in the heavy transport sector, and a general support for the electrification oftransport. In 2014, New Zealand also launched a tyre-labelling program to promote low rolling
resistance tyres, which increase vehicle fuel economy.



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 buildings, a subsidy program to insulate approximately 188 500 homes (over 10% of the housing
stock) concluded in 2013 and a follow-up smaller program targeting at-risk households began in
2014. New residential buildings must meet tougher insulation standards last updated in 2007. 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(MBIE, 2012).

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RENEWABLE ENERGYNew Zealand is well endowed with hydro, geothermal, wind, biomass and, potentially, ocean energy. So
much so that all current wind and geothermal capacity was developed without subsidies. Although the stateowned electricity generating companies have played a major role in the development of these resources, they
are required to operate as commercial businesses and must compete with private generators (The Treasury,2011). As part of the Energy Strategy, the New Zealand Government set a target of generating 90% of its
electricity from renewable sources by 2025, provided security of supply is maintained. The major instrument
to achieve this goal is the Emissions Trading Scheme, discussed in Climate Change (MBIE, 2012).
Hydro has historically been New Zealand’s major source of renewable energy. However, the majorityof favourable hydro sites have already been developed, and there is a strong social opposition to furtherhydro developments, thus New Zealand has been focusing on geothermal and wind. Several major renewablegeneration capacity projects have been consented in recent years but have not been developed due to lower
than expected electricity demand. In effect, the next 20 years of the new demand have already been consented
and is mostly wind and geothermal electricity.
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).
In the transport sector, a grant of up to 42.5 cents per litre for biodiesel producers ended on 30 June2012 with very low uptake during its three-year period (EECA, 2012b). In order to promote biofuels, thegovernment is now supporting research, development and demonstration for advanced biofuels projects (i.e.
from woody biomass).
Electric and plug-in hybrid electric light vehicles (EVs and PHEVs) are also considered an option toincrease renewables in transport, not just as a form of demand but also as a source of storage for intermittent
renewable electricity generation. In order to stimulate EVs and PHEVs, they have been exempted from roaduser taxes until 2020, which for the average user equates to a saving of around NZD 700 per year (NZG,
2011b; MT, 2015). For more information, see the Energy Wise website: www.energywise.govt.nz/yourvehicle/electric-vehicles/regulations.
NUCLEAR ENERGY

Nuclear energy is not legal in New Zealand and there are no plans to revisit this stance in the foreseeable
future.
CLIMATE CHANGE

The New Zealand Government supports climate change action and has several policies and initiatives tothis effect. The government has adopted a domestic economy-wide target for a 50% emissions reduction in
New Zealand’s carbon-equivalent net emissions, compared with the 1990 levels, by 2050. Further, for thelatest Intended Nationally Determined Contribution (INDC), New Zealand adopted a 30% emissions
reduction compared to 2005.
The key climate change intervention is the Climate Change Response (Emissions Trading)Amendment Act of 2008 that established New Zealand’s emissions trading scheme. The scheme places aprice on greenhouse gas emissions to provide an incentive to reduce the volume of overall emissions. The
scheme includes all sectors of the economy and the six gases covered under the Kyoto Protocol under thescheme—carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur
hexafluoride (CCINZ, 2012). However, the entry of the agriculture sector has been delayed indefinitely until
there are realistic options for the sector to curb its emissions (Table 4).
The scheme has been in effect since 2008 and was amended in 2009 and 2011. After the amendment,
generous free emissions permits were allocated to export-exposed industries in order to preserve
international competitiveness. However, the generous grandfathering, the lack of an overall cap, and a twofor-one permit surrendering deal put a downward pressure on the price of carbon, which remained underNZD 5 during 2013, limiting its impact on emission.
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
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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).
Table 4: Timeframe for entry into the emissions trading scheme
SectorVoluntary Reporting

Mandatory Reporting

Forestry

Full Obligations
1 January 2008

Liquid fuels (including transport)

1 January 2010

1 July 2010

Stationary energy (including
electricity, coal, gas, geothermal)

1 January 2010

1 July 2010

Industrial processes

1 January 2010

1 July 2010

Synthetic gases

1 January 2011

1 January 2012

1 January 2013

Waste

1 January 2011

1 January 2012

1 January 2013

Agriculture

1 January 2011

1 January 2012

No date set

Source: CCINZ (2013).
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 process is expected to raise as much as NZD six toseven billion, which has been reserved for reinvestment in education and infrastructure (FT, 2013).
The electricity sector is grappling with uncertainty in both the demand side from large industrial
electric consumers and the 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 output by half and there are concerns about the profitability of the Tiwai
Point Aluminium Smelter (TPAS), which accounts for about 14% of New Zealand’s total electricity demand.
The New Zealand Government supplied a short-term NZD 30 million one-off subsidy to ensure the plantcontinues 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.
In the supply side, the recent 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 pressurising the grid and market
operators to ensure security of supply during dry climate periods when hydro generation will be constrained(NBR, 2015). This may spur the development of some of the currently shelved projects, but currently the
major players want more security before investing. 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 bothcompleted in 2014.
Another development includes the deployment of smart metering devices throughout the market. To
date, approximately 1.2 million meters have been replaced out of around 2.1 million (EA, 2015). The key
driver resides in operational savings for electricity retailers in terms of not having to employ meter readersand control of certain processes remotely. The newly formed Smart Grid Forum, however, believes that
there is potential to expand benefits into streamlining the market, energy efficiency technologies adoption,and greater adoption of renewables, among others (MBIE, 2014b).
NEW PROJECTSIn 2015, no new generation projects were under construction. There are, however, several large-scale wind,geothermal and hydro projects that have regulatory and environmental consent to proceed. However, all thelarge utility companies have stated that they are unlikely to develop any new large-scale projects 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 longterm than seen historically.

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The New Zealand grid system operator Transpower, in the past few years, completed several essential
major upgrade projects to maintain grid security and keep up with the demand. These include: theNZD 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 the oil and gas industry, the government continues to offer blocks for exploration and the industry
is spending around NZD 300 million in multiple sites to explore further resources. However, at present, nosignificant funds are being developed for production.
In transport, Z Energy is currently building New Zealand’s largest biofuel plant with a capacity of 20
million litres per year. It is expected to be operational in early 2016 (Z Energy, 2015). In addition, a
consortium led by Z Energy and partly funded by the government is investigating the large-scale productionof next-generation biofuels from domestically grown timber.
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BP (2014), Statistical Review of World Energy 2014, www.bp.com/statisticalreview.
CCINZ (Climate Change Information New Zealand) (2012), Emissions Trading Scheme Basics,
www.climatechange.govt.nz/emissions-trading-scheme/basics.html/.
——(2013), About Obligations, www.climatechange.govt.nz/emissions-trading-scheme/obligations/.
EA (Electricity Authority) (2015), Electricity Market Information website ʻRetail Dashboardsʼ page,
http://www.emi.ea.govt.nz/Reports/Dashboard?reportName=BZTDDC&categoryName=Retail&r
eportDisplayContext=Dashboard
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FL (Frazer Lindstrom) (2012), New Zealand Emissions Trading Scheme (NZETS),
www.frazerlindstrom.com/nzets.htm.
FT (Financial Times) (2013), ʻNZ Finance Minister Bullish on Privatisation Schedule after Mighty River
Saleʼ, 14 May 2013, www.ft.com/cms/s/2/2c882f9a-bca4-11e2-951900144feab7de.html#axzz2jvxgUbMo/.
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/.
MED (Ministry of Economic Development) (2009), Improving Electricity Market Performance Discussion
Document, www.med.govt.nz/sectors-industries/energy/pdf-docs-library/electricity142

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market/implementing-the-electricity-market-review-recommendations/background-papers-on-2009review/improving-electricity-market-performance-volume-one-discussion-document-1152-kbpdf.pdf/.
–– (2010), Comparative Review of Health, Safety and Environmental Legislation for Offshore Petroleum Operations,www.med.govt.nz/sectors-industries/natural-resources/pdf-docs-library/oil-and-gas/offshorepetroleum-hse-legislation-review/offshore-petroleum-final-report-and-annexures.pdf/.
–– (2014), Gas Governance, www.med.govt.nz/sectors-industries/energy/gas-market/governance-of-thegas-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.
–– (2014), The Resource Management Act, www.mfe.govt.nz/rma.
MT (Ministry of Transport) (2015), Exemption for Light Electric Vehicles from Road User Charges,
www.transport.govt.nz/land/roadusercharges/vehiclesexemptfrompayingrucqandas/.
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,
www.nzpam.govt.nz/cms/about-nzpam/rules-and-regulations.
Ralph Samuelson (2008), Oil: An Introduction for New Zealanders, Ministry of Economic Development.
www.med.govt.nz/sectors-industries/energy/energy-modelling/publications/oil-an-introductionfor-new-zealanders.
Rob Harris (2004), Handbook of Environmental Law, Royal Forest and Bird Protection Society of New
Zealand, Wellington.
Statistics New Zealand (2014), New Zealand in Profile: 2014,www.stats.govt.nz/browse_for_stats/snapshots-of-nz/nz-in-profile-2014.aspx/.
The Treasury (2011), State-Owned Enterprises, www.treasury.govt.nz/statesector/soes/.
Transpower (2015), Major Projects, www.gridnewzealand.co.nz/projects/.
Z Energy (2015), Z Bio D biodiesel, http://z.co.nz/keeping-business-on-the-move/fuels/z-biodiesel/

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N E W Z E A L AN DUSEFUL 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)—www.med.govt.nz
New Zealand Government (portal for access to New Zealand government agencies and governmentfunded 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

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P 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 located in the south-west part of the Pacific Ocean, just south of the equator.
It comprises more than 600 islands, including the eastern half of New Guinea—the world’s second-largest
island—as well as the Bismarck Archipelago, D’Entrecasteaux island group and the three islands of theLouisiade Archipelago. The mainland and the larger islands are mountainous and rugged, with a string ofactive volcanoes dotting the northern part of the mainland and continuing to the island of New Britain.
PNG has a population of more than seven million, spread across a total area of 462 840 square kilometres(km2). The natural resource extraction industry, which includes minerals, oil and gas, contributes toapproximately 80% of PNG’s export income (MRA, 2012).
In 2013, PNGʼs real gross domestic product (GDP) was estimated at USD 18.4 billion (2010 USD
purchasing power parity [PPP]), an increase of 5.5% from 2012.
Table 1: Key data and economic profile, 2013
Key dataa

Energy reservesb

Area (thousand km2)

463

Oil (million barrels)

175

Population (million)

7.3

Gas (billion cubic metres)155

GDP (2010 USD billion PPP)

18.4

Coal (million tonnes)－

GDP (2010 USD PPP per capita)

2 511

Uranium (kilotonnes U)－

Sources: a. EGEDA (2015); b. CIA (2015).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

In 2013, PNG’s net primary energy supply was 2 321 kilotonnes oil equivalent (ktoe), an increase of 6.6%
over the value in 2012. Of the total supply, light crude oil and petroleum products accounted for the largest
share (75%), followed by gas (5%) and hydro and other renewables contributed the remaining (19%)(EGEDA, 2015).
Production of crude oil in PNG started in 1992 and peaked at over 150 000 barrels per day (bbl/d)
the following year. Since then, production has declined to 34 000 bbl/d in 2014 (CIA, 2015), despite
exploration activities that resulted in the development of additional oilfields. At this rate, crude oil reserves
are expected to be depleted by 2026. Crude oil has been refined locally since the first refinery plant wascommissioned in 2004 (Napanapa Oil Refinery, owned by InterOil), which has a refining capacity of 33 000
bbl/d.
PNG remains underexplored and until recently, the natural gas resources have been undeveloped,
except for the Hides gas field, which provides 145–155 million cubic metres per year for power generation
to supply the Porgera Gold Mine in the central highlands of PNG. However, the PNG liquefied natural gas(LNG) project development was initiated in 2009 to develop these resources.
The PNG LNG Project is operated by Esso Highlands Limited (Company), a subsidiary of
Exxonmobil, and is a joint venture between Esso Highlands Limited and Oil Search Limited, Santos, AGL,JX Nippon Oil & Gas Exploration, Minerals Resources Development Company and Petromin PNG
Holdings Limited, as well as local landowners. It is a 6.9 million tonnes per annum integrated LNG projectsourced from the Hides, Angore and Juha fields, and from associated gas in the Kutubu, Agogo, Moran andGobe Main oil fields. The PNG LNG Project commenced production in April 2014 and the first LNG
deliveries began in May 2014 to Asian customers (PNG LNG, 2014).
In 2013, PNG generated 3 965 gigawatt-hours (GWh) of electricity, a 5.3% increase from 2012.
Thermal generation contributed the largest share (64%), followed by hydro (25%) and geothermal (11%)(EGEDA, 2015). The electricity system of PNG is characterised by numerous smaller regional or townsized generation and distribution network systems without a central transmission network connecting
generation and demand. The majority of these are small thermal generation systems, except three hydrolocations and two hybrid micro-hydro and diesel systems. Most thermal and hydro power stations are owned
and operated by PNG Power Limited (PPL), formerly the PNG Electricity Commission.
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PNG also has significant geothermal resources and the first plant was commissioned in April 2003. By
2007, the installed geothermal capacity was 56 megawatts (MW). The Geothermal Energy Association(GEA) estimated a potential 3 to 4 GW of geothermal potential which could, in theory, meet all its electricity
needs well into the future from geothermal sources alone (GEA, 2010).
In 2010, the International Renewable Energy Agency (IRENA) estimated that traditional biomass
accounted for over half of PNG’s energy consumption (IRENA, 2013). However, since there are no recent
surveys to track its use and it is not commercial in nature, its use is largely undocumented and therefore notincluded in the statistics below.
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Indigenous production

1 394 Industry sector

Net imports and others

879 Transport sector

Total primary energy supply
Coal
Oil

Power generation (GWh)
640 Total power generation

3 965

538

Thermal

2 546

2 321 Other sectors

257

Hydro

996

－ Non-energy－

Nuclear－

1 434

Others422

1 746 Total final energy consumption

Gas

127

Coal

－

Others

449

Oil

1 133

Gas

－

Electricity and others

302

Source: EGEDA (2015).
FINAL ENERGY CONSUMPTION

In 2013, total final energy consumption (TFEC) in PNG was 1 434 ktoe, an increase of 5.7% from 2012.
The industrial sector’s consumption witnessed an increase of 6.2% from 2012, and it was the largest end
user, accounting for 45% of the total, followed by the transport sector with 37%. The other sectors,
including agriculture and residential/commercial, constituted 18%. By energy source, petroleum products
accounted for 79% of the total consumption, while electricity and other sources accounted for 21%.
In PNG, although around 85% of the population lives in rural areas, electrification remains limited tothe main urban areas relying largely on traditional biomass to meet their energy needs. As such, the levels ofownership of electric domestic appliances is low (ADB, 2012) and likely to remain low until the wealth fromthe resource sector is translated into improved incomes for the population and infrastructure development.
In the 2014 Fifteen-Year Power Development Plan 2014–28, PPL highlights the government key
target to extend electricity access to 70% of the population by 2030 by extending generation capacity anddeveloping their transmission and distribution networks (PPL, 2014a). 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 a state of disrepair. Many locations can only be accessed
through coastal or river barges. As such, transport fuel demand will be hampered once road saturation levels
are reached. In 2013, transport demand grew by 6% from 2012 to a total of 538 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 the assistance of the World Bank, are continuously
extending their rural distribution networks throughout the economy, especially within the outskirts of urban
areas. PNG aims to increase electricity access to 41% of the population by 2020 and to 70% by 2030
(IRENA, 2013).
The industry sector is expected to show a high growth in consumption as the PNG LNG project
develops and commences operations. Given the scale of PNG’s economy and energy consumption, thisproject on its own will impact national level statistics. The remainder of the resource industry is currently
under pressure due to the low international prices for oil and minerals (ADB, 2015).
ENERGY 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 2013, however, was 127 tonnes of oil equivalent146

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per million USD (toe/million USD), a slight increase of 1% from 125 toe/million USD in 2012. The increaseis potentially due to the increased energy consumption in the industry sector from the LNG development.
The energy intensity of final energy demand was 78.2 toe/million USD in 2013. The energy intensityof the industry and transport sectors remained flat at 34.9 and 29.3 toe/million USD respectively. Regarding
the others sector, which includes commercial, residential and agriculture, the value decreased from 2012 by
1.8% to 14.0 toe/million USD.
Table 3: Energy intensity analysis, 2013
EnergyEnergy Intensity (toe/ million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

125

127

1.0

Total final energy consumption

78.1

78.2

0.1

Industry

34.7

34.9

0.6

Transportation

29.2

29.3

0.5

Other sectors

14.2

14.0

–1.8

Source: EGEDA (2015).
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

Papua New Guinea, or the Independent State of Papua New Guinea, is a constitutional, parliamentarydemocracy and a Commonwealth realm. Jurisdiction over energy matters is the responsibility of the PNG
Government’s Energy Division within the Department of Petroleum and Energy (DPE).
In 2010, the PNG Government initiated The National Strategic Plan 2010–50, also known as the PNG
Vision 2050 (PNG Government, 2010), their overarching development document. The plan has sevenpillars encompassing all areas of development with energy under the Environmental Sustainability andClimate Change pillar. The Wealth Creation, Natural Resources and Growth Nodes may also influenceenergy development as infrastructure develops and demand grows. The key energy-related objectives
included:Provide 100% electricity generation from renewable sources



Reduce greenhouse gas (GHG) emissions by 90% from 1990 levels

In March 2010, the PNG Government announced the Development Strategic Plan (DSP) 2010–30 in
response to the vision. The DSP 2010–30 also set this goal: All households should have access to a reliable
and affordable energy supply, and sufficient power should be generated and distributed to meet futureenergy requirements and demands (12% of households had access to electricity in 2010).
Since 2011, the Energy Division has authored several draft energy policies pursuant to the strategies
and objectives mentioned above. The key draft policies included the National Energy Policy, National
Energy Plan, Rural Electrification Policy and Strategy, Geothermal Policy, Renewable Energy Policy and theElectricity Industry Policy (IRENA, 2013). However, not all of them have been finalised and passed by thegovernment. The exploration and development of petroleum resources has also been authorised andadministered by the DPE.
In October 2010, the PNG Government announced its Medium-Term Development Plan (MTDP)
2011–15. The MTDP 2011–15 will focus on increasing access to electricity for all households in the member
economy government. New investments from the private sector in solar technology are also expected during
the period of the first MTDP. A comprehensive analysis will be necessary to analyse the cost effectivenessof the various alternative sources of power.
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, in order to achieve the targets indicated in thestrategy documents, the government will need a coordinated effort with private sector to develop theinfrastructure and generate demand, and source funding.
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ENERGY MARKETSPNG’s power authority, PPL, is responsible for generating, transmitting, distributing and retailing electricity
throughout PNG. Sections 21 and 23 of the Electricity Industry Act 2000 outline the functions and powersof PPL. Under the Act, PPL’s function is to plan and coordinate the supply of electricity throughout theeconomy, especially in urban areas.
The Act also authorised the Independent Consumer and Competition Commission (ICCC) as thetechnical regulator of the electricity and petroleum sector, determining standards, carrying out inspections
and controlling applications for all matters relating to the operations of electricity supply. The ICCC wasestablished in 2002 to oversee and regulate price and service standard issues relating to utilities such as PPL
and selected corporatized government statutory entities. This made it responsible for setting prices or tariffs
for electricity and petroleum products. PPL was also corporatised under the Electricity Commission(Privatisation) Act 2002.
Due to the lack of 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 under this contract (PPL, 2014b). PPL sold 1 023 GWh in 2014.
In the latest power development plan (PPL, 2014a), there are provisions for independent power
producers (IPPs) to enter the market and develop more competition.
FISCAL REGIME AND INVESTMENT

In September 2003, the PNG Government introduced special fiscal terms to provide incentives for oil andgas exploration in the economy. This was in response to a decline in investments in exploration, as well as
the prospect of declining oil production from the Kutubu, Gobe and Moran oilfields between 2003 and2010.
The special terms are known as ‘incentive rate petroleum operations’. They offer a revised income tax
rate of 30% of the taxable income, which is lower than the tax rate for income from petroleum projects
established before 1 January 2001 (50%), and that for projects established after that date (45%). The new
30% fiscal rate is available for petroleum operations that have a petroleum development licence granted onor before 31 December 2017, and a petroleum prospecting licence granted within the period of 1 January
2003 to 31 December 2007.
PNG has arguably the most competitive terms for oil and gas investment in the region. There is no
capital gains tax, and a full (100%) tax deduction is available for exploration expenditure. The PNG
Government’s equity is set at 20.5% and that of landowners at 2%. The effective royalty rate is 2%, of which
the government’s share is approximately 50% (Papua Petroleum Limited, 2008).
In 2015, the government started a review of the electricity tariff methodologies to improve thecompetitiveness of the electricity system.
Investment prospects in PNG are currently hampered by the low prices in the agricultural and natural
resources sectors. This is putting pressure on the government’s ability to finance projects and its own
expenditure.
ENERGY EFFICIENCYEnergy efficiency (EE) policies and regulations are regulated by the Energy Efficiency Division of the DPE.
While EE is not currently a major priority for the PNG Government, it might prove to be important if the
DSP 2010–30 goals are to be achieved. Since there are only two separate power grids (the Port Moresby
grid, which depends heavily on diesel generation and the Ramu grid), urban areas are forced into expensive
and inefficient self-generation, and large industries such as mining sites operate using off-grid self-generated
power.
In 2014, the Asian Development Bank (ADB) funded the Promoting Energy Efficiency in the Pacific(phase 2) project, which carried out several projects in the Pacific to improve EE, including lighting, solar
power generation, EE in hotels and the commercial and public sectors, and data collection. The analysis
revealed that in an aggressive efficiency scenario, PNG could save over 30% on the current level ofconsumption (ADB, 2014). When the potential growth of PNG is considered, that level of saving would
improve the possibility of meeting its targets as it reduces significantly the generation and distribution
requirements.
RENEWABLE ENERGYThe PNG 2050 Vision states the government’s target of 100% electricity generation from renewable sourcesby 2050. This is a challenge because although PNG’s renewable energy potential is very high, its remote148

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locations and difficult terrain restrict access to the best sites and the development of infrastructure to provide
electricity to load centres. Currently, the ageing Rouna hydro scheme in the Port Moresby network
represents the majority of renewable electricity. This scheme, however, is ageing and losing capacity. Recent
renewable development is limited to privately developed hydro and geothermal generation in mining sites
to support their mining operations.
In February 2007, Newcrest Mining Limited commissioned a 20 MW geothermal power plant. This isin addition to a 6 MW geothermal power plant constructed in 2003, and a 30 MW geothermal plantcommissioned in 2005. This increased the company’s total geothermal generating capacity to 56 MW.
The use of geothermal energy for electricity generation and its expansion of capacity are consistent
with the government’s goal of promoting green energy (see the ‘Climate Change’ section) and reducing
dependency on fuel oil for electricity generation. The Lihir Mine’s geothermal plant generates approximately
40% of its current power requirement and provides free electricity to residents residing near the Lihir minesite. It saves the plant approximately USD two million per year in fuel oil costs (Booth and Bixley, 2005).
The DPEʼs Energy Division assessed 45 hydro-electricity power sites in 1987 and completed threesmall hydro systems in 1992. In 2010, the Australian state of Queensland discussed a partnership with PNG
to develop a 1 800 MW hydro-electricity power plant on the Pukari River. This plant would make 600 MW
available for local use and the majority would go to Queensland through a 350 km undersea cable (IRENA,
2013).
In 2002, the Chinese Government donated 50 small combined wind/solar generators, some of whichhave been installed at coastal locations (IRENA, 2013).
NUCLEAR ENERGYPNG has no nuclear energy industry and there are no current plans to develop one.
CLIMATE CHANGE

PNG is directly threatened by the effects of climate change as tropical cyclones are a major hazard and sea
level rise threatens its primarily coastal nature. The PNG 2050 Vision and associated strategic documents
have included climate change as one of the key pillars for the future. The Office of Climate Change andDevelopment (OCCD) administers PNG’s Climate Compatible Development Management Policy(NCCDMP), which is based on the National Strategic Plan.
This strategy aims to achieve GDP per capita of USD 3 000 by 2030, while reducing GHG emissions
by 50%. PNG has identified changes to improve land use, land-use change and forestry as the main sourceof emissions reductions besides the renewable energy target mentioned before. In the strategy, thegovernment intends PNG to become carbon neutral by 2050 (OCCD, 2014).
However, the NCCDMP identifies significant challenges for the delivery and adoption of clean
technologies such as geographical barriers and lack of transport access. Furthermore, it identifies the lack of
coordination of government strategies and agencies as hampering the government’s ability to sustain robust
development.
The geothermal power plant (mentioned in the ‘Renewable Energy’ section) was the first project in
PNG to be registered for carbon credit trading under the Kyoto Protocol. The amount of GHG emissions
reduced by the geothermal plant is approximately 4% of PNG’s total CO 2 emissions (Newcrest, 2012).
There are currently nine clean development mechanism (CDM) projects registered with the United Nations
Framework Convention on Climate Change CDM Board (OCCD, 2014). DMs allow developed countries
to set up emissions reduction projects in developing countries to earn certified emissions reduction credits
under the Kyoto Protocol.
N OTA B L E E N E RG Y D E V E L O P M E N T S

There are several areas of development mentioned in the strategic documents; however, specific project
development is limited. The only detailed projects to date are included in the PNG Power Fifteen-YearPower Development Plan up to 2028 and include:

Generation feasibility studies for several hydro and geothermal sites.

Transmission and generation improvements in Kimbe, including a 6 MW run-off-the-river hydroscheme.

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P AP U A N E W G U I N E APort Moresby System transmission and distribution improvements including connecting 3 000
households and rehabilitation of 8 MW of hydro generation and transmission interconnections to
the Ramu system.



Development of the 80 MW Naoro Brown hydro project.

Refurbishment of the Ramu 1 Hydro scheme to increase capacity by 15 MW and development of
the 240 MW Ramu 2 project, which is in the initial geotechnical studies stage.



Geothermal energy development document and potentials research.

These developments have a strong component of donor funding such as the World Bank or the ADB.
The strategy considers other opportunities such as biomass development from palm oil, new gas potential,hydro potential, including a very large 2.5 gigawatts (GW) potential project that includes a demand creation
component.
UPSTREAM DEVELOPMENT

Several international companies have shown a renewed interest in investing in PNG’s upstream oil and gas
sector in recent years. At the end of 2007, the total number of petroleum prospecting licences was 37,
compared with 17 in 2003. The surge in interest has been principally attributed to the September 2003
introduction of internationally competitive fiscal incentives designed to attract oil exploration.
LNG PROJECTSIn March 2008, the project’s participants signed a joint operating agreement (JOA) for the PNG LNG
Project, namely: ExxonMobil (41.6%), Oil Search (34.1%), Santos (17.7%), AGL, Merlin Petroleum
Company (a subsidiary of Nippon Oil) and local landowners. The feed gas is sourced from the Kutubu,
Gobe and Moran oilfields as well as the Hides, Juha and Angore gas fields. In May 2008, the joint project’s
participants and PNG signed a gas agreement. The project aims to export 6.9 million tonnes of LNG fromPNG annually. Production began in April 2014, and the first deliveries commenced in May 2014. It is thelargest-ever private sector investment in PNG and is expected to increase its GDP by 21% in 2015 (ADB,2014).
REVIEW OF THE MINING AND PETROLEUM TAXATION REGIMEThe International Monetary Fund provided technical assistance to the PNG Department of Treasury to
conduct a review of the mining and petroleum taxation in 2013. The review’s purpose is to determine the‘appropriateness of the mining and petroleum taxation arrangement compared to similar resource-richcountries’ (CTR, 2014).
RENEWABLE ENERGY DEVELOPMENT AND RURAL ELECTRIFICATION

In 2013, the World Bank and the PNG Government signed a four-year agreement for renewable energy
development and rural electrification. The project aims to help expand electricity to millions of people in
Port Moresby and rural communities, and to develop clean energy options. Assistance will be provided in
the form of finance, expert advice and studies to help PPL and the PNG Government. The project will aim
to increase electrification rates from below 10% to 70% by 2030 (World Bank, 2013).
REFERENCES

ADB (Asian Development Bank) (2012). Promoting Energy Efficiency in the Pacific. http://www.eepacific.net/–– (2014) Promoting Energy Efficiency in the Pacific (PHASE 2). http://www.ee-pacific.net/–– (2015), Papua New Guinea: Economy, www.adb.org/countries/papua-new-guinea/economy.Central
Intelligence Agency (CIA) (2015), The World Fact Book: Papua New Guinea, Retrieved December 2015,
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.
http://taxreview.gov.pg/wpcontent/uploads/2014/05/31.03.14_issues.paper_.1_mining.petroleum.tax_.pdf
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.

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G. Martin Booth II and Paul F. Bixley (2005), Geothermal Development in Papua New Guinea, A country update
report: 2000-2005, www.geothermal-energy.org/pdf/IGAstandard/WGC/2005/0136.pdf．
GEA (Geothermal Energy Association) (2010), Geothermal Energy: International Market Update, www.geoenergy.org/pdf/reports/GEA_International_Market_Report_Final_May_2010.pdf．
IRENA (The International Renewable Energy Agency) (2013), Renewable Energy Opportunities and Challenges
in the Pacific Islands Region: Papua New Guinea,
www.irena.org/DocumentDownloads/Publications/Papua%20New%20Guinea.pdf.
MRA (Mineral Resources Authority) (2012). Mineral and Exploration Bulletin July to December 2012.
http://www.mra.gov.pg/Portals/2/Publications/Bulletin/julydec2012/Issue%202.pdf
Newcrest (2012), Mining Lihir,
www.newcrest.com.au/media/our_business/Newcrest_FS_Lihir_FINAL_27_July_2012_low_res_(2).pdf.
Office of Climate Change and Development (OCCD)(2014) National Climate Compatible Development
Management Policy.
http://www.pacificclimatechange.net/sites/default/files/documents/National_Climate_Change_Po
licy1.pdf
Papua Petroleum Limited (2008), Oil & Gas Exploration and Production: Why Papua New Guinea,
www.papuapetroleum.com/why-png/default.php．
PNG Government (2010), Papua New Guinea Vision 2050, National Strategic Plan Taskforce.
PNG LNG (2014), About PNG LNG, http://pnglng.com/project/about/．
PPL (PNG Power Ltd) (2014a), Fifteen Year Power Development Plan 2014-2028.
–– (2014b), PPL Energy Emergency Response Presentation at the 48th APEC Energy Working Group Meeting, Port
Moresby, p. 10．
World Bank (2013). Papua New Guinea Government and World Bank sign agreements for renewableenergy development. http://www.worldbank.org/en/news/press-release/2013/05/29/pnggovernment-and-world-bank-sign-agreements-for-renewable-energy-development
USEFUL LINKS

Papua New Guinea, Development Strategic Plan 2010–30—
www.treasury.gov.pg/html/publications/files/pub_files/2011/png-development-strategicplan.2010-2030.pdf/.
Papua New Guinea, Medium Term Development Plan 2011-2015—
www.unescap.org/pdd/calendar/CSN-Cambodia-Dec10/PapersPresentations/PapuaNewGuinea_PPT.pdf/.
Papua New Guinea Mineral Resources Authority (2013). Government Links and Other Links
www.mra.gov.pg/Help/UsefulLinks.aspx/.

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P E RUPERU
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. Witha land area of 1.3 million square kilometres (km2), Peru is divided into three main geographical regions: the
Costa to the west, the mountain region (Andes Mountains) and the Amazon region (Selva), covered by the
Amazon rainforest. The economy is divided into 25 political departments (administrative regions). In 2013,
the economy had a total population of about 30 million, an increase of 1.3% from the previous year
(EGEDA, 2015). By 2014, around 23% of its population was considered poor and 4.3% extremely poor.
The major population centre of Peru is the Lima region, which represents nine million people, nearly a thirdof the total population (INEI, 2015). The urbanisation rate of Peru is 76% (INEI, 2011).
Since 1990, the economy has been driven by its internal demand, mainly private investment, exports
and domestic consumption. Peru has a market-oriented economy, and in 2014, its key segments wereservices (49%), manufacturing and construction (21%), and mining (12%) (BCRP, 2014). Between 2000 and2013, the AAGR was 5.7% higher than the level reached in 2014 (2.4%) due to the deceleration of theemerging economies and the global uncertainty. This resulted in negative growth rates in total exports (1%), private and public investments (-1.6% and -2.4%, respectively), and reduction in private consumption
growth rate from 5.3% in 2013 to 4.1% in 2014 (BCRP, 2014). Mining is especially important, since Peru isa major global producer, ranking third in silver, third in zinc, third in copper and tin, fourth in lead and sixthin gold (USGS, 2015). Consequently, mineral exports have consistently accounted for a significant share of
the export revenue of the economy, being as much as 55% in 2014 (BCRP, 2014).
By 2013, the GDP of the economy reached USD 339 billion (2010 USD purchasing power parity[PPP]), with its GDP per capita growing at 4.4% to reach USD 11 095 (EGEDA, 2015). In addition, theforeign reserves reached a record USD 66 billion while its fiscal balance was 2.2% of the GDP (BCRP,
2014).
Owing to its scarce oil resources, Peru is a net importer of oil. Specifically, domestic production is not
only insufficient to meet the economy’s demand, but since most crude oil produced is of extra-heavy qualityand domestic refineries are unable to process it, a substantial share of the domestic production is exported.
In contrast, the proven gas reserves in the economy were 0.4 trillion cubic metres (tcm) in 2013. The Camisea
Gas Project is the largest energy project in Peru, which commenced operations in 2004 by supplying gas tothe local market. By 2010, Peru started to export through the LNG port located in Pisco (south of Lima).
Table 1: Key data and economic profile, 2013
Key dataa

Energy reservesb, c, dArea (million km2)

1.3

Oil (million barrels)

1 400

Population (million)

30

Gas (trillion cubic metres)

0.4

GDP (2010 USD billion PPP)

339

Coal (million tonnes)

9.9

GDP (2010 USD PPP per capita)

11 095

Uranium (kilotonnes of U)

1.4

Sources: a. EGEDA (2015); b. BP (2014); c. MEM (2014); d. NEA (2014).

E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

Peru’s total primary energy supply (TPES) in 2013 was 21 515 kilotonnes of oil equivalent (ktoe), a decreaseof 2.3% from 2012, due to the lower production of oil and natural gas. By energy source, in 2013, almost
half (10 352 ktoe) of the TPES was from oil, 26% from natural gas (5 781 ktoe) and 4% from coal (880ktoe). Non-fossil energy sources, such as hydro, wood, biomass, wind and others constituted the remainder
at 21% (4 501 ktoe) (EGEDA, 2015).
The proven gas reserves of the economy were 0.4 tcm in 2013, and are expected to increase to 0.8 tcm
by 2025, based on the information from the Ministry of Energy and Mines (MEM) (MEM, 2014). The
Camisea Gas Project is located 500 km from Lima, in the region of Cusco. The pipeline has a length of 560
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P E RUkm and passes through the Andes from the Las Malvinas plant (Cusco) to the liquefaction port in Pisco. A
second pipeline connects the Las Malvinas plant to Ica and Lima (715 km), and is used to distribute gas toresidential and industrial consumers. A third pipeline, with a transport capacity of 1 500 million cubic feetper day (MMcf/D) is under construction from Camisea to the regions of Arequipa and Moquegua in thesouth of Peru.
The Camisea project was initially aimed to satisfy the domestic demand for natural gas. However, as
production levels have increased at an average annual rate of 63% since 2004, this has allowed thedevelopment of an export market in the form of liquefied natural gas (LNG), which is sent by ships primarily
destined for Mexico, Japan and Europe. In 2013, Peruvian LNG exports from the ‘Melchorita’ liquefaction
plant amounted to 9.5 billion cubic metres (bcm) (Perupetro, 2015).
Peru’s proven coal reserves are around 9.9 million tonnes (Mt), with about 95% being constituted byanthracite and the remainder by bituminous coal. The majority of the reserves are located in the La Libertad,
Ancash and Lima departments. Peru is a net importer of coal, with 82% of its coal demand in 2013 being
met by imports and 18% by domestic production (MEM, 2013).
In 2013, Peru’s electricity generation totalled 43 295 gigawatt-hours (GWh), an 8.5% increase from the
39 909 GWh generated in 2012. Of the total, electricity generated from hydropower constituted the
maximum share of 53% (22 890 GWh), that from thermal plants accounted for 46% (19 762 GWh) and theremainder was generated from other sources such as biomass and wind (EGEDA, 2015).
In the other energy sectors, other types of biomass (such as firewood, vegetable coal, dung andyareta—a moss-type plant dried and then burned) are used for heating and cooking. In 2013, the renewablesources used for energy supply included firewood (38%), hydropower (48%) and other biomass sources
constituted the rest (MEM, 2013).
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

23 184

Industry sector

4 942

Net imports and others-1 838Transport sector

7 279

Thermal

19 762

Total primary energy supply

21 515

Other sectors

5 041

Hydro

22 890Coal

880

Non-energy704

Nuclear—Oil

10 35217 966

Others

643

Gas

5 781

Coal

573

Others

4 501

Oil

10 149Gas

1 761

Electricity and others

5 483

Total final energy consumption

Total power generation

43 295

Source: EGEDA (2015).
FINAL ENERGY CONSUMPTION

The final energy consumption in Peru grew by 6.5% in 2013, reaching 17 966 ktoe. Transportation was themost dynamic sector, growing 6.8% from the previous year, and representing 41% of the total final energy
consumption in 2013. The share of the industrial sector was 28%, while the combined ‘other’ residential,commercial and agricultural sectors consumed 28%. Accordingly, oil products dominated the total energy
consumption in 2013 with 56%, the majority of which was consumed as diesel, gasoline and liquefied
petroleum gas (LPG) (MEM, 2013). Electricity constituted 31% of the total end-use energy demand, while
gas and coal accounted for the remaining 10% and 3%, respectively (EGEDA, 2015).
ENERGY INTENSITY ANALYSIS

Peru’s energy intensity has been decreasing since 2012 due to the better use of energy sources. The primaryenergy intensity of the economy in 2013 was 63 tonnes of oil equivalent per million USD (toe/million USD),
decreasing by 7.8% from 69 toe/million USD in 2012. In contrast, the final energy demand increased its
energy intensity by 0.7% from 53 toe/million USD in 2012 to 53 toe/million USD by 2013. Industry energy
intensity increased from 14 toe/million USD in 2012 to 15 toe/million USD (4%) in 2013, while that of thetransport sector increased from 21 toe/million USD in 2012 to 22 toe/million USD in 2013 (0.9%).
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Table 3: Energy intensity analysis, 2013
EnergyEnergy Intensity (toe/million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

69

63

-7.8

Total final energy consumption

52.6

53.0

0.7

Industry

14

15

4.0

Transportation

21

22

0.9

Others

15.1

14.9

-1.7

Non-energy

2.2

2.1

-5.5

Source: EGEDA (2015).
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKIn Peru, the organisation responsible for the formulation and evaluation of energy and mining policies aswell as the energy sector’s guidance is the MEM, which is divided into two sub-ministries: the Vice-Ministryof Energy and the Vice-Ministry of Mines. MEM is also responsible for environmental issues concerningenergy and mining activities. Through its General Directorates (Electricity, Rural Electrification,
Hydrocarbons, Energy Efficiency, Mining, Energy-Environmental Issues and Mining-Environmental
Issues), the ministry covers the major areas of influence in the sector, overseeing its activities and promoting
investment to achieve sustainable development. In addition to MEM, the Supervisory Agency for
Investments in Energy and Mining (OSINERGMIN), is an autonomous regulatory agency created in 1996,
and is responsible for setting 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 challenge for Peru is to generate the energy resources needed to support future economic growth,and build the infrastructure that enables their use. The Peruvian Government has prepared the National
Energy Plan 2014–25 (MEM, 2014), detailing the policies and objectives to guide the energy policy of theeconomy. The overarching goal is to have a reliable, continuous and sufficient energy system that can
support sustainable development, in part by promoting investments in infrastructure (transport, refinery andproduction) and exploration.
In 2014, the Peruvian Government presented the Energy Plan 2014–25, whose main goals are as
follows (MEM, 2014):

To provide energy security and universal access to energy supply; andTo develop energy resources under a social and environmental perspective.

Under the energy efficiency goals, Peru has:

Established new labelling rules for electrical appliances, water heaters, lighting, electric engines andcauldrons;Promoted an Energy Efficiency culture;Established an exclusive way for the public transportation system;Maximised the use of natural gas in transportation;

Promoted the substitution between natural gas, LPG and diesel; andStrived to maintain energy prices in real terms.

At the same time, the Energy Plan considers the expansion of gas pipelines to cover the entire coastal
region. This is expected to increase the consumption of natural gas in Peru by 2025 to reach almost 35% of
the final energy demand.
The plan mentions some social indicators as summarised below:
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P E RUElectric Frontier: 99% of the population with direct access to electricity;Connections to a natural gas grid: 1 800 000 in 2025 versus 164 000 in 2013.

Seeking to become an energy hub in the South American region, Peru is encouraging energy integration
projects with Ecuador, Colombia and Chile in electricity, Brazil in hydro, and Bolivia in gas. Peru has
electricity interconnection projects with Ecuador through 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,
which is expected to commence operations by 2018. In electricity, additionally, Peru and Bolivia areundertaking studies to assess the potential to interconnect their own power systems in order to jointly supply
electricity to Chile. Finally, Peru and Brazil have a cooperation agreement to generate up to 6 000 megawatts(MW) of hydropower in the Peruvian territory, which would be transmitted to the Brazilian territory (MEM,
2010).
In energy security, in 2012, the Peruvian Government published the Law to Ensure Energy Security
and Promote the Development of the Petrochemical Industry (OSINERGMIN, 2012). It states that the
government aims to improve energy security by diversifying energy sources, reducing external dependence
and boosting reliability of the energy supply chain. Peru has high-energy self-sufficiency, based on thedomestic production of natural gas and the potential of hydropower. Despite this, Peru is projected to
become more dependent on oil imports as the rapid growth of the transport sector increases the demand.
To address this challenge, the government is overhauling the existing facilities of the Talara refinery so thatheavy oil can be refined domestically.
The project, with a cost of around USD 3.5 billion, is expected to increase the refinery capacity from65 000 to 95 000 barrels per day (bbl/d). The government is also encouraging state-owned companies tobecome active in energy exploration and production projects in the north and east of the economy. The
government is reducing the time required to obtain exploration permits and facilitating communication withlocal communities to help reduce protests against exploration and production of extractive activities.
The Peruvian Government is implementing the Social Energy Inclusion Program aimed to improve
the quality of life of the people residing in isolated regions and close to the economy borders. The program
intends to increase electricity coverage to cover 2.2 million people by expanding the electricity grid orproviding access to non-conventional energy sources. Further, implementation of the Social Energy
Inclusion Fund aims to provide 1.2 million low-income families with access to LPG through discountcoupons. Finally, the distribution of improved cooking kits aims to encourage a more efficient use of
Biomass among low-income families. These improved cooking kits are 50% more efficient in the use of
traditional Biomass, reducing CO2 emissions and reducing the risk of respiratory infections.
Table 4: Energy social inclusion indicators of Peru, Energy Plan 2014–25
2013

2016

2025

Electricity Access (% population)

90.3

95.8

99.0

LPG Discount Coupons (Families)

645 000

1 200 000

1 200 000

Improved Cooking Kits (Families)

72 000144 000

500 000

Source: MEM (2014).

ENERGY MARKETSThe Peruvian economy has become more market-oriented following the structural reforms of the 1990s,
resulting in the privatisation of the mining, electricity, hydrocarbons and telecommunications industries.
Several new laws have established a regime under which domestic and foreign investments are subject toequal terms, and 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 No. 27133), which
established specific conditions to promote the development of the natural gas industry, fostering
competition and diversifying energy sources to increase the reliability of the energy supply and improve thecompetitiveness of a productive sector of the economy (El Peruano, 1999).
In 1992, the Peruvian Government issued the Electric Power Concession Law. This law established a
new regulatory framework to promote competition and efficiency in generation, transmission anddistribution of electric power. This law is very important because it permits to set electricity tariffs based on
the marginal costs and free market forces. In this context, the government has enabled the introduction ofbidding and incentives for the optimal supply of electrical energy; establishment of a spot market;
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modification of the functions held by the Electric Energy Operation and Dispatch Committee (Comité deOperación Económica del Sistema Interconectado Nacional—COES), which is a private, independent
operator and planner for the electricity system; and adjustments to the legal framework related to theformation of transmission prices. Finally, an option was implemented for the large electricity customers tonegotiate directly with generation and distribution companies to obtain better tariffs for the energy that they
demanded.
Peru has two main electrical systems, the North-Central System (which includes Lima) and theSouthern System. These systems are interconnected and constitute the National Integrated Electrical System(SEIN), which is fed by hydro and thermal power plants. Since 2012, the SEIN also integrates solar, windand biomass sources.
In 2013, the SEIN accounted for 85% of the installed power in Peru and 93% of the total energy
generation (MEM, 2013). In 2013, 38 companies were responsible for electricity generation—63% private
and the rest state companies. In the same period, there were eight transmission and 21 distribution
companies (52% private and 48% state companies) (OSINERGMIN, 2013).
The National Energy Policy has stated the goal of developing the natural gas industry and expanding
its use. It encourages projects for power generation, prioritising the use of renewable energy (hydro) andnatural gas. The next major energy project, a 2 000 MW generation plant using natural gas simple-cycle
turbines and located in the southern region, is expected to boost generation in the southern system byaround 150%. The project, representing an estimated investment of USD 3.6 billion, is linked to theextension of the pipeline from the Camisea gas field in Cusco to Moquegua and Arequipa. This expansion
is a necessary step to integrate Peru with other power markets in the region.
FISCAL REGIME AND INVESTMENT

The Peruvian Government strives to attract foreign investment to sustain economic growth and improve
competitiveness. In recent years, Peru has expanded and streamlined the available investment schemes, withparticular focus on areas involving exports, infrastructure and services to the population. As such,investments in oil and gas upstream activities are conducted under licence 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 5: Investments required according to the Energy Plan 2014–25
Upstream Activities
Authorisation up to seven years.
Exploration

The Ministry of Energy and Mines can extend it up to three
additional years.

Exploitation

Maximum 30 years for crude oil.
Maximum 40 years for non-associated natural gas andcondensates.
Downstream Activities

Transportation

Done by ships or pipelines.
Concession up to 60 years.

Refinery

Authorised by the General Directorate of Hydrocarbons (Ministryof Energy and Mines).

Distribution

Liquid hydrocarbon and similar hydrocarbon by-products requireauthorisation from the Ministry of Energy and Mines.

Source: E&Y (2014).

The Peruvian Government guarantees legal stability to foreign investors, mainly on income tax regulations
and dividend distributions. Additionally, Peruvian laws, regulations and practices cannot discriminate
between Peruvian and foreign companies. In that sense, both kinds of companies are equal under the law.
There are no restrictions on repatriation of revenues, international transfers of capital, remittance ofdividends, interests and royalties.
The production scale methodology sets a percentage for royalties (starting at 5%) over a certain scaleof production (i.e. volume of barrels per calendar day) for liquid hydrocarbons and natural gas liquids, andother royalty percentages for natural gas for each valuation period. (E&Y, 2014).
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Table 6: Energy investment incentives
Tax losses can be carried forward for four years or indefinitely
Stabilisation agreements
Investment Incentives

Value Added Tax exemptions on imports of goods for
exploration activities
Value Added Tax recovery

Source: E&Y (2014).

The Global Competitiveness Report 2013 ranked Peru 61 among 144 countries. According to thisranking, Peru is among the top countries in Latin America in terms of macroeconomic environment, market
size, financial market development, labour market efficiency and goods market efficiency (E&Y, 2014).
The increasing energy demand and the abundance of natural gas will challenge the economy to increaseenergy investments to meet future energy infrastructure requirements. The Energy Plan forecasts that USD
50 billion to USD 53 billion will be required for energy investment, based on the average GDP growth
expected until 2025, covering the electricity, gas and oil sectors.

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 EFFICIENCYIn 2009, the MEM presented the Benchmark Plan for Efficient Use of Energy from 2009 to 2018. This plan
outlines various projects that are expected to be implemented in the industry through 2018 with potential
energy savings of 15% compared to a scenario without energy efficiency measures. This plan calls for the
replacement of lighting systems, boilers and engines, as well as implementation of a labelling scheme forcomputers. To date, the implementation of the plan has been delayed due to shortage of audit firms and alack of incentives.
In 2000, the government passed the Law for the Promotion of the Efficient Use of Energy (Ley dePromoción Del Uso Eficiente de la Energía), Law No. 27345. Consistent with this legislation, and with the2007 Supreme Decree No. 053–2007–EM, the Peruvian Government, through the President, createdsignificant initiatives to support energy efficiency through few mechanisms. These included DS–No. 034–
2008–EM of 19 June 2008 (Energy Saving Measures in Public Services), and RM No. 038–2009–MEM/DM
of 21 January 2009 (Energy Consumption Indicators and their Monitoring Methodology). Through theSupreme Decree No. 034–2008–EM of June 2008, the Peruvian Government promoted energy-saving
measures in the public sector, such as replacing less-efficient incandescent lamps with compact fluorescentlamps and acquiring equipment with energy efficiency labels.
In September 2009, the government, through MEM, organised a workshop on the efficient use ofenergy, during which the Referential Plan for the Efficient Use of Energy 2009–18 was approved. This is
the main instrument to achieve the energy efficiency goals of the economy through action plans proposed
for each sector (MEM, 2009). The Referential Plan aims to reduce energy consumption by 15% from the2007 levels by 2018 through energy efficiency measures. The plan includes an analysis of energy efficiency
in Peru and identifying sector programs that could be implemented to achieve the proposed targets.
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In workshop discussions, the following actions were identified as current priorities:

Reinforce strategic alliances with other economies to promote electricity security, efficient use ofenergy and environmental protection;

Develop tax benefits for private companies that operate with efficient technologies;Strengthen the Energy and Mines Regional Offices (DREMs) to enable them to implement theReferential Plan;

Use renewable energies according to the geography and climatic conditions of several regions; andObtain the commitment of the mining and energy sectors to being role models of efficiency.

In May 2010, the Peruvian Government created the DGEE within the Vice-Ministry of Energy(through Supreme Decree No. 026–2010–EM). The DGEE serves as the technical regulatory body,
proposing and assessing energy efficient use and production while also covering non-conventional
renewable energy issues. The DGEE also leads the energy planning of the economy, and is responsible fordeveloping the National Energy Plan.
RENEWABLE ENERGYThe Renewable Energy Policy in Peru promotes the use of solar, wind, geothermal, biomass and mini hydro(<20MW) energy sources. Peru has established goals to increase renewable energy use and has developed alegislative and policy program to support their development. Electricity generation from renewable
resources is being expanded from an already significant reliance on hydropower generation.
By 2006, Law No. 28876, to promote the use of renewable energy, provided an advance tax
reimbursement on the electricity sales of renewable energy-based utilities. In 2008, Law No. 1058 waspassed, which allows tax benefits to investment participants in electricity generation based on renewableenergy (including hydro), by accelerated depreciation of their investments by up to 20% per year, in orderto improve the projects’ feasibility (MEM, 2010). Finally, the Law on Promotion of Investment forElectricity Generation with Renewable Energies (Law No. 1002), was enacted in May 2008, and theRegulations for Generation of Electricity with Renewable Energies (Supreme Decree No. 050–2008–EM)
were issued in October 2008. Some of the incentives provided by the law are (El Peruano, 2008a, 2008b):


A five-year target for the share of domestic power consumption to be generated from renewableenergy sources, excluding large hydropower generation (i.e. less than 20 MW of installed capacity);

A firm price guaranteed for bidders who are awarded energy supply contracts for up to 20 years;and

Priority in loan dispatch and access to networks.

To achieve these goals, 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.



Photovoltaic: 96 MW at USD 173 per MWh.

Table 8: 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

-

Source: a. IFC (2011) b. MEM (2014).

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P E RUNUCLEAR ENERGY

Although Peru does not use nuclear energy for electricity generation, a government-run nuclear program
has been operational since 1975. This program involved constructing basic infrastructure, human resources
training and the establishment of the Peruvian Institute of Nuclear Energy (IPEN) as part of the MEM. The
mission of the IPEN is to promote and develop research in nuclear application to civil purposes to improvethe competitiveness of the economy and the quality of life of its inhabitants. Peru has been a member of theInternational Atomic Energy Agency since its creation in 1957.
CLIMATE CHANGE

As part of its environmental strategy policy, in October 2003, the Peruvian Government, by the Supreme
Decree No. 086–2003–PCM, approved the National Strategy on Climate Change (NSCC) for the mitigationof an adaptation to climate change (El Peruano, 2003). The main objectives of the NSCC are to reduceclimate change impacts through integrated studies on vulnerability and adaptation, and to control both local
pollution and greenhouse gas (GHG) emissions by using renewable energies and energy efficiency programsin production sectors.
Peru accounts for 0.1% of the world’s GHG emissions (CAIT, 2012). Based on the Intended
Nationally Determined Contribution (INDC), Peru is aiming to reduce GHG emissions by 30% by 2030
compared with the Business-As-Usual (BAU). The absolute reduction is estimated at 90 million tonnes of
CO2 equivalent, with 50% of this reduction being in the forestry sector, including land use, land use change
and forestry (LULUCF) (UNFCCC, 2015).
N OTA B L E E N E RG Y D E V E L O P M E N T S

In September 2015, the MEM modified the Electricity Regulation on Distribution to Promote the Energy
Access Act to include the possibility of a feed-in tariff system for those who generate their own electricity
based on non-conventional renewable technologies. This modification is awaiting the new regulation and
it is expected to be approved by the first part of 2016. Additionally, during March 2016, the MEM also
approves the project that allows the exports of electricity surplus generation to other economies. This
project has to be approved in the Peruvian Congress before the end of 2016.
REFERENCESBCRP (Banco Central de Reserva del Perú) (2014), Memoria Anual 2014,www.bcrp.gob.pe/publicaciones/memoria-anual/memoria-2014.html.
CAIT (2012), website ʻCAIT Climate Data Explorerʼ page, http://cait.wri.org/.
E&Y (Ernst & Young) (2014), Global Oil and Gas Tax Guide 2014, www.ey.com/GL/en/Industries/Oil--Gas.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
El Peruano (1999), Ley para la Promoción del Uso de Gas Natural Industrial, Ley No. 27133,
www2.osinerg.gob.pe/MarcoLegal/docrev/LEY-27133-CONCORDADO.pdf.
–– (2003), Aprueban la Estrategia Nacional de Cambio Climático, Decreto Supremo No. 086–2003–PCM,
www2.congreso.gob.pe/Sicr/CenDocBib/cat_uibd.nsf/RepLegPeruana?OpenForm&CARPETA=%28CAMBIO_CLIMATICO_Y_BIODIVERSIDAD%29&FIN.
–– (2008a), Decreto Legislativo 1002, www.minem.gob.pe/archivos/legislacion-9ozj22z9ap5zz33zDL_de_promocion_de_la_inversion_para_la_generacion_de_electricidad_con_el_uso_de_energias_
renovables_1002.pdf.
–– (2008b), Decreto Supremo No. 050–2008–EM, www2.osinerg.gob.pe/MarcoLegal/docrev/DS-012-2011EM-CONCORDADO.pdf.
IFC (International Finance Corporation) (2011), Assessment of the Peruvian Market for Sustainable Energy
Finance. Executive Summary.
INEI (Instituto Nacional De Estadistica E Informatica) (2011), Perú: Estimaciones y Proyecciones de Población
Urbana y Rural por Sexo y Edades Quinquenales, Según Departamento 2000-2015,
http://proyectos.inei.gob.pe/web/biblioineipub/bancopub/Est/Lib0844/index.htm.
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P E RU–– (2013), Evolución de la Pobreza Monetaria 2009-2013,www.inei.gob.pe/media/cifras_de_pobreza/informetecnico.pdf.
–– (2014), Reporte de Población,
www.inei.gob.pe/media/MenuRecursivo/publicaciones_digitales/Est/Lib1157/libro.pdf.
–– (2015), Cifras de Pobreza, www.inei.gob.pe/media/cifras_de_pobreza/np_057-2015-inei.pdf.
MEM (Ministerio de Energía y Minas) (2009), Plan Referencial para el Uso Eficiente de la Energía 2009–2018,www.minem.gob.pe.
–– (2013), Balance Nacional de Energía 2013, www.minem.gob.pe.
–– (2014), Plan Estratégico Nacional 2014–2025.
MINAM (Ministerio de Ambiente) (2011), Compromisos Internacionales,
http://cambioclimatico.minam.gob.pe.NEA (Nuclear Energy Agency) (2014), Uranium 2014:
Resources, Production and Demand, https://www.oecd-nea.org/ndd/pubs/2014/7209-uranium2014.pdf.
OSINERGMIN (Organismo Supervisor de la Inversión en Energía y Minería) (2012), Gerencia Adjunta deRegulación Tarifaria – GART. Energías Renovables,
www2.osinerg.gob.pe/EnergiasRenovables/EnergiasRenovables.html.
–– (2013). Reporte Trimestral de Monitoreo del Mercado Eléctrico. Segundo Semestre del 2013 Año 2 –Nº 4 – Noviembre 2014,
http://www.osinergmin.gob.pe/seccion/centro_documental/Institucional/Estudios_Economicos/
Reportes_de_Mercado/RSMME_II_2013.pdf
Perupetro (2015), Shipment of Natural Gas for export purposes. www.perupetro.com.pe/exporta/relacion.jsp.
USGS (United States Geological Survey) (2016), Minerals Information. http://minerals.usgs.gov/minerals/.

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
Plantadelicuefacción
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 PHILIPPINESI N T ROD U C T I ON

As an archipelago, the Philippines comprises 7 107 islands, covers a total land area of 300 000 square
kilometres (km2) and its coastline extends to about 36 289 kilometres. It is located in the south-eastern partof Asia, bordered by the Philippine Sea in the east and west, the Luzon Strait in the north and the Celebes
Sea in the south. The economy has three major geographical divisions, namely: Luzon, Visayas andMindanao islands. Manila, located in Luzon, is the capital of the Philippines and is one of the 70 largest
cities in the world based on United Nation report (UN, 2014). In 2013, the economy’s total population was
97.6 million, up by 1.6% from 2012. Based on the 2014 World Population Ranking, it is the twelfth mostpopulated economy in the world and the seventh in Asia (WB, 2014).
The Philippine economy is moving towards inclusive growth with a 7.2% increase in gross domestic
product (GDP), from USD 569 billion in 2012 to USD 610 billion in 2013 (2010 USD purchasing power
parity [PPP]) (EGEDA, 2015). This remarkable growth was mainly driven by the service sector, which
accounted for almost 60% of the GDP. The combined effects of a robust domestic trade and the boom in
the real estate business helped augment the aggregate value-added in the service sector by 7%. Meanwhile,the industry sector contributed about 33% to the economy’s total output. This could be attributed to theincreased manufacturing output as well as the rebound in public construction due to the much needed
government stimulus in infrastructure spending. The Agriculture, Fishery and Forestry (AFF) sector, which
had the least contribution to GDP at 11%, grew by 1.1% owing to the increase in rice production output
attributed to the expansion in the area harvested and improvement in yield, despite the several typhoons
that plagued the economy in 2013 (Navarro and Llanto, 2014). Further, the GDP per capita income also
exhibited significant growth, registering an increase of 5.5% from the 2012 level of USD 5 926 (EGEDA,
2015). The revival in investments and the buoyant external trade contributed to the healthy growth of theeconomy during the period (PSA-NSCB, 2014).
With the positive economic outlook of the Philippines, the rating agencies Standard and Poor’s andFitch and Moody’s upgraded the credit ratings of the economy to that of ‘stable outlook’ (high quality withvery low/minimal credit risks) (Official Gazette, 2014). Likewise, the economy’s ranking by the World
Economic Forum had improved from being 65th out of 144 countries in 2012 to 59th out of 148 countries
in 2013 (Navarro and Llanto, 2014).
The robust economic development poses a challenge to the government to meet the growing demandfor energy. Harnessing the domestic energy resources remains a priority policy of the government as thiswill not only bring in additional investments in the economy but will also significantly reduce reliance on
imported fuels as well as achieve its goal of increasing the self-sufficiency level. The continuous
implementation of the Philippine Energy Contracting Round (PECR) is a measure to attract investments inthe exploration and development of oil, gas and coal resources in the economy. The economy has modest
proven reserves of around 76 million barrels of oil (includes condensate), 24 billion cubic metres (834 billion
cubic feet [Bcf]) of natural gas and 440 million tonnes (Mt) of coal (DOE, 2015a). On the other hand, theeconomy’s renewable energy resources contribute significantly to its energy mix. Since the passage of R.A.
9513, otherwise known as the Renewable Energy Act of 2008, the Philippine Government has awarded 617
renewable energy service/operating contracts with a total aggregate capacity of 15 233 megawatts (MW)(DOE, 2015j).
Table 1: Key data and economic profile, 2013
Key dataa, bEnergy reservesc

Area (thousand km2)

300

Oil (million barrels)

76

Population (million)

97.6

Gas (billion cubic metres)24

GDP (2010 USD billion PPP)

610

Coal (million tonnes)

440

GDP (2010 USD PPP per capita)

6 250

Sources: a. WB (2014); b. EGEDA (2015); c. (DOE, 2015a).

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E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLYThe economy’s total primary energy supply (PES) in 2013 grew by 7.3%, reaching 45 783 kilotonnes of oil
equivalent (ktoe) from the 2012 supply level of 42 668 ktoe (EGEDA, 2015). More than 56% of theeconomy’s energy requirement was sourced locally, largely from renewable energy and coal, whichsignificantly improved its self-sufficiency level by 1.5 percentage points from the 55% level in 2012. Oilremained a dominant energy source, accounting for about 30% of the economy’s primary energy supply
mix. The growing oil demand for transport and households constitutes the bulk of the economy’s primary
oil supply requirement. However, the total primary oil supply decreased by 0.8% from 13 826 ktoe in 2012
to 13 715 ktoe in 2013. The decrease was attributed to the reduction of oil demand in the household sector,
being the most vulnerable to oil price escalation (DOE, 2014a). Coal followed next, contributing 22% to
the PES, posting an increase of 7.4% in 2013 (10 000 ktoe) from the level in 2012. On the other hand,production of natural gas from the Malampaya gas field decreased by 2.3% from its 2012 level to 3 066 ktoe
in 2013. During the same period, the aggregate share of renewable energy resources was registered at 42%of the PES. Wind, geothermal and hydro production levels exhibited a decline of 13%, 6.3% and 2.3%,
respectively. Production of other renewables such as solar and biomass increased by 7.1% and 2.9%,
respectively (DOE, 2014a).
FOSSIL ENERGYThe Philippines relies on energy imports, specifically fossil fuels, to meet its energy demand requirement.
The economy’s net imports increased by 4.7% from 19 632 ktoe in 2012 to 20 555 ktoe in 2013. The bulkof the energy imports were oil and oil products, constituting about 67% of the total, while the remaining
was contributed by coal (32%), and biofuels (1%).
The hike on energy imports was mainly due to the increasing demand for coal in the power generation
sector. Coal imports increased by 49% in 2013 from the 2012 level, and was sourced mostly from Indonesia,
Australia and Vietnam. On the other hand, local coal production decelerated by 3.5% from 3 879 ktoe in
2012. The decrease in the production output of the economy’s major coal producer (Semirara Mining
Corporation) significantly affected the production level. Unprofitable operations of other major domestic
coal producers from Zamboanga and Cebu also contributed to the declined production level of indigenous
coal in the economy (DOE, 2014a).
RENEWABLE ENERGY

Renewable energy sources contributed substantially to the economy’s supply mix, contributing 40% to the
TPES in 2013. Geothermal provided the bulk of the renewable energy contribution, about 32%, to the total
indigenous primary energy supply. Biomass, which is mostly utilised in the residential sector, contributed
29% to the total. Meanwhile, hydro’s share in the indigenous energy supply was 9.8% in 2013, with a decline
in production due to the “El Niño” (drought) causing reduced availability of water. Solar and wind, which
had the smallest contribution, are expected to increase their respective shares in the future with a growing
number of awarded contracts issued by the government. Wind contribution increased with the installationof an additional 283 MW wind power plant in 2014 (DOE, 2014a).
As a government priority policy, greater private sector involvement will be promoted and intensified
for the development and utilisation of the economy’s vast renewable energy potential. As stipulated in the
National Renewable Energy Program (NREP), the economy intends to triple the 2010 renewable energybased installed capacity as an aspirational target. This is intended for power generation, as well as its
contribution to non-power applications to increase the share of renewable energy in the primary energy mix
by 2030 (DOE, 2013).
ELECTRICITY GENERATIONThe economy’s total electricity generation in 2013 grew by 3.2%, from 72 922 gigawatt-hours (GWh) in2012 to 75 266 GWh. Coal remained the dominant source of electricity, especially for baseload accounting,for more than 42% of the economy’s total power supply in 2013. Natural gas continued to contributesignificantly to the economy’s total electricity generation (25%). However, power generation from natural
gas declined slightly by 4.3% during the same period due to the decrease in production of the Malampaya
gas field, which affected the power generation of three natural gas-fired power plants. On the other hand,the aggregate level of renewable energy in power generation decreased by 4.1% in 2013, from 20 762 GWh
in 2012. This is mainly due to the decreased production output from geothermal and hydropower-based
plants, about 6.2% and 2.2% respectively, from the 2012 levels. Hydro and geothermal both contributed
13% each to the total power generation mix, lower by one percentage point from the previous year’s level.
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Similarly, wind also exhibited a drop in power generation by 15%. Only solar and biomass posted an increasein their generation in 2013, 8% and 15%, respectively (DOE, 2014c).
Table 2: Energy supply and consumption, 2013
Primary Energy Supply (ktoe)

Final Energy Consumption (ktoe)

Power Generation (GWh)

Indigenous production

25 812 Industry sector

6 299 Total power generation

75 266

Net imports and others

20 555 Transport sector

8 466

Thermal55 363

Total primary energy supply

45 783 Other sectors

11 625Hydro

10 019Coal

10 003 Non-energy

314

Nuclear–Oil

13 715 Total final energy consumption

26 704

Others

9 884

Gas

3 066

Coal

2 196

Others18 999Oil

12 249

Gas

67

Electricity and others

12 192

Source: EGEDA (2015).
FINAL ENERGY CONSUMPTION

The sturdy growth of the Philippine economy was reflected in the 13.6% increase in the economy’s total
final energy consumption (TFEC), from 23 502 ktoe in 2012 to 26 704 ktoe in 2013. All economic sectors
exhibited an increase during this period, with transport and industry still being the largest energy-consuming
sectors. Energy use in the transport sector, which accounted for 32% of the TFEC, increased by 4.4% in
2013. This was attributed to the increased utilisation of gasoline, diesel and ethanol for public transport, as
well as jet fuel for domestic aviation. Meanwhile, the increase in production output of the industrial sectors,
particularly in the cement and basic metal industries, increased its aggregate energy requirement by 9.9%.
The other sectors’ energy consumption accounted for an aggregate share of 45% in 2013 (DOE, 2014a).
Petroleum products continued to be the major fuel for the economy, accounting for 46% of the totalenergy demand, as its demand level increased by 6%, from 11 556 ktoe in 2012 to 12 249 ktoe in 2013.
Similarly, electricity and others (biomass) remarkably expanded by around 21%, contributing an aggregate
share of 46% to the total.
ENERGY INTENSITY ANALYSISThe GDP growth rate of 7.2% in 2012 (2010 USD PPP) increased the total primary supply requirement of
the economy by 7.3%. This could be translated into an economy-wide primary energy intensity level of 75.1
tonnes of oil equivalent per million USD (toe/million USD) in 2013 with a minor increase from 2012.
Table 3: Energy intensity analysis, 2013
EnergyEnergy Intensity (toe/million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

75.0

75.1

0.1

Total final energy consumption

41

44

6.0

Industry

10.1

10.3

2.5

Transportation

14.2

13.9

–2.6

Other sectors

17

19

14

Non-energy

0.2

0.5

120

Source: EGEDA (2015).

In terms of final energy demand, the intensity level increased from the 2012 level. Among the sectors,
the non-energy sector registered the largest increase, specifically triggered by oil-related products used for
petrochemical processing. Other sectors and industry sector followed next with both posting an increase
from previous year’s level. The other sectors’ demand increased by 14% due primarily to mid-term election
held in 2013, which required additional energy demand for the production of campaign materials and other163

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related activities needing energy. Similarly, the industry’s energy demand could also have been affected by
the election period. Only the transport sector posted a decrease in intensity as the continuous increase inpetroleum prices made several vehicle owners more judicious in fuel use, as well as the adoption of more
fuel-efficient vehicles.
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORK

Cognizant that energy is an economic driver to fuel local productivity and boost countryside development,
the Department of Energy (DOE) has been continuously implementing and intensifying its plans andprograms directed at attaining energy security and bringing reliable and affordable energy services to thegreater populace. The Philippine Energy Plan 2012–30 has outlined several measures being undertaken by
the government and energy stakeholders in creating a sustainable future with less carbon footprints.
Specifically, the Plan outlines the following policy thrusts with specific goals and targets that are to beachieved within the planning period 2012–30:
a.

b.

c.

d.

Ensure energy security
Triple the capacity of renewable energy by 2030 (from 5 438 MW in 2010 to 15 304 MW
by 2030).

Promote indigenous fossil fuels.

Ensure reliable and efficient power supply.

Expand energy access

Achieve 90% household electrification by 2017 and 100% local electrification level forsitios (an administrative-territorial category in the Philippines) by 2016.



Ensure transmission system reliability and integrity.

Promote low-carbon future

Achieve 10% energy savings on total energy demand.



Achieve 30% of all public utility vehicles running on alternative fuels.

Climate-proof the energy sector


e.

f.

Promote a climate-change-resilient energy sector.

Promote investments in the energy sectorOperationalise a one-stop-shop for energy projects.

Strengthen closer partnerships with local government units (LGUs) and industry players.

Develop regional energy plansFormulate more responsive geographic plans (DOE, 2013).
ENERGY MARKETSOIL AND GAS

To boost exploration and development of the economy’s 16 sedimentary basins (with combined oil and gas
reserves of 4 777 million barrels of oil equivalent (MMBOE) or 690 million tonnes of oil equivalent [Mtoe]),the DOE has been constantly conducting the PECR to provide a transparent and competitive system oftendering onshore and offshore oil and gas blocks for exploration to both local and foreign investors. In
2014, the PECR5 was launched, which offered 11 petroleum potential areas in the economy to prospective
investors. In the same year, the DOE supervised and monitored 29 existing petroleum service contracts(DOE, 2015e).
Production from the existing oil and gas fields of the economy yielded about 1.9 million barrels (Mbbl),
124 Bcf of natural gas and 4.1 Mbbl of condensate in 2013. A reduction of 4.3% was observed in oil
production, including condensate, during this period due to the shutdown of the Galoc field during themonths of August and September in preparation for the production line and tie-in of the two new wells
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T H E P H I LI P P I N E Sfrom Galoc 5 and 6 (DOE, 2014b). Likewise, the economy’s natural gas producing fields, Malampaya andLibertad, produced an aggregate of 124 Bcf in 2013, which is 7.9% lower compared to the 2012 level of 135
Bcf. The 30-day shutdown of the Malampaya gas production facility and the 24-day halt in the operation at
the Libertad gas field in Cebu contributed to the decreased production of natural gas. This was also coupledwith the repair and maintenance activities at the Ilijan, San Lorenzo, and Sta. Rita natural gas power plants
in Batangas City, which are the major users of Malampaya gas, and the stoppage in the operation of the 1
MW Desco natural gas plant in Cebu (DOE, 2014a).
COAL

The Philippines also has 13 coal basins with an estimated total resource potential of 2.4 billion metric tonnes.
The largest coal resources are found in Semirara in Antique (Visayas) with a total potential of 570 Mt.
As coal remains a dominant source of fuel in the economy, efforts for expanding the utilisation of thevast domestic coal reserves are continuously being pursued. Greater partnerships between the government
and the private sector are extensively promoted to encourage investors to explore the coal resource potentialof the economy. The newly awarded 22 exploration contracts during the conduct of PECR4 in 2011 (15contracts) and PECR 5 in 2014 (seven contracts) are expected to boost the coal reserves in the economy(DOE, 2015e). Currently, a total of 75 coal-operating contracts (45 exploration and 30
development/production) are being monitored and supervised by the DOE to ensure timely completion of
the proponent’s work program.
In 2013, the total coal production reached 7.1 Mt of coal, lower by 4.3% from the 2012 level of 7.4
Mt. The bulk of the production was from Semirara contributing 96% to the total. However, its production
together with that of other coal basins in Zamboanga and Cebu, including small-scale mines, had decreased
considerably due to unprofitable operations as a result of the low price of coal. Several contract holders
were also cancelled/terminated due to breach of contract obligations, while other contracts did not follow
through with the operation because of market problems and high operating costs.
MARKET REFORMSELECTRICITY

The Philippine Government continuously oversees and pursues the implementation of power sector
reforms in accordance with the Republic Act 9136 or the Electric Power Industry Reform Act (EPIRA) of
2001. Consistent with Section 31 of the EPIRA, the operating and regulatory policies and guidelines for the
implementation of the Retail Competition and Open Access (RCOA) were established to provide guidance
to retail market participants and to ensure a smooth transition. Full commercial operation of RCOA
commenced on 26 June 2013 with a total of 275 registered participants (DOE, 2014b). The RCOA is being
implemented to improve competition in the generation and supply sector, which is seen to result incompetitive tariffs for electricity.
The DOE has consistently monitored and supervised the operation of the Wholesale Electricity Spot
Market (WESM) under the Philippine Electricity Market Corporation (PEMC). In 2013, the integrated
WESM (Luzon and Visayas) had a total of 246 registered participants comprising 54 generating companies
and 192 customer-trading participants (DOE, 2014b). In order to facilitate the inclusion of the ancillary
services requirement of the power grid in the WESM operation, the DOE issued Department Circular (D.C.)
2013-02-0027 in December 2013 ‘Declaring the Commercial Launch for the Trading of Ancillary Services in Luzon and
Visayas under the Philippine Wholesale Spot Market’. As stated in the D.C., the Reserve Market will have tocommence commercial operations in March 2014 after all requisite systems and procedures are already inplace (DOE, 2014b). On 26 February 2014, the PEMC launched the Trial Operation Plan (TOP) comprising
two phases. The first phase involves testing the protocols, procedures and interfaces development for theMarket Operator-System Operation and Reserve Market Working Group, as well as resolving the remaining
operational issues. Meanwhile, the second phase (the main TOP) involves the demonstration of operationsof the Reserve Market and familiarisation of trading participants in all processes. To further prepare themarket participants, the DOE issued D.C. 2014-03-0009 ‘Declaring a New Commercial Launch Date for the
WESM Reserve Market and Directing PEMC to Develop a Protocol for Central Scheduling and Dispatch of Energy andContracted Reserves’ (DOE, 2015e). It is envisioned that the Reserve Market will benefit the power industry
with the co-optimisation of energy and reserves. This would help achieve greater competition among energy
and reserve providers that could lead to transparent and competitive energy prices. Likewise, the Reserve
Market will also facilitate the entry of renewable energy in accordance with the Renewable Energy Act of2008.
The DOE has implemented several programs as part of their sustainable solutions to address thepower shortage in Mindanao (southern part of the Philippines) to provide stakeholders with the power ofchoices and draw in available energy resources and untapped power capacities for additional supply to the165

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grid. The roadmap for sustainable solutions to Mindanao includes the establishment of a market fortransparent and efficient utilisation of available power capacities. This market would encourage participationof existing power generating capacities and interruptible loads, and entry of new generating capacities in
Mindanao. To establish such a market, the DOE directed the PEMC to develop and implement an Interim
Mindanao Electricity Market (IMEM) and correspondingly issued D.C. 2013-05-0008 in May 2013
‘Promulgating the IMEM Implementing Rules’ and D.C. 2013-09-0023 in September 2013 ‘Declaring the Launch of
IMEM and the Terms and Conditions for the Commencement of the Full Commercial Operations of IMEM’. The said
Circular had set the dates for the initial and full commercial operation of IMEM in September andNovember 2013, respectively (DOE, 2014b). To strengthen the operation of IMEM, the IMEM Rules wereamended in May 2014 to include ‘Demand-side bidding and transitory arrangement’ (DOE, 2015e).
The Interruptible Load Program (ILP) is another measure being implemented in Mindanao. Under
this program, customers of a distribution utility (DU) will be compensated for voluntarily de-loading itself
from the grid by operating its generation facility for its own use during peak demand hours. The DU willthen charge and collect from the customers within its franchise area the corresponding energy ‘freed up’ (inkilowatt-hours) by the ILP customers. This will be used to pay these customers based on the Energy
Regulatory Commission-approved ILP rates (DOE, 2015b). Initially, the program was implemented to solve
the power shortage issues in the Visayas and Mindanao islands, but with the tight power supply in Luzon
Island during the summer months of 2015, it was also implemented there.
Aimed at enhancing the operations of the National Electrification Administration (NEA) and theeconomy’s electric cooperatives (ECs), President Aquino enacted on 07 May 2013 the Republic Act No.
10531, otherwise known as ‘An Act Strengthening the National Electrification Administration (NEA), Further
Amending for the Purpose of Presidential Decree No. 269, as Amended, otherwise known as the National Electrification
Administration Decree’. This Act provides greater accountability for NEA as the regulator of ECs with theadditional mandate to supervise the operation of problematic ECs towards the goal of improving its
operational parameters and standards. The new law has the following objectives:i.

Promote sustainable development in rural areas through rural electrification;ii.

Empower and strengthen NEA to pursue the electrification program and bring electricity throughthe electric cooperatives as its implementing arm, and to the countryside even in missionary or
economically unviable areas; andiii.

Empower the ECs to cope with the changes introduced by the restructuring of the electric powerindustry pursuant to RA 9136.

It has been a challenge for the government to provide greater access to electricity in some areas thatare isolated from the grid. Due to the geographical landscape of the economy, the government has devised
and implemented mechanisms to energise these areas through a decentralised RE system such as
photovoltaic solar home system (PV-SHS) and micro-hydro systems. The Qualified Third Party (QTP) is
another electrification program of the government, which opens up unviable areas for private sector
investment, intending to provide an integrated power generation and distribution service to the households.
By the end of 2013, the household and sitio electrification levels were already registered at 79% and 74%,
respectively (DOE, 2014b).
OIL

As mandated under Republic Act 8479 or the Downstream Oil Industry Deregulation Act of 1998, theDOE ensures a continuous, adequate and stable supply of oil in the economy. As such, monitoring the costof crude and product imports/exports, local production, industry demand, inventory levels, distribution andmarketing facilities, and other downstream capability statistics continue to be a major undertaking of thedepartment. These will facilitate prospective investors to engage in business in the downstream oil sector.
In 2014, a total of 249 oil companies were already engaged in marketing, distribution and storage of
petroleum products in the Philippines with an accumulated investment cost amounting to PHP 48 billion(DOE, 2015e).
As a measure to ensure oil supply and address the risks from supply-related problems such as
geopolitical uncertainties and calamities, the government is enforcing the Minimum Inventory Requirement(MIR) on oil companies, bulk suppliers and LPG players operating in the economy. An equivalent to 30
days for total in-country stocks of crude and finished products are required for refiners, while an equivalentof 15 days in-country stock is required for bulk marketers and seven days for the LPG players. The oilcompanies are compliant and normally maintain more than the required minimum level of inventory (DOE,
2014b). Supply situationer is regularly released particularly during contingencies in areas affected by naturalcalamities (DOE, 2015e).
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As a response during emergency situations caused by natural calamities such as the super typhoon
Haiyan that hit the economy in 2013, a Memorandum was issued to the oil companies to serve as a reminder
to implement the DOE Circular No. 211-03-003 on Mutual Product Sharing Accommodations (MPSA).
The MPSA intends to provide and stabilise oil supply in calamity-affected areas as it permits the oilcompanies to supply petroleum products to the facilities of other oil companies to ensure a steady supplyof petroleum products in the affected areas (DOE, 2014b). Likewise, a Memorandum of Agreement (MOA)
was signed on 22 October 2014, which embodies the commitments of the following entities: Metro Manila
Development Authority (MMDA), Office of Civil Defence (OCD)/The National Disaster Risk Reduction
and Management Council (NDRRMC) and members of the Philippine Institute of Petroleum, Inc. (PIP),
namely: Pilipinas Shell, Chevron, Petron Corp, Isla LPG Corp., PTT Philippines and Total Philippines, todevelop a framework that will enable a sustainable supply of petroleum products to areas and organisations
affected by emergencies, disasters and calamities (including but not limited to those resulting fromearthquakes, typhoons, floods, conflagrations and spills) (DOE, 2015e).
DOWNSTREAM NATURAL GAS

The development of natural gas is considered an important component of the fuel supply diversification
strategy of the economy, thus ensuring greater energy supply security and reliability. Having a balance ordiversified energy mix reduces dependency on any particular fuel/resource, and mitigates vulnerability to
any supply disruptions due to unforeseen situations. Natural gas is considered the best alternative to oilbased energy for power generation, transport and industry uses. With this, the government intends to expand
the utilisation of natural gas in different demand sectors of the economy. Apart from the Malampaya Gasto-Power Project, the government is also promoting the development of liquefied natural gas (LNG)
terminals and gas pipeline distribution networks.
The technical feasibility study conducted by the Pilipinas Shell Petroleum Corporation (PSPC) on theestablishment of a Floating Storage Regasification Unit (FSRU) in Batangas concluded in July 2013. Resultsof the study confirmed the viability of developing an import regasification terminal in the economy,
particularly a floating storage instead of a land-based terminal. The FSRU is more appropriate for the
economy given its weather patterns. Likewise, the FSRU can service a demand up to 2000 MW and cancomplement the growing renewable industry in the economy (PhilStar, 2013). Meanwhile, the Philippine
National Oil Company (PNOC) commissioned the Public-Private Partnership (PPP) Center for the detailed
feasibility study of the 105 km Batangas-Manila pipeline (BatMan 1) to supplement the Japan International
Cooperation Agency (JICA) study completed in June 2014 (DOE, 2015e). It may be noted that JICA studied
the entire natural gas supply chain, which includes the LNG facility, regasification facility, pipeline andofftake facilities, among others.
On the other hand, the DOE is closely monitoring the on-going construction of an LNG terminal anda merchant gas-fired power plant in Pagbilao, Quezon. The LNG facility comprises two unit storage tankswith a capacity of 130 000 cubic meters each. The project has an on-site 600 MW merchant gas-fired power
plant, which will serve as an anchor load for the project (DOE, 2015e).
A Natural Gas Quality Standard was formulated in February 2015 for possible promulgation by the
Bureau of Product Standards. This standard is considered necessary for more efficient supply acquisitionand distribution of natural gas in the economy.
Cognizant of the importance to have a clear and comprehensive policy and regulatory frameworks
governing the development of the downstream natural gas industry, the government has drafted a Natural
Gas Bill, which was filed in both Houses of Congress. Pending approval and promulgation of the Natural
Gas Bill, the DOE D.C. issued in 2002 on the ‘Interim Rules and Regulations Governing the Transmission,
Distribution and Supply of Natural Gas’ serves as the guiding policy of the government for the promotion of
the natural gas industry in the Philippines.
ALTERNATIVE FUELS

The government continues to embark on a fuel diversification program that envisions equal sharing of fuels
and technologies with a preference for cleaner fuels and lessening dependence on imported fuels. As such,the DOE has strengthened its implementing policies and programs on alternative fuels for the transport
sector. The enactment of the Biofuels Act underscores the government’s efforts in further intensifying the
production of the economy’s local biofuels. Currently, the government mandates the use of 2% biodiesel
blend and 10% bioethanol blend. As a continuing effort, the DOE has issued a Notice to Proceed
Construction for the three bioethanol producers with a total annual rated capacity of 59.4 million litres.
These new additions have increased the economy’s total number of biofuel producers to 19 (11 biodiesel
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and eight bioethanol) (DOE, 2015e). The government is studying the possible increase in biodiesel blend
from 2% to 5%. Continuous research and development has been undertaken through partnerships withvarious academic institutions and other stakeholders on areas for potential biofuel feedstocks and inincreasing the blend rate, specifically for biodiesel.
As support for the government campaign on Compressed Natural Gas (CNG)-fuelled buses, the Land
Transportation Franchising and Regulatory Board (LTFRB) under the Department of Transportation andCommunications (DOTC) has guaranteed the availability of franchises for the remaining 169 CNG buses(from 200 CNG buses targeted in the pilot phase). On the other hand, to strengthen the Auto-LPG program,the government has entered into an MOA with two academic institutions in 2014 to produce proficienttechnicians who will be involved in the conversion from gasoline-fed to auto-LPG, including the repair andmaintenance of such vehicles.
The government has also engaged in an electric vehicle program, which is seen to contribute to reduce
oil consumption of the transport sector and to lower the emission level. The program was carried out underthe Asian Development Bank (ADB) Loan Assistance Program involving deployment of 100 000 electric
tricycles or e-trikes (a motorcycle with an attached passenger sidecar used as a local-based public utility
vehicle).
The DOE is also proposing to enter into MOA with the Development Academy of the Philippines todevelop an Alternative Fuels Roadmap, which will serve as a blueprint for the implementation of the
program.
ENERGY EFFICIENCY

The government has continuously been implementing high impact programs and projects such as the
National Energy Efficiency and Conservation Program (NEECP) to support the energy requirements ofthe productive sectors of the economy through efficient management of energy use. The NEECP waslaunched in 2004 as an umbrella and banner program of the government for its various initiatives on energy
efficiency and conservation, including:Social Mobilisation and Information, Education and Communication (IEC) Campaign;Energy Efficiency Standards and Labelling Program;

Government Energy Management Program (GEMP);Energy Management Services/Energy Audits;

Recognition Award Program;Fuel Conservation and Efficiency in Road Transport (FCERT); andPower Conservation and Demand Management (Power Patrol).

The FCERT is an IEC campaign to establish significant data for a vehicle-labelling program in the
future.
Dissemination of information through the conduct of workshops and trainings has been steadily
carried out to encourage involvement of various economic sectors on the government’s initiative. The DOE,
in partnership with the Development Academy of the Philippines launched the ‘Usapang Klima at Enerhiya:
Facilitators’ Training on Energy Efficiency and Conservation’ in 2013 to inform educators, particularly
science teachers and coordinators in secondary public schools, about energy efficiency and conservation
practices and measures as a response to climate change, which in turn could be taught and relayed to theirstudents (DOE, 2015e). The government also took advantage of the benefits of the tri-media campaign
through the publication of promotional materials on broadsheets as well as the establishment of the Watt
Matters website (www.wattmatters.org.ph). These provide consumers with energy saving tips and practicalways to use energy efficiently, while the establishment of the website allows energy consumers to view theenergy consumption of their household appliances and lets them calculate their electric bills. This website
intends to provide consumers the power of choice in selecting the best and most efficient appliances in themarket.
The implementation of the Energy Standards and Labelling Program is a way to promote the use ofenergy efficient household electrical appliances. This program helps consumers choose the appliance modelthat provides the same amount of performance with lower electricity consumption. At present, the program
covers household air conditioners, household refrigerators, compact/linear/circular fluorescent lamps andballasts (DOE, 2014b). The government plans to expand the coverage of the program to include other168

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household electric appliances and industrial equipment, such as electric fans, washing machines, televisions,industrial fans and blowers, and even vehicles.
To set a good example to the public, the GEMP is also implemented, which mandates all government
offices to reduce their monthly consumption of electricity and petroleum products (transport) by at least
10%. This program also aims to reduce the public sector’s electricity bill and fuel expenses. Since theinception of the program in September 2005 to December 2013, accumulated savings of the government
reached about PHP 1.8 billion in electricity bill and PHP 283 million in fuel expenses (DOE, 2014b). To
further reduce electricity consumption, the DOE recommended a scheme to replace the existing noninverter window-type and package-type air conditioning units with inverter-type ones. The study conductedby DOE comparing an inverter-type with non-inverter type of air conditioning wherein the thermostat was
set at 25 °C, revealed that using inverter-type reduces electricity consumption by about 44%, from 0.9
kilowatt-hours (kWh) to 0.5 kWh (DOE, 2015e).
The DOE also offers audit services to manufacturing plants, commercial buildings and other energy
intensive companies to determine their energy use patterns and identify energy conservation measures,
which could be adopted in their respective companies. A team of engineers from the DOE evaluates theenergy utilisation efficiencies of equipment, processes and operations of these companies and recommends
energy efficiency conservation measures in order to achieve energy savings. In accordance with D.C. 200809-20004, the DOE undertakes accreditation of Energy Service Companies (ESCO) in the economy. Suchaccreditation aims to promote ESCO as an emerging business industry. To date, there are 14 ESCOs
accredited by the DOE (DOE, 2015e).
Other major undertakings involved collaborations with international institutions to provide technicalassistance for the development and introduction of a new and efficient technology. The DOE has partneredwith the United Nations Industrial Development Organization (UNIDO) and the Department of Trade andIndustry (DTI) to implement the Philippine Industrial Energy Efficiency Project (PIEEP) funded by the
Global Environment Fund (GEF). The PIEEP intends to improve the energy efficiency in the industrial
sector, which includes the provision of tools and capacity building on energy management system and energy
system optimisation. The project will introduce the application of ISO 50001 to select industrial sectors suchas chemicals, food and beverage, iron and steel, and pulp and paper. The project is expected to generate
about 2 million megawatt-hours (MWh) of energy savings. On the other hand, the EU-funded Switch-Asia
Policy Support Program in the Philippines is assisting the government in revising the economy’s Energy
Efficiency and Conservation Roadmap (DOE, 2015e).
RENEWABLE ENERGYProviding clean and sustainable energy to the citizens is one of the key priorities of the government. Efforts
to further expand the utilisation of the economy’s renewable energy (RE) resources were apparent with the
adoption of the NREP in June 2011. The NREP intends to increase utilisation of indigenous RE resources,
institutionalise a comprehensive approach to address the challenges and gaps that prevent wider applicationof RE technologies in a sustainable manner and outlines the action plans necessary to facilitate andencourage greater private sector investments in RE development (DOE, 2011).
To stimulate the implementation of the NREP, the following policy mechanisms are espoused under
the RE law:

Feed-in Tariff (FiT);

Renewable Portfolio Standards (RPS);Green Energy Option Program; and

Net-Metering for Renewable Energy

The FiT provides guaranteed payment on a fixed rate per kWh for RE generation excluding generationfor own use, particularly for run-of-river hydro, biomass, wind and solar. There is no FiT rate initiallyapproved for the Ocean Thermal Energy Conversion (OTEC) resource as further study and more data
analysis must be first undertaken. The FiT Rules and FiT Rates were promulgated and approved by the
Energy Regulatory Commission (ERC) upon recommendation by the DOE on 12 August 2010 and 27 July
2012, respectively. The initial FiT rates approved by the ERC are as follows:Solar—PHP 9.7/kWhWind—PHP 8.5/kWhBiomass—PHP 6.6/kWh169

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Hydro—PHP 5.9/kWh

The approved FiT rates shall be subject to review and readjustment by the ERC after three years of
initial implementation or when the installation targets for each technology as set by the DOE have been
met. The PHP 9.7/kWh rate for solar was effective until 15 March 2015, whereas the new rate of PHP
8.7/kWh, which was approved by ERC will be effective until 15 March 2016. Initially, the FiT installation
target of 760 MW is set for the first three years from 2013 to 2015. In August 2014, the DOE issued acertification endorsing an increase in the FiT installation target for solar from 50 MW to 500 MW withapplication of a lower FiT rate for the additional capacity. Similarly, the FiT installation target for wind was
also increased in April 2015 from 200 MW to 400 MW (DOE, 2015f). These increases brought the total
installation targets to 1 410 MW, divided as follows:

250 MW Run-of-River Hydropower

250 MW Biomass

400 MW Wind



500 MW Solar

10 MW Ocean

On the other hand, the RPS is a market-based policy that requires mandated electric power industry
participants such as generators, distribution utilities and electric suppliers to source an agreed portion of
their energy supply from eligible RE resources. Other mechanisms include the Green Energy Option
Program, which provides end-users with the option to choose RE resources as their source of energy.
Meanwhile, the 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 may be used to offset electricity provided by the distribution utilities to the end-user during theapplicable period. Enabling rules on the net metering for RE were approved on 27 May 2013 (DOE, 2014c).
Since the passage of the RE law, the economy has consistently accelerated the installation of RE
capacity. In 2013, the total installed generating capacity from RE already stood at 5 543 MW (DOE, 2014c).
With the awarding of 617 RE service contracts comprising an estimated aggregate capacity of 15 233 MW,
the NREP target of tripling the RE capacity (based on the 2010 level) may be achieved by the economy.
NUCLEAR ENERGY

As a matter of policy, the government is open to all potential and available energy resources for the economy
to have a secure, reliable and stable energy supply to meet its growing energy requirements. With this, thegovernment still considers nuclear energy as a long-term option for power generation based on its benefits
for supply security and the environment, particularly on CO 2 emissions. Several initiatives were carried out
to reintroduce nuclear energy in the power supply mix. The government even created an Inter-agency CoreGroup on Nuclear Energy in 2009 through a Joint Department Order between the DOE and theDepartment of Science and Technology (DOST). The Core Group was tasked to develop, manage andformulate policies and strategies on nuclear power generation, as well as to study the 19 infrastructure
requirements for a nuclear energy program as prescribed by the International Atomic Energy Agency(IAEA). Likewise, the Core Group was envisioned to serve as the Interim Nuclear Energy Program
Implementing Organization (NEPIO). However, all initiatives were debilitated after the Fukushima incident
in 2011.
The advancement in nuclear energy technology coupled with enhancement in safety and safeguard
standards as the lessons learned from the Fukushima incident could encourage the economy to adopt a
nuclear energy policy in the future.
CLIMATE CHANGE

The Climate Change Commission is created by the government by virtue of the Philippine Climate Change
Act of 2009 (RA 9729) as a policy-making body under the Office of the President with the same status asthat of a national government agency. The Commission monitors and evaluates programs and action plans
relating to climate change (CCC). A Cabinet Cluster on Climate Change Adaptation and Mitigation was also
created through Executive Order 43 issued by the President of the Philippines in May 2011 to serve as anadvisory committee to the President on matters relating to climate change. The Cabinet Cluster will take thelead in pursuing measures to adapt to and mitigate the effects of climate change on the Philippine
archipelago, and undertake all the necessary preparations for both natural and man-made disasters (PMS,2011).
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During the 21st Session of the Conference of Parties (COP21) of the United Nations Frameworkon Climate Change, the Philippines expressed intention to undertake about 70% CO 2 reduction by 2030
relative to its BAU scenario of 2000–30 as indicated in the economy’s ‘Individual Nationally Determined
Contributions’ (INDC). Energy is identified as being among the sources of CO 2 reduction together with thetransport, waste, forestry and industry sectors. The mitigation reduction is conditioned on the availability offinancial resources, technology development, and transfer and capability building (UNFCCC, 2015).
N OTA B L E E N E RG Y D E V E L O P M E N T S
REGIONAL ENERGY PLAN

The DOE is drafting regional energy plans for the three major islands—Luzon, Visayas and Mindanao—of
the economy to address and provide appropriate measures to the specific local energy issues and concerns.
The Mindanao Energy Plan (MEP) was already completed and published including policies and programson sustainable and long-term solutions to the region’s power supply shortfall problem. The Visayas Energy
Plan (VEP) is currently being formulated to be followed by the Luzon Energy Plan (LEP). Simultaneously,
the DOE is also formulating a Power Development Plan in close partnership with the local stakeholders
particularly in missionary areas or those provincial areas not connected to the main power grid. The Palawan,
Mindoro and Bohol (an island province but connected to the Visayas grid) Provincial Power Development
Plans are in progress for adoption by the Provincial Council/Board.
RENEWABLE ENERGYThe DOE issued D.C. 2015-07-0014 in July 2015 prescribing a policy for maintaining the share of renewableenergy to the total power installed at a minimum of 30% through FiT and other mechanisms as stipulated
in the Renewable Energy Act (DOE, 2015i). Such D.C. could serve as an energy mix policy of the economy,
which would further accelerate the development and utilisation of renewable energy, and achieve the NREP
aspirational target. The DOE is currently undertaking a study on a fuel mix policy for the economy with theprimary aim of sustaining the share of RE to 30% within the planning horizon of 2014–30. The fuel mix
study aims to consider the issues on diversification of energy resources, increasing energy efficiency,
environmental sustainability and reasonable electricity prices.
An earlier D.C. was also issued in April 2015 providing the framework for the implementation of amust and priority dispatch of RE resources in the Wholesale Electricity Market (DOE, 2015d). Under thesaid D.C., renewable energy power plants will be allowed to have maximum penetration to the gridconsidering system security and economically short-run dispatch of ancillary services.
The government launched the 2014 Wind Atlas and the Geo-Spatial Toolkit for the economy, which
was developed in collaboration with the United States Department of Energy’s National Renewable Energy
Laboratory (NREL). The new assessment provided information on economically viable wind potential areas,
which are closer to loads and infrastructure. This information would help promote wind development andattract prospective international investors/developers to the economy.
In 2014, four wind grid-connected power projects commenced operation with a total aggregate
capacity of 304 MW, of which three are located in northern Luzon where the first wind power plant in theeconomy is situated. The largest among these wind projects is the 150 MW Nagsurot-Saoit in Burgos, Ilocos
Norte (DOE, 2015e).
On the other hand, 10 solar power projects with a total estimated generation capacity of 230 MW were
issued with a Certificate of Compliance by the ERC under the FiT system.
PENDING ACTIONSThe DOE is pursuing several legislative agenda to further enhance the economy’s energy policies andregulatory frameworks. Several bills have been filed in both Houses of Congress for a policy regulatory
framework covering specific energy sub-sectors, while other bills are filed for purposes of amending theexisting framework for improvement, and to provide additional incentives to encourage and attract moreprivate investments. These energy bills include: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;
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T H E P H I LI P P I N E S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.
MARKET REFORMS

Several D.C.s were issued by the DOE to improve the power sector. Through D.C. 2015-06-0008 signed
on 19 June 2015, the DOE is mandating all distribution utilities to undergo a competitive selection process
in securing power supply agreements. This is to ensure security and certainty of electricity prices to theconsumers in the long term. With this D.C., the distribution utilities will be guided by the following
principles:

Increase transparency in the procurement process in order to reduce risks;

Promote and instil competition in the procurement and supply of electric power;Ascertain least-cost outcomes that will be not be challenged in the future; and,Protect the interest of the public (DOE, 2015h).

Likewise, the DOE issued D.C. 2015-06-0009 on 15 June 2015 providing additional guidelines for
distribution utilities in complying with their mandate to ensure supply security. The object of the circular is
to ensure supply security for electric power through incorporation of standard contractual terms to clearlydelineate the responsibilities of the contracting parties in the event of any forced majeure or events affecting
delivery of power supply or delays in commercial operations of committed power projects (DOE, 2015g).
On the other hand, the D.C. 2015-06-0010 issued on 20 March 2015 provides policies to facilitate the full
implementation of RCOA in the electric power industry (DOE, 2015c).
CLEAN TECHNOLOGY FUND PROJECT

Through the EU-Funded Switch Asia Policy Support Program in the Philippines, the DOE is enhancing
the Energy Efficiency and Conservation Roadmap. This roadmap intends to improve and accelerate theimplementation program and provide long-term policy direction for the economy on energy efficiency andconservation. Overall, the objective of the roadmap is to achieve 40% reduction in energy intensity basedon the 2010 levels.
On the other hand, the DOE is also implementing the Joint Development Program for Climate
Change in the Philippines, in partnership with the Korean Energy Management Corporation (KEMCO).
The Joint Development Program aims to develop investment projects on improving energy efficiency andnew and renewable energy to mitigate the effects of climate change. The program includes informationexchange, identification of applicable technologies for project development, and support in undertaking a
pre-feasibility study to include the development of financing plans (DOE, 2015e).
GOOD GOVERNANCE AND TRANSPARENCY INITIATIVESThe DOE established the Energy Virtual One Shared System (EVOSS) in June 2015, a web-based systemproject, with the support of the United States Agency for International Development (USAID). EVOSS isdesigned to facilitate online tracking of Renewable Energy Service Contract (RESC) applications andprocessing permits, which will eventually extend to other technology/resource applications in the future.
The system will facilitate and help streamline business processes as it is expected to reduce cost; promote
efficiency in the government service; foster healthy relationships with stakeholders; increase private
investments and promote transparency.
Other good governance initiatives implemented by the government to provide data and informationtransparency to the public include creating websites on ‘Kuryente’, ‘Wattmatters’ and ‘Langis’. The Kuryente
website (www.kuryente.org.ph) offers consumers easy access to information on all distribution utilities intheir franchise area pertaining to the components of electricity rates charged to customers, such as systems
losses, collection efficiency and liabilities. Meanwhile, the Wattmatters website provides information onenergy conservation and more efficient appliances available in the market for the residential sector. The newaddition is the ‘Langis’ website (www.langis.org.ph) providing information on factors affecting pump pricesof petroleum products and international price movements.
The DOE is carrying out Open and Competitive Selection Process (OCSP) for awarding
service/operating contracts for RE. This process promotes a greater transparency and competitive system
for RE developers in the economy.

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REFERENCES

Adoracion Navarro and Gilbert Llanto (2014), The Philippine Economy in 2013 and Prospects for 2014.
Philippine Institute for Development Studies (PIDS).March
2014.http://dirp3.pids.gov.ph/webportal/CDN/PUBLICATIONS/pidsdrn14-1.pdf.
DOE (Department of Energy) (2011), National Renewable Energy Program,
www.doe.gov.ph/microsites/nrep/index.php?opt=execSummary–– (2013), 2012-2030 Philippine Energy Plan, www.doe.gov.ph/doe_files/pdf/01_Energy_Situationer/20122030-PEP-Executive-Summary_revised.pdf.
–– (2014a), Philippine Energy Sector Situationer 2013, DOE-Energy Policy and Planning Bureau.
–– (2014b), Energy Sector Accomplishment Report 2013,www.doe.gov.ph/doe_files/pdf/Transparency_Seal/Annual%20Report%20%20Energy%20Sector%20Accomplishment%20Report%202013.pdf.
–– (2014c), 2013 Philippine Power Statistics,
https://www.doe.gov.ph/doe_files/pdf/02_Energy_Statistics/Power-Statistics-2013.pdf.
–– (2015a), DOE-Energy Resource Development Bureau. Fossil Fuels Reserves.
–– (2015b), Mindanao Energy Plan 2014-2030.
–– (2015c), Department Circular No.: 2015-06-0010 Providing Policies to Facilitate the Full Implementation of
Retail Competition and Open Access (RCOA) in the Philippine Electric Power Industry, 20 March 2015,
https://www.doe.gov.ph/doe_files/pdf/Issuances/DC/DC2015-03-0001.pdf.
–– (2015d), Department Circular No.: 2015-03-0001 Promulgation of the Framework for the Implementation ofMust Dispatch and Priority Dispatch of Renewable Energy Resources in the Wholesale Electricity Spot Market,
April 2015, https://www.doe.gov.ph/doe_files/pdf/Issuances/DC/DC2015-03-0001.pdf–– (2015e), 2014 Energy Sector Accomplishment Report,
https://www.doe.gov.ph/doe_files/pdf/Transparency_Seal/Annual%20Report%20%20Energy%20Sector%20Accomplishment%20Report%202014.pdf.
–– (2015f), Renewable Energy Development in the Philippines, Presented by Undersecretary Loreta G.
Ayson of Department of Energy during the APERC Annual Conference 2015 held on 9-10 June2015 in Japan.
–– (2015g), Department Circular No.: 2015-06-0009 Providing Additional Guidelines for Distribution Utilities inComplying with their Mandate to Ensure Supply Security, 15 June 2015,
https://www.doe.gov.ph/doe_files/pdf/Issuances/DC/dc2015-06-0009.pdf.
–– (2015h), 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/doe_files/pdf/Issuances/DC/dc2015-06-0008.pdf.
–– (2015i), Department Circular No.: 2015-07-0014 Prescribing the Policy for Maintaining the Share of Renewable
Energy in the Country’s Installed Capacity, 22 July 2015,
https://www.doe.gov.ph/doe_files/pdf/Issuances/DC/dc2015-07-0014.pdf.
–– (2015j), Summary of RE Projects as of November 2015, https://www.doe.gov.ph/summary-ofprojects/2857-summary-of-re-projects-as-of-30-november-2015.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
Official Gazette (2014), Philippines Credit Rating, www.gov.ph/report/credit-ratings/.
PhilStar (The Philippine Star) (2013), Pilipinas Shell Concludes Feasibility Study on LNG Project,www.philstar.com/business/2013/06/22/956668/pilipinas-shell-concludes-feasibility-study-lng-proj.
PMS (Presidential Management Staff) (2011), Cabinet Cluster on Climate Change Adaptation and
Mitigation
http://www.pms.gov.ph/index.php/transseal/67-linkccam/57-cabinet-clusters
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PSA-NSCB (Philippine Statistics Authority-National Statistical Coordination Board) (2014), Philippine
Economy Grew by 7.2% in 2013, www.nscb.gov.ph/sna/2013/4th2013/2013qpr4.asp.
UN (United Nation) (2014). World Urbanization Prospects.
http://esa.un.org/unpd/wup/highlights/wup2014-highlights.pdf
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) (2014), World Population Ranking, IBRD-IDA, http://data.worldbank.org/datacatalog/Population-ranking-table.
USEFUL 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/174

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THE RUSSIAN FEDERATIONI N T ROD U C T I ON

Russia is the world’s largest economy, spanning over 17 million square kilometres (km2). It is the only APEC
economy 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, the tundraalong the Arctic seaboard and uplands and mountains in the southern regions. Russia’s vast natural resources
include major deposits of coal, natural gas, oil and other minerals. Despite its land area advantage, two-thirdsof the economy is a zone of high-risk agriculture, due to mostly continental climate, which is either too cold
or too dry. Centralised district heating is provided for 6–8 months per year, while cooling during the summer
is not widely used.
From 1990 to 2008, the Russian population declined from 148 million to 143 million, however, from2008 to 2013, there was an increase to 144 million (EGEDA, 2015). The share of urban and rural population
has remained unchanged from 2009 at 74% and 26% respectively. Russia’s average population density is
8.4 people per square kilometre, with the majority of the population living in the European part of theeconomy (GKS, 2015).
Russia’s economic growth has slowed from the 2012 level of 3.4% to 1.3% in 2013 with an average
growth rate of 4.4% for the period 2000–13. In 2009, the global economic and financial crisis affected theRussian economy, with the GDP) declining by 7.8% in 2009 from the 2008 level. The recovery in 2010–13
was driven by soaring world prices for oil and natural gas.
Table 1: Key data and economic profile, 2013
Key dataa, bEnergy reservesc, dArea (million km2)

17

Oil (billion barrels)

105

Population (million)

143.5

Gas (trillion cubic metres)33

GDP (2010 USD billion PPP)

3 200

Coal (billion tonnes)

157

GDP (2010 USD PPP per capita)

22 294

Uranium (kilotonnes of U)

262

Note: NEA data is for uranium reserves recoverable at a production cost of less than 260 USD per kg.
Sources: a. EGEDA (2015); b. GKS (2015); c. BP (2015); d. NEA (2014).

Russia’s major industries include oil and gas production, petroleum refining, mining, iron and steel,chemicals, machinery and motor vehicles. The energy sector’s output accounts for about 30% of Russia’sGDP, which is more than 50% of the tax and custom duty payments, 70% of total export and 30% of thetotal investment, and is important not only for Russia’s economic development, but to the survival of its
population during harsh winters.
In terms of proven reserves, as of 2013, Russia holds 17% of the world’s gas, 6.2% oil, 18% coal(BP, 2015) and about 18% of its reasonably assured resources of uranium (NEA, 2014). Several otherresources remain undiscovered, but the formidable obstacles of climate, terrain and distance hinder their
exploitation.
Russia’s oil resources in the traditional oil-producing regions are believed to be heavily depleted, as
more than 50% of the economically recoverable resources have already been produced. In the Urals andVolga regions, resource depletion is considered to exceed 70%. The share of the remaining resources thatare more complex to recover is constantly growing. Nearly 80% of Russia’s oil production is from large
fields with remaining lives of 8 to 10 years. Newly developed resources are often concentrated in mediumand small-size deposits (ME, 2014).
Russia’s gas industry is in a more favourable resource situation than its oil industry. The proven natural
gas reserves in Russia, estimated at 33 trillion cubic metres, should be adequate to meet both the domestic
market and export demands for the foreseeable future.
The remaining proven reserves of coal in Russia amount to more than 157 billion tonnes, or 18% of
the world’s reserves. At current rates of coal consumption in the economy, these reserves should be
sufficient for 800 years.
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The refining industry in Russia includes about 30 major refineries with a total capacity for the primaryprocessing of about 277 million tonnes (Mt) of crude oil per year (ME, 2014).
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. Given the obsolescence of this heating infrastructure, a considerable amount of energy
can be saved through relatively accessible technologies and cost-effective energy saving practices. The energy
sector is very important to the security of the global energy supply. The economy is the world’s largest
exporter of energy overall, the largest exporter of natural gas and the second-largest exporter of oil. In
addition, Russian-labelled nuclear fuel is used at 74 commercial reactors (17% of the global market) and 30
research reactors in 17 economies worldwide, and the economy provides over 40% of the world’s uranium
enrichment services (ME, 2014).
In 2013, exports of crude oil, petroleum products and natural gas accounted for two-thirds of the totalexports of the economy. Russia holds leading positions in each of the world’s energy markets: uranium
enrichment (40%), natural gas trading (about 20%), reactor construction (almost 20%), spent nuclear fuelconversion (15%), crude oil and petroleum products trading (more than 10%), and coal trading (about 10%).
In 2013, Russia exported 234 Mt of crude oil, 206 billion cubic metres (bcm) of natural gas (including
Liquefied Natural Gas [LNG]) and 143 Mt of coal.
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

Russia’s total primary energy supply in 2013 was 731 million tonnes of oil equivalent (Mtoe), comprising
natural gas (54%), crude oil and petroleum products (22%), coal (15%) and others, including nuclear andhydro (9.2%).
By destination, more than 90% of Russia’s total energy exports are directed to Western and Eastern
Europe, including the Commonwealth of Independent States (CIS). To secure its future energy exports,
since 2008 Russia has actively been diversifying its export routes towards regional markets in the Asia–
Pacific region, aiming to deliver oil, natural gas and coal to China, Japan and Korea in north-east Asia.
Russia produced 523 Mt of crude oil and gas condensate in 2013. The oil heartland province of West
Siberia accounted for about two-thirds of the total production. Refiners consumed 279 Mt of crude oil as
feedstock, producing 269 Mtoe of petroleum products, including 39 Mt of gasoline, 78 Mt of diesel oil,
71 Mtoe of fuel oil and 10 Mtoe of kerosene.
Oil exports declined from 241 Mtoe in 2012 to 238 Mtoe in 2013. Petroleum products exports
amounted to 116 Mtoe in 2013, a 10 Mtoe increase from the 2011 level. There are prospective onshore
oilfields in the Timano–Pechora and East Siberia regions and offshore in the Arctic and Far East seas, andon the North Caspian shelf.
Natural gas production increased from 541 Mtoe in 2012 to 563 Mtoe in 2013. Net exports of natural
gas in 2013 accounted for 174 Mtoe (159 Mtoe in 2012) or 31% of the production. Nearly all natural gas
exports were destined for Western and Central Europe, including Turkey, with small amounts piped to theTranscaucasian states. Huge but undeveloped reserves of natural gas are located in remote regions, where
the lack of infrastructure prevents the start-up of upstream operations.
Russia produced 184 Mtoe of coal in 2013. Coal exports reached almost 89 Mtoe. From 2000 to 2013,of the total coal produced, the proportion exported increased from 17% to 49%, despite the fact that themain coal-producing areas (the Kuznetsky and Kansko–Achinsky basins) are landlocked in the south ofSiberia, some 4 000–6 000 km from the nearest coal shipping terminal for the Atlantic/Pacific markets.
Enormous prospective coal deposits have been found in even less-developed and more remote areas ofeastern Siberia, south Yakutia and the Russian Far East.
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

1 339 967 Industry sector

123 672 Total power generation 1 057 589

Net imports and others–592 993 Transport sector

93 540

Thermal

700 556

Total primary
supply730 559 Other sectors

148 227

Hydro

181 151

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Coal

108 289 Non-energy

69 079

Nuclear172 508

Oil

160 110 Total final energy
consumption

434 519

Others3 374

Gas

395 161Coal

11 746

Others

66 999

Oil

121 725

Gas

126 473

Electricity and others

174 575

Source: EGEDA (2015).

Russia produced 1 058 terawatt-hours (TWh) of electricity in 2013, of which 66% was from thermal
power plants, 17% from hydropower and 16% from nuclear energy. The economic potential of hydropoweris estimated at 852 TWh per year, but only 20% of this has been developed. Russia has enormous technicalpotential for renewable energy production, such as hydro and biomass in Siberia, wind along its Arctic andPacific shores and geothermal in Kamchatka and the Kuril Islands. However, the use of this potential isconstrained by the huge distances over which the renewable energy would have to be delivered toconsumers.
FINAL ENERGY CONSUMPTION

In 2013, the total final energy consumption (TFEC) in Russia was 435 Mtoe, a decrease of 3.1% compared
to 2012. By sector, industry accounted for 29%, transport 22% and other sectors 50%. By energy source,coal accounted for 2.7% of the total consumption, petroleum products 28%, natural gas 29% and electricity
and others, including heat, 40%. Due to Russia’s extremely cold climate, the most important energy use isfor space heating, constituting about one-quarter of the TFEC.
The traditional energy-intensive industrial structure has been one of the major drivers of economic
development. New policies on energy efficiency increase the share of less energy-intensive services inexisting industries, and improve the efficiency of the heat supply to the residential and commercial sectors.
It is estimated that Russia’s energy saving potential ranges from one-third to almost half of its TFEC.
ENERGY INTENSITY ANALYSIS

The growth of Russia’s real GDP of 1.3% in 2013 resulted in a 2.7% improvement in the economy’s total
primary energy supply. This could be translated to an economy-wide level of 228 tonnes of oil equivalent
per million USD (toe/million USD). For final energy demand, the energy intensity level decreased by 4.4%
from the 2012 level of 142 toe/million USD to 136 toe/million USD in 2013.
According to a sector-wide analysis, in 2013 industry registered a reduction of 7% in energy use per
million USD of GDP from the 2012 level of 42 toe/million USD to 39 toe/million USD. Such a progressshows the effect of energy efficiency policies, especially in the Industry. The intensity in the transport sector
improved by 1.4% to 29 toe/million USD, compared to its 2012 level, due to the increased share of more
efficient vehicles introduced into the Russian market during 2013. The other sectors’ energy intensity also
decreased by 6.9% from the 2012 level, which could also be attributed to improvements in energy efficiency
and availability of energy efficient technology, especially in district heating systems.
Table 3: Energy intensity analysis, 2013
Energy intensity (toe/million USD)

Change (%)

Energy2012

20132012 vs 2013

Total primary energy supply

235

228

–2.7

Total final energy consumption

142

136

–4.4

Industry

42

39

–7.0

Transportation

30

29

–1.4

Other sectors

50

46

–6.9

Non-energy

21

22

2.5

Source: EGEDA (2015).

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

Russia’s Energy Strategy 2020 was adopted in August 2003, and was a milestone in the economy’s energy
sector development. The strategy identified the economy’s long-term energy policy and the mechanisms for
its realisation. The current revised Energy Strategy of Russia 2030 was adopted in November 2009 (IES,2010). The new version of the strategy was updated to include new realities and priorities in the energy
sector as affected by the global recession. The strategy is a framework within which more detailed industryoriented medium-term and short-term programs can be developed.
In 2015, the Russian Government continued to work on the revised version of the Strategy 2035, but
the strategic objective of Russia’s external energy policy is unlikely to change. The objective will continue tobe 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.
To achieve this, Russia will implement several measures to improve the security of domestic energy
consumption and energy export obligations, and will make efficiency improvements along the entire energy
supply chain. This will include the development of new hydrocarbon provinces in remote areas and offshore.
It will also include the rehabilitation, modernisation and development of an energy infrastructure, including
the construction of additional trunk oil and gas pipelines, to enhance the economy’s energy export capacity.
Furthermore, to better integrate Russia into the world energy markets, export delivery markets will bediversified. It is anticipated that at least 27% of Russia’s total energy exports in 2030 will be delivered to theAsia–Pacific region (IES, 2010).
Russia’s nuclear energy industry remains a priority for Russia’s development despite the Fukushima
nuclear accident that occurred in Japan in 2011. The share of domestic nuclear power generation is expected
to continue to increase, with many units being constructed abroad. Russia intends to remain a key player inthe practical implementation of improved nuclear fuel technology. Despite the existing programs forrenewable energy development outlined in the Energy Strategy 2030, the economic efficiency of renewableenergy projects is still lower than that of fossil fuels.
The 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 (about 335 tonnes of oil equivalent per million
USD in 2009) needs to be one of the main objectives of the Russian energy policy. This would improve thecompetitiveness of the domestic industry in the global market, and stimulate Russia’s economic
development.
Perhaps the most important measures in the Energy Strategy 2030 are directed towards developing
energy market institutions, such as fair pricing mechanisms and transparent trading principles, while ensuring
the availability of sufficient energy transportation infrastructure. State participation in energy sector
development will mainly comprise supporting innovative developments in the energy sector, as well as
providing a stable institutional environment for the effective functioning of the sector (IES, 2010).
Under the general framework of the Energy Strategy 2030, medium- and long-term programs andindustry-wide schemes are being developed. These include the Federal Program 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 the development of the oil industry up to 2020 was approved. This
provides for the comprehensive development of the oil sector—exploration and utilisation of associatedpetroleum 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 gas industry
development in the long term. 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 Program to develop the natural gas fields andbuild extensive trunk gas pipelines in Eastern Siberia and the Russian Far East up to 2030. The program
also includes building export pipelines to the East Asian economies. Gazprom, the state gas monopoly andthe owner of the economy-wide gas pipeline system, is the coordinator of the program and is responsible
for conducting long-term sales contracts for natural gas deliveries.
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In 2011, the Ministry of Energy forwarded to the Russian Government the second phase development
plan up to 2030 for the economy’s gas and petrochemical industry. This includes an updated general planfor the development of key oil and gas investment projects; an updated program 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 program for developing
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 program is to realise potential competitive advantages for
Russian coal companies while implementing the government’s long-term energy policy.
In November 2010, the Federal Targeted Program (FTP) on Energy Saving and Energy Efficiency
Improvement 2020 was approved by the government, which is concerned with energy policy formulation.
The draft ‘General Scheme for the Natural Gas Industry Development 2030’ will be a major development
stimulus for Russia’s energy sector, considering the soaring importance of the gas industry in theinternational stage and that of natural gas in the economy’s primary energy supply. In addition, 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 amended on an annual basis
and serves as a seven-year outlook for generation and transmission line projects. It includes an outlook forelectricity demand by region, maximum loads, generation capacity reserves, power exchange, retirement ofold facilities, maintenance, retrofitting and commissioning of new generation and transmission facilities withmore than 5 megawatts (MW) capacity/110 kilovolts (kV) and higher voltage, respectively.
LAWS AND REGULATIONS

The basic laws on specific energy-related industries are either being implemented or developed. These acting
laws include:Subsoil (since February 1992);

Price Control for Electricity and Heat Supply (since April 1995);

Natural Monopolies (since August 1995);

Production Sharing Agreements (since December 1995);

Energy Conservation (since April 1996);



Gas Supply (since March 1999), Power Industry (since March 2003);



Nuclear Industry (since February 2007);Heat Supply (since July 2010); andEnergy Conservation and Increase of Energy Efficiency (since August 2010).

The last law is the logical extension of the Power Industry law because the major sources of heat supply
in Russia are cogeneration plants (CHP), where electricity is a by-product of residential and industrial heat
supply. However, while crude oil extraction and refining is an important industry in Russia, the draft of theoil law is still being developed in light of its international influence and the growing domestic economic andsocial challenges.
As a rule, the Ministry of Energy is responsible for issuing regulations and instructions, etc., to enforce
the smooth implementation of the basic energy laws and to coordinate current economic development withthe long-term energy policy. Other major government institutions actively participate in the development
and implementation of the regulatory framework regarding energy consumption and energy supply, and theexport and import of energy. The major federal government institutions involved in the development andendorsement of Russia’s energy policy and its regulatory framework include:

Ministry of Energy;

Ministry of Natural Resources and Environmental Protection:oFederal Subsoil Resources Management Agency;oFederal Water Resources Agency; andoFederal Supervisory Natural Resources Management Service;179

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

Ministry of Industry and Trade;Federal Antimonopoly Service;Federal Customs Service; andFederal Tariff Service.

T H E R U S S I AN F E D E RAT I ON

ENERGY SECURITY

Russia considers issues related to energy security a global phenomenon. Due to the increasing
interdependence of energy producers, importers and transition economies, improving partnership relations
is regarded as an effective mechanism for international energy security. The key approach is to coordinate
the actions of energy producers and consumers 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 thebalance 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 to
improving the global energy security. The development of an international infrastructure for the reliable
maintenance of the nuclear fuel cycle, under strict International Atomic Energy Agency (IAEA) supervision,is another Russian contribution to the improvement of the 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 is controlling the tariff setting fornatural monopolies—power transmission lines and pipelines (gas, crude oil, petroleum products
transportation systems and heat supply for residential and commercial sectors) as well as energy tariffs inremote and isolated areas. The authorities are authorised to set maximum regional tariffs for natural gas,
electricity and centralised heat supply. One of the objectives of the Energy Strategy 2030 of Russia is tocomplete the full liberalisation of domestic energy markets, where at least 20% of the energy should betraded on commodity exchanges.
In 2006, the simultaneous liberalisation of natural gas and electricity prices by 2011 was approved.
Deregulating both markets is important as 50% of the total electricity generation is from natural gas, andnearly 45% of the primary gas supply is for the power industry. However, due to social issues, the regulated
tariff for residential energy supply will remain even after 2014.
The oil market in Russia has been deregulated since the 1990s, but crude oil and petroleum trading is
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 fuelmarkets. 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 wasliberalised, with similar institutions to 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 then been extended. The government
will maintain control over the residential and commercial energy tariffs to gradually eliminate the crosssubsidies.
OIL AND GAS

Russia’s oil and gas industry was privatised in the 1990s. However, the government retained control overmajor oil companies and crude oil and petroleum trunk pipelines, and owns 73% of the shares of Russia’s
biggest gas company, Gazprom.
The oil sector is heavily controlled by the government and this control increased after the state-owned
Rosneft takeover of TNK-BP. The USD 55 billion merger in 2013 created the world’s largest listed oilcompany with a daily output of 4.6 million barrels in oil-equivalent terms (Reuters, 2013).

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As of 2015, the oil industry in Russia comprised 10 vertically integrated companies (VIC) 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 owned by VIC, nine companies not
owned by VIC and 34 small refineries with the total refining capacity of 312 Mt of crude oil per year. Afterthe merger of the crude oil and petroleum products pipeline companies Transneft and Transnefteprodukt,
the state controlled 75% of the combined company’s shares. Private oil pipelines do exist in Russia—themost important being the Caspian Pipeline Consortium for crude oil transit from Kazakhstan to the BlackSea ports—but other private pipelines operate in the European part of Russia and in Siberia.
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 vertically integrated companies (13%).
International oil companies, such as ConocoPhillips, ExxonMobil, Royal Dutch Shell, BP, CNPC andTotal, hold up to 10 billion barrels of oil and natural gas reserves in Russia through their stake in state andprivate companies, and produce at least 14% of the economy’s crude oil and 7% of its natural gas. Foreign
investments accounted for USD 52 billion worth cumulative investments in the Russian energy sector fromJanuary 2000 to June 2010.
At the beginning of 2001, there were no Russian oil/petroleum export facilities on the shores of theBaltic Sea. Since then, the Baltic Pipeline System (BTS) and the new Primorsk and Vysotsk oil export
terminals have been developed. The general capacity of this system reached 75 Mt in 2006. In July 2009,
work began on the construction of BTS-2, which will be able to deliver 50 Mt to the new oil export facilities
at the Ust-Luga port on the Baltic Sea.
Refining volumes are expected to stay flat over the next decade, but quality will be a key issue. Gas
developments are planned to increase the share of independent producers, that is, other than Gazprom, toabout 30% by 2030. The Nord Stream pipeline helps maintain Russia’s traditional European market, butmore gas trunk pipelines are needed to tap into the Asian market, specifically China. New LNG projects inthe European Arctic, like those on the Yamal Peninsula, are considered an important means of delivering
natural gas to international markets.
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 company and is almost
entirely privatised.
As of 2013, 202 coal enterprises were operational in the Russian coal industry (84 mines and 118 openpit mines), with a total annual production capacity of 350 Mt. Coal processing is carried out by 56 processing
plants and mechanical installations.
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 restrictions on exporting coal,
but the geographical size of Russia’s vast economy requires coal to be transported over long distances. Coalis the single largest commodity transported by Russia’s railway network, accounting for almost 30% of its
total freight.
ELECTRICITY

Russia started restructuring the 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
generation and regional power distribution companies were privatised before July 2008. From July 2008, thegeneration and transmission assets in Russia have been separated under binding regulations. Generation
assets are 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, with one state-owned holding company, RusHydro,
which controls over 53 hydropower plants. TGCs manage facilities in neighbouring regions. The initialdesign of the WGCs provided them with roughly equal starting conditions in the market, with respect toinstalled capacity, 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, while 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, in which the threshold is less
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than 20% of the transmission line capacity per company. The wholesale power market infrastructure
includes the following 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 ʻAdministrator of Trading System of the Wholesale Power Marketʼ
(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 the organisation of trade, the wholesale power market, ensuring
the execution 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, which was 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.
In monetary terms, the market shares needed to maintain the system’s power reliability are 48% ofelectricity sales, 47% of power sales and 5% of services sales.
The free electricity trading market (one-day forward) was launched in November 2003 within theframework of the Federal Wholesale Electricity Market (ʻFOREMʼ). In September 2006, the regulated
sector of the wholesale market was replaced by a system of contracts to be concluded between the buyers
and sellers of electricity and electric power. In the FOREM, power generators and importers sell electricity
and power 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 enduse 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. It is expected to become the major method for calculating middle-term tariffs.
The methodology is regarded as transparent and provides incentives for investors to rehabilitate andimprove the operations 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 was introduced in July 2010
to create investment opportunities, minimise energy losses and subsidies and provide business incentives. A
transparent market for the heat supply will provide additional incentives to develop combined heat andpower facilities as a primary option for generators. The use of registration equipment will be compulsory
for new buildings. The industry’s restructuring will be a cornerstone for energy conservation activities andprovide significant business opportunities for both domestic and international businesses.
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. It 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 are still 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
fuel services to nuclear energy plant construction and electricity production. The company has up to 16%of the world’s market for new nuclear energy plant construction, and is affiliated with Tenex (40% share of
the world’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).
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TRANSPORT

Russia’s economy faces challenges due to the underdevelopment of its transport infrastructure. In particular,
the current condition of Russian airports and air transport facilities provides insufficient capacity and slows
the performance of air transportation services. Further modernisation of air and rail transport is planned inconnection with Russia’s programs for the 2018 Football World Cup and the 2020 World Expo.
The total length of Russian roads in 2013 was 1 395 601 km, 70.5% of which were paved. The member
economy had only 30 146 km of high-speed divided highways connecting big cities (GKS, 2016). Further
development of highways will be necessary to connect big cities.
Russia has a state railway system with a total length of 85 641 km, but only some cities have high-speed
train services. Almost all towns in Russia, regardless of size, are served by regional bus services. Subway
systems have been introduced in seven of Russia’s major cities, and all cities have extensive city bus 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 249 700 km in 2010, of which 70% is gas pipeline, 22%
oil pipeline and the remaining 8% oil products pipeline.
FISCAL REGIME AND INVESTMENT

In 2007, dozens of oil and gas fields were decreed to be ‘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 is applied to oilfields with reserves
larger than 70 Mt and gas fields with reserves larger than 50 bcm. In March 2009, regulations were adopted
for the compensation of costs associated with the discovery and exploration of deposits under exploration
licenses, the further development of which is prohibited due to their strategic status.
From 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 creates favourable
conditions for the development of new capital-intensive projects in remote areas that lack an energy
infrastructure. From 1 January 2010, zero export duty was introduced for crude oil extracted from East
Siberia oilfields to maintain a 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 the new rules, the duty on oil exports decreased by 7.4% to USD 411 per tonne, and fees for lightand heavy petroleum products were set at 66% duty on crude oil. For several fields in Eastern Siberia andthe North Caspian, there will be a preferential export duty, which, as of October 2011, is set at USD 204
per tonne. A reduced duty on crude oil is achieved by changing the formula for calculating it. According to
the norms of the ‘60–66’, from now on duty on crude oil will be at 65% and 60% of the difference between
the market price and standard price of oil at a rate of USD 182 per tonne.
The size of the duty on exports of gasoline is set at 90% of the duty on crude oil. Before May 2011,
the duty on exports of gasoline was 60% of the duty on oil, but because of the sharp rise in home prices andgasoline shortages in some regions, it was increased to 90%. It is believed that such new fees will allow oilcompanies to obtain additional funds for the exploration of new fields and will thus increase current oil
production. In addition, the unification of tariffs on exports 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 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 that of most developed economies.
The introduction of effective 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 one of the priority areas of the Energy Strategy 2030.
On 23 November 2009, the federal government adopted a Law on Energy Conservation and Increaseof Energy Efficiency to take effect from 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 new183

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federal law sets a legal framework and targets for 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.
These measures include:

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 interagency 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, etc.).

In addition to the new federal law, on 27 December 2010 the federal government adopted (FTP) on
Energy Saving and Energy Efficiency Improvement 2020. The Program will be carried out in two stages:
from 2011–15, and from 2016–20. The energy intensity of Russia’s economy is expected to decline by atleast 7.4% by 2015 and 14% by 2020. In addition, the program outlines measures to achieve the federal
target of ‘at least a 40%’ decrease in the economy’s energy intensity by 2020, compared to 2007, through therational use of energy resources and other measures to encourage EE and energy conservation. These
measures include the enhancement and coordination of federal, regional and municipal EE and energysaving programs; establishment of information dissemination, public awareness and the promotion of
education initiatives; introduction of financial measures to promote the efficient use of energy; and a 4.5%
target for the share of renewable energy in power generation by 2020.
In accordance with the EE federal law and the Program, all regions are required to prepare their own
respective regional programs on energy efficiency improvements. The implementation of these programs
will be financed jointly by regional governments and the federal government.
On 22 December 2009, the government established the Federal Energy Agency within the Ministry ofEnergy, which has 70 regional branches. Its key tasks focus on operating the federal EE and energy-saving
information system; and administering, monitoring and coordinating efforts for the effective
implementation of the EE law, the FTP and other measures for improving EE and energy 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 applied across all regions. In
addition, technical potential exists to save almost half of Russia’s primary energy demand through energy
conservation (ME, 2015). However, a major impediment for businesses to improve their EE is the absenceof appropriate financial mechanisms.
The regulatory framework described in the FTP on Energy Saving and Energy Efficiency
Improvement 2020 estimates that the total investments into EE up to 2020 will be approximately
RUB 9.3 trillion (USD 320 billion), amounting to 8% from governments and 92% from private investments.
The economic effect of such investments up to 2030 is expected to exceed RUB 26.5 trillion (overUSD 880 billion). Governments at different levels will provide more than USD 10 billion in guarantees onloans for businesses involved in activities to improve EE in either the industrial, residential or commercial
sectors.
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RENEWABLE ENERGY

The technical potential for renewable energy (RE), excluding large hydro, in Russia is estimated at
4 400 Mtoe per year, or almost eight times more than Russia’s current TFEC. 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’s 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 (FiT) and subsidies forgrid connection. The government is expected to develop regulations for FiT and grid connection subsidies,for the compulsory share of RE in the wholesale market to be purchased by electricity consumers, and forbringing 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 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. All of the Russian, CommonwealthIndependent States and Eastern European nuclear reactors are supplied by Tenex—the state company
responsible for the nuclear fuel cycle business. In addition, Tenex meets 40% of the nuclear fuelrequirements of the United States, 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 the
IUEC 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 program for
the IUEC’s expansion at Angarsk by 2015 was developed. The program 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Full internationalisation with the involvement of many customer economies under the IAEA’s
auspices.

Russia also announced that guaranteed reserves of low-enriched uranium hexafluoride—equivalent to
two 1 000 MW reactor loads—would be created at the IUEC as a fuel bank available under the IAEA’s
control. The first phase of the capacity enhancement was scheduled for 2011, when one million separation
work units were expected to be commissioned, with a target of five million expected to be achieved in 2017.
In November 2009, the IAEA’s Board of Governors adopted a resolution supporting a Russian
initiative to establish and maintain in Russia a stock of low-enriched uranium (LEU), and to carry LEU
supplies for the IAEA member states. This was a breakthrough in the establishment of an international
system guaranteeing reliable nuclear energy plant fuel supplies and lowering the risks of the proliferation ofsensitive nuclear technologies. It was suggested that the stock will be managed by the IUEC and transferredunder contract from the IUEC to the IAEA when an appropriate supply request is obtained from the IAEA.
One major concern for world energy development is nuclear safety, which has become a key agenda
after the Fukushima accident in Japan. Russia has adopted the ‘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 on
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environmental protection and the use of nuclear energy were amended in June 2010. Since 2007, the expired
contracts for depleted uranium hexafluoride enrichment/conversion have not been extended.
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). The prospects for future international cooperation in the nuclear energy
industry are promising; the construction of 35 reactors in 15 economies is in the pipeline, and contracts havebeen signed for 19 reactors in seven economies.
For the next 20 to 25 years, three core reactor technologies have been chosen for nuclear energy
development in Russia:


Water reactors, VVER type, and their modification and advanced development;

Sodium fast neutron reactors; andHigh-temperature helium reactors.
CLIMATE CHANGE

Russia’s key environmental and climate policy is outlined in the Climate Doctrine and Environmental Policy
until 2030 (Kremlin, 2009; 2012). In November 2004, Russia ratified the Kyoto Protocol (UN COP3). Thisdecision confirmed Russia’s strong commitment to addressing climate change and working with theinternational community on dealing with this global challenge. Ratification by Russia satisfied the ‘55%’
clause and brought the Kyoto Protocol into force, effective from 16 February 2005.
Russia is considered the world’s largest potential host for ‘joint implementation’ projects under the
Kyoto Protocol. In May 2007, procedures for the approval and verification of Russia-based joint
implementation greenhouse gas (GHG) reduction projects were adopted. Responsibilities were assigned forsetting up and keeping the Registry of Carbon Units, thus paving the 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 by 50% from the 1990 level by 2050. These emission reductions are contingent on the following
conditions: appropriate accounting of the contribution of emissions reductions from Russia’s forestry
activities will be introduced, and 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, since the biggest polluters—US, China and India—have not joined it.
In April 2016, the Russian Government has 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.
N OTA B L E E N E RG Y D E V E L O P M E N T S
PROGRAM ON ENERGY SAVING AND ENERGY EFFICIENCY IMPROVEMENT UP TO
2020

The main objective of the State Program on Energy Saving and Energy Efficiency Improvement 2020 is to
reduce the energy intensity of the GDP of Russia by 14%. This is expected to combine with other factors
to provide an overall reduction of 40% in the energy intensity of the GDP in the period 2007–20. Other
expected results of the program are savings of 330 bcm of natural gas (301 Mtoe), 630 billion kWh ofelectricity (54 Mtoe), 1 550 million Gcal of heat (155 Mtoe) and 17 Mt of petroleum products (19 Mtoe)
through the duration of the program.
The program also aims for a significant reduction in energy costs and to ensure the competitivenessand financial stability of the Russian economy, the provision of high quality energy services at affordable
prices and reducing GHG emissions, thereby strengthening the health of the population. The funding of
the program is divided between RUB 70 billion from the federal budget, RUB 625 billion from budgets of
the regions of Russia and RUB 8.8 trillion from extra budgetary sources.

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Gazprom has adopted the FTP on Energy Saving and Energy Efficiency Improvement 2020, whichshould lead to a 1.2% annual decline in energy consumption by this giant energy company up to 2020.
Gazprom’s current energy demand for natural gas extraction, processing and transportation is close to 10%of the economy’s total extracted energy. The major share of improvements is expected from measuresrelated to its pipeline operations (estimations are up to 85%).
POWER MARKET DEVELOPMENT

The Ministry of Energy presented concepts for a program of power sector modernisation up to 2020. The
central theme of this modernisation is to introduce new technologies, both domestic and imported,
increasing the reliability of the electricity supply and energy security.
OIL AND GAS DEVELOPMENTIn May 2014, OAO Gazprom and China National Petroleum Corporation (CNPC) inked a historic
agreement on Purchase and Sale Agreement for the Russian gas supply via the eastern route. The 30-year
contract provides for gas supplies amounting to 38 bcm of gas per year.
As part of the APEC summit in Beijing in November 2014, several documents related to the RussianChinese cooperation in the energy sector were signed in the presence of the Russian President Vladimir
Putin and Chinese President Xi Jinping.
OAO Gazprom and CNPC signed a Framework Agreement on gas supplies via the western route.
In particular, the document reflects such conditions as the volume and terms of supply, the take-or-pay level
and the location of the gas delivery point on the border. The Framework Agreement defines the scheduleof compiling a gas purchase and sale agreement, a technical agreement and an intergovernmental agreementon the western route. In addition, Alexey Miller and Wang Yilin, Chairman of the CNOOC Boardof Directors signed a confidential Memorandum of Understanding for cooperation in the oil and gas sector(Gazprom, 2014).
COAL INDUSTRY DEVELOPMENT

In the framework of the Russian strategy for developing the coal sector through 2030, as mapped out by
the Russian Energy Ministry, Rostech, the Russian state-controlled technology corporation, signed anagreement with China’s Shenhua Group, the largest producer of coal in the world, to explore and develop
coal deposits in Russia’s Siberia and Far East.
The Russian strategy for developing the coal sector through 2030 foresees transferring the centre of
the coal production to Russia’s eastern regions to supply Asian markets, which now constitute 80% of theworld’s consumption.
NUCLEAR AND RENEWABLE ENERGY DEVELOPMENT

Russia will join the International Renewable Energy Agency (IRENA). Accession to IRENA will provide
Russia wide access to the existing practice of using and implementing renewable energy sources, results of
the latest studies and will allow Russia to participate in the elaboration of international standards, as well as
influence the renewable energy sector’s development worldwide.
ENERGY SECURITY IMPROVEMENTS

In late 2011, the Ministry of Energy approved a joint statement between Russia and the International Energy
Agency (IEA), agreeing on regular bilateral consultations. Those consultations will strengthen theircollaboration in an effort to maximise the contribution of the energy sector in reconstruction and economic
development, enhance global energy security and reduce the environmental impact of energy production
and consumption.
IMPORT SUBSTITUTION

In 2014, the government approved a plan of supporting the import substitution in industry, including thefuel and energy sectors. This involves actions to increase the share of local content, domestic workforce,engineering services and domestically developed computer services.

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REFERENCES

BP (2015), Statistical Review of World Energy 2015, www.bp.com/content/dam/bp/excel/energyeconomics/statistical-review-2015/bp-statistical-review-of-world-energy-2015-workbook.xlsx.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
Gazprom (2014), Russia and China Sign Framework Agreement on Gas Supplies via Western Route,www.gazprom.com/press/news/2014/november/article205898/.
GKS (Federal State Statistics Service) (2015), Russia in Figures – 2015,www.gks.ru/bgd/regl/b15_12/Main.htm.
–– (2016), Lengths of communication routes of the Russian Federation,
http://www.gks.ru/free_doc/new_site/business/trans-sv/prot.xls.
IES (Institute of Energy Strategy) (2010), Energy Strategy of Russia for the Period up to 2030,
www.energystrategy.ru/projects/docs/ES-2030 (Eng).pdf.
Kremlin (2009), Climate Doctrine of the Russian Federation, http://kremlin.ru/events/president/news/6365.
–– (2012), Environmental Policy of the Russian Federation until 2030,
http://kremlin.ru/events/president/news/15177.
ME (Ministry of Energy) (2014), Actual Problems and Directions of Russian Fuel & Energy Complex Development,
www.minenergo.gov.ru.
–– (2015), Annual Report on Russian Fuel and Energy Sector Development,
http://minenergo.gov.ru/system/download-pdf/92/42.
NEA (Nuclear Energy Agency) (2014), Uranium 2014: Resources, Production and Demand, https://www.oecdnea.org/ndd/pubs/2014/7209-uranium-2014.pdf.
Reuters (2013), www.reuters.com/article/2013/03/21/us-rosneft-tnkbp-deal-idUSBRE92K0IZ20130321.
RG (Rossijskaya Gazeta) (2016), The Government has approved the Paris Agreement on climate change (in Russian),
http://rg.ru/2016/04/21/rg-rossiia-24-kabmin-odobril-soglashenie-ob-izmenenii-klimata.html.
USEFUL LINKS
OFFICIAL BODIES OF RUSSIA

Structure of the Government of Russia—http://government.ru/en/
Ministry of Energy—www.minenergo.gov.ru/
Ministry of Natural Resources—www.mnr.gov.ru/
Federal Service on Ecological, Technological and Nuclear Supervision—www.gosnadzor.ru/
Ministry of Economic Development—www.economy.gov.ru/minec/main/
Federal State Statistics Service—www.gks.ru/
Ministry of Industry and Trade—www.minprom.gov.ru/
Federal Agency on Technical Regulating and Metrology—www.gost.ru/wps/portal/pages.en.Main
Federal Antimonopoly Service—www.fas.gov.ru/
Federal Customs Service—www.russian-customs.org/
Federal Tariff Service—www.fstrf.ru/

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ENERGY-RELATED NON-PROFIT AND STATE-OWNED BUSINESS INSTITUTIONSAtomEnergoProm—www.atomenergoprom.ru/en/
Federal Power Grids—www.fsk-ees.ru/
Non-commercial Partnership of the Wholesale Power Market—www.np-ats.ru/
Gazprom—www.gazprom.ru/
Rosneft—www.rosneft.ru/
RusHydro—www.rushydro.ru/
Transneft—www.transneft.ru/
Transnefteprodukt—www.transnefteprodukt.ru
STATE ENERGY-POLICY-RELATED RESEARCH CENTRESInstitute of Energy Strategy—www.energystrategy.ru/
Centre for Energy Policy—www.cenef.ru/
Energy Research Institute of the RAS—www.eriras.ru/
Energy Systems Institute of the SB of RAS—www.sei.irk.ru/eng/index.htm
MAJOR ENERGY-RELATED MEDIA IN RUSSIA

Official newspaper, Rossiyskaya Gazeta—www.rg.ru/
Central Dispatching Unit of the Fuel and Energy Complex—www.riatec.ru/

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S I N G AP O RESINGAPOREI N T ROD U C T I ON

Singapore is located south of the Malaysia Peninsula between the Strait of Malacca and the South China Sea.
This South-East Asian economy’s land area was 714 square kilometres (km2) in 2013 with a population of 5.4
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 of which a significant part isreclaimed land. The economy’s impressive economic success is due to certain factors including turning itself intoa regional hub for tourism, financial activities, shipbuilding, petroleum and related equipment, biotechnology,
high tech and solar energy, and its expanding role in international cargo and fuel shipping.
The economy’s gross domestic product (GDP) of USD 414 billion and per capita of USD 76 149 (2010
USD purchasing power parity [PPP]) in 2013 reflected growth of 4.4% and 2.7%, respectively, from 2012 levels.
Services producing industries accounted for the largest GDP share (66%), with the biggest sub-sector
represented by wholesale and retail trade (18%), followed by goods-producing industries (23%), with
manufacturing and housing representing 17% and 4.3%, respectively (SingStat, 2015a).
Singapore’s exports in 2013 amounted to USD 513 billion of which the respective shares of domestic
exports (USD 274 billion) and re-exports (USD 239 billion) were 53% and 47%. Non-oil products accounted forthe bulk of the exports (76%), with machinery and equipment representing the largest share (46%), followed bychemicals and chemical products (12%), miscellaneous manufactured articles (8.7%), manufactured goods (3.2%)
and food, beverages and tobacco (2.2%), leaving the rest for miscellaneous transaction articles (1.2%), crudematerials (0.7%) and animal and vegetable oils (0.1%). Oil exports (refined oil products and lubricants) accounted
for 24% of the economy’s exports (SingStat, 2015b).
Table 1: Key data and economic profile, 2013
Key data

Energy reserves

Area (km2)714

Oil (billion barrels)–

Population (million)

5.4

Gas (billion cubic metres)–

GDP (2010 USD billion PPP)

414

Coal (million tonnes)–

GDP (2010 USD PPP per capita)

76 149Uranium (kilotonnes U)–

Source: EGEDA (2015).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

Singapore imports all its crude fossil fuel requirements. The economy’s total primary energy supply (TPES) in
2013 was 26 592 kilotonnes of oil equivalent (ktoe) (EGEDA, 2015). Oil had the largest share (over 60%) andexperienced an increase of 5.8% over 2012, from 15 117 ktoe to 16 006 ktoe. Natural gas had a 36% share (9653 ktoe), with a modest growth (5%) compared to the preceding year when gas experienced a substantial
increase of almost 39% over its 2010 share. Coal’s share increased tenfold to 264 ktoe from 2012, when theeconomy imported coal (25 ktoe) for the first time, but it remained only a small share (0.9%) of the total(EGEDA, 2015).
Singapore’s total imports of energy (crude oil, petroleum products, gas and coal) in 2013 were 159 314
ktoe, which included supplies to meet its energy requirements as well as those to meet the needs of its oil
refineries whose refined products are mainly exported (ESTO, 2015). Of these imports and their produced
refined products, about 53% (84 168 ktoe) were exported (ESTO, 2015). Most of the remaining imports wereused at home for marine bunkering (26%; 41 995 ktoe) and aviation bunkering (4.4%; 7 165 ktoe), signifying therole of Singapore in international shipping and aviation (ESTO, 2015).
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The economy’s electricity generation in 2013 reached 47 964 gigawatt hours (GWh), showing an increaseof 2.2% over 2012 (46 915 GWh) (EGEDA, 2015). The peak demand for electricity of 6 814 megawatts (MW)was slightly larger than that in 2012 (6 639 MW) (EMA, 2015a).
Thermal power plants operated by Singapore’s six main power producers (44 555 GWh) accounted for thebulk of its total power generation (93%) in 2013. Auto-producers accounted for the remaining 7.1%
(3 409 GWh) of which the share of waste-to-energy was 3.5%, reflecting a significant increase compared to 2012
(2.7%). Grid-connected photovoltaic (PV) installations make a very small contribution to the economy’s power
generation despite the substantial growth in their installed capacity in 2013 (15 megawatts peak [MWp]), equal
to about a 50% increase over 2012 (10 MWp) (EMA, 2015a).
The licensed power generation capacity of thermal power plants in 2013 was 10 964.3 MW, showing asignificant increase of 12% over 2012 (9 831 MW). Of this, the combined capacity of the cycle gas turbine power
plants was 8 082 MW, followed by steam turbine plants (2 702 MW) and open cycle gas turbine plants (180 MW)(EMA, 2015a). Waste-to-energy plants generated 257 MW of electricity (EMA, 2015a).
The respective shares of Singapore’s residential and non-residential grid-connected solar PV systeminstallations in 2013 were 15 MWp and 1 MWp (EMA, 2015a).
Natural gas dominated Singapore’s fuel mix for power generation in that year, with a share of 92%, leaving
small shares for petroleum products (5%) and other fuels (3.5%), mainly waste with a very small contribution ofcoal and solar (EMA, 2015a). Compared to 2012, the power mix reflected a major increase in the share of gas(7.2%) and a relatively significant increase in that of others, mainly, waste-to-energy (0.8%), but a large decreasein that of oil (8%).
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Indigenous production

670 Industry sector

Net imports and others
Total primary energy supply
CoalPower generation (GWh)
11 114 Total power generation

47 96475 023 Transport sector

2 357

Thermal

44 55526 592 Other sectors

2 306

Hydro

–

264 Non-energy–

Nuclear–15 777

Others

3 409

Oil

16 006 Total final energy consumption

Gas

9 653

Coal

129

Others670

Oil

10 343

Gas

1 442

Electricity and others

3 862

Source: EGEDA (2015).
FINAL ENERGY CONSUMPTION

Singapore’s total final energy consumption (FEC) was 15 777 ktoe in 2013, increasing 26% from 2012. Oil
accounted for the bulk of this (10 343 ktoe), with a share of about 66%, followed by electricity and others (24%,
3 863 ktoe), natural gas (9.1%, 1 442 ktoe) and coal (0.8%, 129 ktoe). In terms of sector consumption, industry
was 70%, transport 15% and others 15% (EGEDA, 2015).
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 the APEC leaders in 2011. However, the economy’s efforts to reduce its energy
intensity began earlier. In 2009, it set for itself an ambitious 35% reduction target by 2035, whereas the APEC
target was 25% by 2030 (APEC, 2014). Singapore’s Inter-Ministerial Committee on Sustainable Development(IMCSD) declared that target in the Sustainable Singapore Blueprint as a national strategy for its sustainable
development (MEWR, 2014).
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Various government initiatives have aimed at helping the economy achieve its commitment to APEC’s
target of 2011. Recent examples include its Energy Conservation Act 2013 (ECA), which focuses on a range ofinter-related energy issues including improving energy conservation, efficiency and intensity, while reducing CO 2
emissions (GBS, 2014). The Act aims to help Singapore achieve its intensity reduction target by improving theenergy performance of the economy’s companies (EMA, 2012). Other initiatives seeking improvements inenergy conservations and efficiencies are discussed in this chapter.
Singapore experienced a slight increase (1.1%) in its energy intensity (energy consumption per unit of GDP
growth) in 2013 over that of 2012 when it significantly reduced its energy intensity (2%) over the preceding year.
The final energy demand in 2013 rose 21% over 2012, with industry and transportation representing the major
contributors to this increase, with the shares of 24% and 27%, respectively.
Table 3: Energy intensity analysis, 2013
Energy Intensity (toe/million USD)

Energy2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

64

65

1.1

Total final energy consumption

32

38

21

Industry

22

27

24

Transportation

4.5

5.7

27

Other sectors

5.4

5.6

3.3

Non-energy

–

–

–

Source: EGEDA (2015).
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKSingapore has implemented various energy policies to ensure that it will meet its energy requirements while
taking into considerations energy-related challenges and opportunities. The recent major ones are detailed below.
The Economic Strategies Committee’s (ESC) Subcommittee on Ensuring Energy Resilience andSustainable Growth released a report in 2010, which made the following recommendations as the key strategies
for Singapore to meet its energy policy objectives (ESC, 2010):
Strategy 1: Diversify Energy Supplies. A diversified energy portfolio is essential to safeguard
Singapore’s energy security. Singapore’s Liquefied Natural Gas (LNG) terminal, which commenced
operations in May 2013, helps diversify energy sources as it allows the import of LNG globally.
Singapore is also studying other medium- to long-term energy options such as electricity imports andrenewables to further diversify its energy mix.

Strategy 2: Enhance Infrastructure and Systems. Singapore continues to improve the liberalisationof its electricity and gas markets to achieve greater competition in energy prices and improve efficiency.
Investing in critical energy infrastructure ahead of demand and enhancing existing infrastructure hashelped make its energy markets more efficient, open new areas for economic development andstrengthen energy security. Singapore is currently conducting an Intelligent Energy System (IES) pilotthat is testing and evaluating smart grid technologies and related applications that will enable consumers
to manage their electricity use more efficiently.

Strategy 3: Improve energy efficiency. Energy efficiency (EE) underpins Singapore’s efforts to
reduce its energy and carbon footprint. Businesses and households can benefit from energy and costsavings through various EE measures. However, market barriers such as lack of awareness and limited
financing schemes are impeding EE implementation and investments by businesses. To address thesebarriers and promote more efficient energy use among consumers, the Government administers several
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programs coordinated by the Energy Efficiency Program Office (E2PO) to help companies reduce
their energy costs and improve their competitiveness, while reducing the economy’s carbon footprint.
Strategy 4: Strengthen the Green Economy. To meet the economy’s energy challenges and facilitate
the growth of the clean energy sector, Singapore will continue to invest in research, development anddemonstration, facilities and manpower development as key enablers. This effort is through interagency collaborations on energy research, development and demonstration (RD&D), such as theEnergy National Innovation Challenge (NIC) and the Energy Innovation Program Office (EIPO), andthrough private-public partnership initiatives to enhance manpower capabilities for the power utilities
sector.

Strategy 5: Pricing Energy Right. Price signals influence energy consumption and investment
decisions to achieve efficiency and conservation. Singapore does not subsidise consumption of energy
as such subsidies lead to the inefficient use of a scarce and precious resource. This is to ensure that theeconomy is able to adapt to the rising cost of energy and to a carbon-constrained world.

In July 2014, the Energy Market Authority (EMA) issued a Final Determination Paper making several
enhancements to the market and regulatory framework for intermittent generation sources, such as solar energy,
as follows (EMA, 2014).
After careful consideration of the feedback received from solar industry players, electricity market
licensees, companies and the public, the EMA is implementing the following key enhancements set out
in this determination paper:
Clarified the licensing requirements for IGS;

Simplified the commissioning procedures for solar PV installations to connect to the grid, while
ensuring safety;Streamlined market participation and settlement to make it easier for IGS to receive payments forexcess electricity exported into the grid; andStreamlined the monitoring requirements for IGS.



It is also important to recognise the characteristics of IGS and its effects on the power system. For
example, IGS output is intermittent as it fluctuates based on weather conditions, cloud cover andshadows. To manage the effects of intermittency, the EMA will adopt a ‘dynamic pathway’ framework
to ensure that there is sufficient reserves (or back-up) capacity in tandem with the growth in IGS
capacity. There will be a further study on the reserves charging mechanism to recognise the intermittent
nature of IGS, as there are trade-offs which need to be carefully considered. To this end, the EMA will
issue a second public consultation paper in Q4 2014 to seek industry feedback on the framework.

Moving forward, the EMA will continue to review the rules in consultation with stakeholders to ensurethat the regulatory framework remains relevant as technologies and business models evolve.

In October 2014, the International Advisory Panel (IAP) emphasised the need for ‘further innovative
policy initiatives and technology development to allow Singapore to meet its growing energy needs and be readyto seize new opportunities in the energy sector’ (MTI, 2014). The IAP was set up by Singapore’s Ministry ofTrade and Industry (MTI) to ‘provide insights and perspectives on emerging trends in the global energy arenaand to advise on the strategic directions for the energy sector in Singapore’ (MTI, 2014). It made the following
suggestions and recommendations based on certain global energy issues of relevance to the economy.
Facilitating Liquefied Natural Gas (LNG) Trading and Strengthening Singapore’s Natural
Gas Position

The IAP noted that the global LNG market would likely double in the next two decades with strong growthin Asia. This will occur in the context of the US unconventional gas revolution, regional gas developments,
international climate change considerations, the shift towards more market-oriented pricing and evolving energy
policy of other countries.
The IAP was of the view that there is an emerging need for supply flexibility and market efficiency in thenatural gas market, particularly in Asia. The panel suggested that given Singapore’s reputation for a stable
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regulatory framework, its political neutrality, existing trading and financial infrastructure and its efficientdecision-making, there is a real prospect of a centre for trading of natural gas in Singapore in collaboration with
regional countries and industry partners.
Noting that other trading hubs took time to develop, the IAP recommended that Singapore take a longterm view and continue to expand its LNG infrastructure and develop ancillary services. Singapore should also
develop trading mechanisms and standards to facilitate gas trading and expand its regional and international
dialogue on gas market opportunities. This will collectively enhance Singapore’s energy security.


Exploring Energy Options

The IAP also supported Singapore’s efforts to facilitate greater deployment of solar energy, welcoming inparticular its decision not to subsidise deployment and its commitment to liberalised markets. The IAP
recognised that solar is at present Singapore’s only technically and economically viable renewable energy source.
It agreed that Singapore’s renewable energy strategy is comprehensive in promoting the integration of solar
energy and accelerating its adoption in the market.
The IAP emphasised the importance of materials research to improve modular and system-level
efficiencies to reduce costs, while developing attractive financing models. In that regard, the IAP commended
the Singapore Government for its consistent efforts in supporting research at the Solar Energy Research Instituteof Singapore (SERIS) and the various institutes of higher learning.
Research Development & Demonstration (RD&D) as a Key Enabler

The IAP supported Singapore’s RD&D strategy to direct investments towards developing solutions acrossboth supply- and demand-side initiatives to assure a reliable, affordable, sustainable and secure energy system.
The panel endorsed Singapore’s RD&D priorities in solar photovoltaics, energy efficiency and new materials inbuildings, and smart infrastructure solutions to address the effects of intermittency of renewable energy. The
IAP encouraged strong collaborations between research institutes and the industry, in line with Singapore’s focus
on applied research and bringing solutions from the laboratory to market.
ENERGY SECURITY

Energy security is of outmost importance for Singapore as a trading economy, a hub for international shipping
and aviation and a major tourist destination, among many other reasons. Therefore, the economy has taken steps
to enhance its energy security within the framework of its geological and geographic restrictions. The latter limit
its options by excluding all types of renewables apart from waste-to-energy and, to a very limited extent, solar
energy as feasible and/or viable ones. Facing this reality, Singapore has sought to increase the share of gas in its
energy requirements as the cleanest type of fossil energy, and diversify its sources of supplies, suppliers andsupply routes as detailed below.
Natural gas is now the major fuel for electricity generation in Singapore as evident in its share (96%) of theeconomy’s power mix in 2015 (EMA, 2015a). Four offshore natural gas pipelines supply Singapore’s piped
natural gas needs. The first gas pipeline, located in the northern part of the main island, was commissioned in1991 and supplies the economy with 4.2 million cubic metres per day (mcm/d) (150 million cubic feet per day[MMcf/D]) of natural gas from Malaysia. Senoko Energy Ltd (formerly known as Senoko Power Ltd) imports
Malaysian gas for its power generation plant. Since January 2001, the second pipeline, from the West Natuna gas
field in Indonesia, has supplied the economy with 9.2 mcm/d (325 MMcf/D) of natural gas. The third pipeline,from South Sumatra, Indonesia, started supplying gas to Singapore in September 2003, and the fourth pipeline,from Malaysia, began its operation in 2007, supplying since that year 3.1 mcm/d (110 MMcf/D) of natural gas,
mainly for power generation. Keppel Gas Pte Ltd is the importer of natural gas for the fourth pipeline.
PowerGas Ltd, a subsidiary of Singapore Power, owns and manages the gas pipeline network conveying
natural gas and town gas. It provides open and non-discriminatory access to the gas pipeline network. SP
PowerGrid Ltd conveys gas and manages the gas pipeline network. SP PowerGrid Ltd is licensed by the EMA
as the gas transport agent.
The diversification of the gas supply has become an important issue, given its large and growing share ofelectricity generation. Towards this end, the Singapore Government announced a plan in 2006 to import LNG
and build the first LNG receiving terminal to meet the rising demand for electricity generation and diversify its
sources of natural gas. PowerGas Ltd was appointed the developer of the LNG terminal in 2007. However, due
to the difficulty of proceeding with the project on a commercial basis, the Singapore Government announced
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its decision to take over the development and ownership of the Singapore LNG terminal in June 2009. As aresult, the EMA formed the Singapore LNG Corporation Pte Ltd (SLNG) to develop, build, own and operate
the LNG terminal. On 8 February 2010, SLNG awarded the contract for the engineering, procurement andconstruction of Singapore’s first LNG terminal.
Singapore completed and commenced commercial operations of the LNG terminal on 7 May 2013, withan initial capacity of 3.5 million tonnes per annum (Mtpa), located at an approximately 40-hectare site on thesouth-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 achieved mechanical completion atthat time (SLNG, 2014a).
The terminal’s capacity will further rise to 11 Mtpa when the fourth tank (under-construction and set forcompletion in 2018) and additional regasification facilities (planned for completion in 2017) are operational(EMA, 2015b). The LNG terminal is designed to have the scalability to provide new services such as LNG
trucking, industrial gas manufacturing and liquid petroleum gas (LPG) imports and exports in the future (SLNG,
2014b).
Singapore has also undertaken major projects apart from LNG to enhance the security of its requiredhydrocarbons.
The economy has initiated a project to build a floating storage facility for oil and petrochemical products.
The initiative, known as the Very Large Floating Structure (VLFS), comprises two rectangular modules, eachwith a storage capacity of 150 000 cubic metres. The VLFS will occupy only seven hectares of foreshore space
as compared to 20 hectares of land for the same storage capacity. This ‘mega-float’ platform, coupled withutilities and amenities support, will boost the Singapore industry’s competitiveness in providing additional
logistic capacity for the refining and petrochemicals and oil trading sectors. The project is not yet realized as ofMarch 2016.
Finally, Singapore has embarked on a project to build South-East Asia’s first underground liquidhydrocarbon storage facility called the ‘Jurong Rock Caverns’, located at a depth of 130 metres under the Banyan
Basin on Jurong Island (JTC, 2014). This project can also be used for other higher value-added petrochemical
processes. Phase One of the project, with a storage capacity of approximately 1.5 million cubic metres, wascompleted September 2014 (SGC, 2014a).
ENERGY TECHNOLOGY/RESEARCH AND DEVELOPMENT

Singapore supports and promotes energy research and development (R&D) for many reasons including thefollowing: developing capabilities to support the clean energy sector as a key growth area; growing a viableindustry that will create jobs; and meeting Singapore’s energy challenges and its sustainable development
objectives. To this end, the National Research Foundation (NRF) allocated SGD 170 million in 2007 and another
SGD 195 million in 2011 to the EIPO (formerly known as the Clean Energy Program Office). In total, the NRF
provided USD 210 million of funds to the EIPO to promote R&D in the energy sector between 2011 and 2015
(EMA, 2015c). Additionally, ‘about $140 million has been set aside for the Energy Innovation Research
Programme’ (EIRP) (EMA, 2015c).
The EIRP, co-led by the EDB (Economic Development Board) and the EMA, is a competitive R&D grant callinitiative under EIPO that aims to strengthen Singapore’s R&D capabilities and address its energy-related
challenges. Between 2012 and 2014, 12 grant calls were launched in areas such as solar, green buildings, power
generation, energy storage, smart grids and gas, and over USD 70 million awarded to various Singapore-based
institutes of higher learning, research institutes and industry. In 2015, the EIPO launched its 13th grant call (RFP
13) under the EIRP as it invited ‘White Papers for R&D Programmes, each comprising multiple projects undera unifying theme to address the following research objective: Innovations to lower the Levelised Cost of
Electricity (LCOE) of solar PV systems in Singapore’ (NUS, 2015a).
The EMA also offered various research grants in 2015 on behalf of the EIRP. They include the Energy
Storage Grant Call 2015 to support ‘innovative solutions in the following domain area: Cost-effective energy
storage innovations that can be effectively deployed in Singapore’ (NUS, 2015b). In partnership with Sembcorp,
the EMA also provided a grant under the Sembcorp-EMA Energy Technology Partnership (SEETP) Grant Call2015 to support research on ‘Domain A: Increasing the accuracy and speed of boiler inspection process for
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defect localisation (Target ≥ 40%) to reduce down time and enhance availability of power plants. Domain B:
Improving the energy efficiency of bio-sludge treatment process (Target ≥20%)’ (NUS, 2015c).
Singapore’s government has supported the establishment of research centres for clean energy under EIPO.
For example, the Solar Energy Research Institute of Singapore (SERIS) was established in 2008 to conductindustry-oriented R&D in solar energy technologies, focusing on materials, components, processes and systems
for solar PV electricity generation and energy-efficient buildings.
EIPO has also supported the establishment of the Energy Research Institute at Nanyang Technological
University (ERI@N), with the objective of advancing research aimed at improving the efficiency of the 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 the Experimental Power Grid Centre (EPGC), a program that
undertakes R&D activities in areas such as intelligent and decentralised power distribution, control andmanagement of distributed energy resources, and smart 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 for researchers, industry and public agencies to develop energy
technologies before bringing them to larger-scale test-beds or commercialisation.
To meet Singapore’s long-term energy challenges, the government allocated SGD 300 million to the first
National Innovation Challenge on ‘Energy Resilience for Sustainable Growth’ or ‘Energy NIC’. The Energy
NIC aims to develop cost-competitive energy solutions for deployment within 20 years to help Singapore
improve energy efficiency, reduce carbon emissions and increase energy options.
Solar energy is Singapore’s most viable renewable energy, apart from waste-to-energy, within thementioned limits, given the economy’s location in the tropical Sunbelt (EDB, 2014a). A key player in this fieldis the SERIS, which conducts world-class industry-oriented R&D and trains manpower for the solar energy
sector. It has attracted world-renowned talent in the solar industry and is now home to some 160 researchers.
Singapore is now a prime location for major solar companies such as Phoenix Solar, Renewable Energy
Corporation (REC), Trina Solar and Yingli, which aim not only to improve the economy’s domestic market, butmarkets all over Asia. Moreover, Singapore also houses a range of key wind technology players such as Keppel
and Vestas.
Finally, the National Environment Agency (NEA) also plays a role supporting environmentally focusedenergy research as part of efforts to help Singapore achieve environmental sustainability. Towards this end, theSingapore Environment Institute (SEI) acts as the NEA’s training and knowledge division (NEA, 2015a).
Additionally, the NEA, in its capacity as Singapore's Designated National Authority (DNA) for Clean
Development Mechanism (CDM) projects under the Kyoto Protocol to the UNFCCC, issued a Letter ofApproval (LoA) to CDM projects that meet Singapore's sustainable development criteria. The LoA supports theregistration of the project by the UNFCCC CDM Executive Board (EB)’ (NEA, 2015b).
ENERGY MARKETSELECTRICITY

Singapore began restructuring of its energy sector in 1995 through corporatising its electricity and gas industries
as vertically integrated companies. Major activities in this regard have since included corporate and industry
structural reforms, the creation of an institutional regulatory framework and market rules for the contestableparts of electricity generation and retail of electricity, separate from the natural monopoly of electricity
transmission at the ownership level. Furthermore, the Singapore Electricity Pool was established in 1998 tofacilitate the trading of electricity between generation and retail companies in a competitive environment.
Singapore’s government introduced additional reforms in 2000, separating Singapore Power Ltd into twoparts. These were the natural monopoly or non-contestable part of the electricity market (the electricity
transmission and distribution grid) and the competitive or contestable part (power generation and retail). As aresult, SP Power Assets Ltd (then known as the electricity grid—PowerGrid Ltd) and SP Services Ltd (thenknown as Power Supply Ltd) remained under Singapore Power Ltd. However, the power generation companies,
namely, Senoko Power Ltd and PowerSeraya Ltd, would compete with each other and other power generationcompanies in Singapore. Additionally, Singapore’s government founded an independent power system operator
and liberalised the electricity retail market.
The government’s other major restructuring initiatives included forming the EMA in April 2001 to regulate
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commencement of operations of the National Electricity Market of Singapore (NEMS) in 2003, wheregeneration companies compete to sell electricity at half-hour intervals in the wholesale electricity market.
The retail market’s liberalisation has been implemented in phases, with plans to open up the market to full
retail contestability. Its final phase (full retail contestability) is currently under review (EMA, 2014a). This phase
covers the remaining non-contestable consumers, mainly small businesses and household consumers—about
1.3 million in number—that represent 25% of total electricity sales. As stated by the MTI minister during theSingapore International Energy Week (SIEW) in October 2015, the EMA is working with the industry
stakeholders to launch full retail contestability (FRC) in 2018 (EMA, 2015d).
GAS

Gas is a key energy resource for Singapore as apparent in the large share of gas in its power mix in 2015 (96%).
The gas industry has been restructured since 2008 to ensure a competitive electricity market. As explained by
the EMA, similar to the electricity market, the gas market is structured in a way that fosters competition (EMA,
2015b). As a result, ‘the gas transportation business is separated from the competitive businesses of gas import,
shipping and retail. A set of rules called the Gas Network Code (GNC) governs the activities of gas
transportation, providing open and non-discriminatory access to the onshore gas pipeline network’ (EMA,
2015b).
The passage of the Gas Act (Act 11) in 2001 began 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 themonopolistic part (gas transportation). A gas grid company owns the gas transmission and distribution network,
which provides market players with open and non-discriminatory access to the network.
In January 2002, PowerGas Ltd divested its contestable activities, namely, gas imports, production andretail. Consequently, City Gas Ltd’s manufactured gas production and gas retail activities and Gas Supply Ltd’s
natural gas import activities were transferred to Temasek Holdings to make PowerGas Ltd a gas transporter.
Under the new gas industry framework, the transportation of natural gas would be regulated.
The GNC, which came into effect on 15 September 2008, initiated Singapore’s newly restructured gas
market operation. The EMA developed and enacted the GNC in consultation with industry players. The GNC’s
rules govern 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 those industry players who engage the transporter to transport gas through the pipeline
network. To ensure the gas transporter is not in commercial conflict with common interests, PowerGas Ltd isbanned from participating in the electricity and gas businesses open to competition such as gas importing, trading
and retailing. Other gas industry participants will not be allowed to transport gas.
The exit of Sembcorp Gas from the gas transportation business on 15 September 2008 affirmed PowerGas
Ltd as a gas transport monopoly. The company, which had diversified interests in gas transportation, import andretail businesses, exited the gas transportation business and transferred its gas pipelines to PowerGas Ltd, via astatutory transfer under section 98 of the Gas Act.
The gas market’s restructuring is mainly to support the liberalisation of the electricity industry by providing
a competitive source of natural gas for electricity generation. Singapore’s government expects greater
competition in the gas and electricity sectors and the benefits of competition, such as lower prices and a wider
choice of retailer, to be passed through to consumers.
The economy’s LNG terminal, which began operation in May 2013, has since made a major contribution
to the diversification of its gas market and boosted its gas security by making LNG available to Singapore’s gas
market (EMA, 2014b). On 21 August 2006, Singapore introduced controls on importing of new piped naturalgas (PNG) supply to allow the build-up of demand for LNG, given the need for a baseload of LNG demand toensure that the LNG terminal can operate safely and maintain financial viability. As a result, Singapore will not
allow
new
PNG
to
be
imported
for
all
new
gas
demand.
The Singaporean government will review the policy on PNG import controls when LNG imports reach 3 Mtpa
or in year 2018, whichever comes first (EMA, 2015e).
TRANSPORT

Singapore promotes the use of public transport as part of its efforts for fuel efficiency and energy conservation.
The economy has innovative policies to discourage car ownership and usage, such as a vehicle quota system and197

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electronic road pricing, towards this end. The Singaporean government has also offered a green vehicle rebate
to encourage the purchase of green vehicles such as hybrid, compressed natural gas and electric cars.
The Green Vehicle Rebate (GVR) program is an inter-agency effort by Singapore’s Ministry of Finance,
Ministry of the Environment and Water Resources, Ministry of Transport, Land Transport Authority and NEA.
The program offers incentives to promote green vehicles, which are more fuel-efficient and emit less air
pollutants than their conventional petrol or diesel equivalents through narrowing the cost differential between
green vehicles and conventional vehicles (NEA, 2015c).
The program was first introduced in January 2001 for the registration and use of electric and hybrid cars,
but was extended to compressed natural gas (CNG) vehicles in October 2001 and imported used electric andpetrol-electric hybrid vehicles registered as of 1 July 2010 (NEA, 2015c).
The rebate was increased from 20% to 40% of the vehicle open market value in January 2006 to offset theadditional registration fee.
An inter-agency Electric Vehicle Taskforce (EVTF) led by the EMA and the LTA (Land Transport
Authority) launched the electric vehicle (EV) test-bed from June 2011 to December 2013 to determine feasibilityof 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 EV costs.
In December 2014, the EDB and the LTA announced the next phase of the EV test-bed. This test-bed
will focus on vehicle fleets such as EV car-sharing and E-taxis (LTA, 2014).
ENERGY CONSERVATION

Singapore has taken measures to decrease its energy consumption through conservation. Towards that end, theSingaporean Parliament passed the Energy Conservation Act 2013 (ECA) to be jointly administered by the
Ministry of the Environment and Water Resources and the Ministry of Transport; it came into effect in 2013
(EMA, 2012).
The ECA requires large users of energy to implement energy management initiatives. Companies that
consume more than 15 GWh or 1.3 ktoe of energy annually are required to appoint an energy manager tomonitor and report their energy use and greenhouse gas 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.
Apart from the ECA, the economy has also sought to decrease energy consumption through improving
the energy efficiency of its industry, transportation, buildings and households sectors.
ENERGY EFFICIENCY

Singapore has actively sought to increase its energy efficiency for various reasons. These reasons include curbing
unnecessary consumption of fossil energy for environmental, financial and health considerations and improving
competitiveness of its industries. Consequently, the economy's key strategies in mitigating greenhouse gas
emissions, for example, are to switch to less carbon-intensive fuels and to improve its energy efficiency. It has
adopted measures to improve its energy efficiency and to reduce the energy use of various sectors of its economy.
The government established the E2PO, a multi-agency committee led by the NEA and the EMA, to implement
energy efficiency. Together, the EMA, the E2PO and the NEA actively promote energy efficiency in both public
and private sectors through legislation, incentives and information (NEA, 2014). Their energy efficiency efforts
are targeted at various sectors such as power generation, industry, transport, buildings and households.
To that end, the E2PO activities are the most prominent. The entity promotes and facilitates the adoptionof energy efficiency in Singapore under the following five strategic goals (E 2PO, 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);
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S I N G AP O REPromote emerging energy efficient technologies and innovation through supporting the researchdevelopment and demonstration of new energy efficient technologies, innovation and business process
improvements;

Profile and promote energy efficiency internationally through various platforms such as Singapore
International Energy Week (SIEW), Asia-Pacific Economic Cooperation (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 programs aimed at improving energy efficiency and reducing their CO2
emissions. Recent examples include: for buildings, the Building Control Act’s Chapter 29 Part IIIB—
Environmental Sustainability Measures for Existing Buildings (E2PO, 2015a); for industry, the 2013 Mandatory
Energy Management Requirements (E2PO, 2015b); and for households, the 10% Energy Challenge of 2008,
aimed at encouraging households to save at least 10% (E2PO, 2015c). Expanding the mass rapid transit (MRT)system has been the major emissions-reduction policy for the transport sector (E2PO, 2015d).
INDUSTRY

Various government initiatives have sought to improve industry’s energy efficiency. They include:

The Energy Efficiency Improvement Assistance Scheme (EASe): EASe encourages and helps
companies identify potential energy efficiency improvement opportunities. Under the EASe, up to 50%of the cost of appraisals for buildings and facilities will be co-funded.

The Investment Allowance Tax Scheme: This program encourages companies to invest in energyefficient equipment. The EDB administers the Investment Allowance Tax Scheme, which is a capitalallowance on qualifying equipment costs that allows a deduction against chargeable incomeDesign for Efficiency Scheme (DfE): Introduced in 2008, it encourages investors to incorporate energy
and resource efficiency considerations into their facilities’ development plans 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 efficient technologies
or equipment.

The Singapore Certified Energy Manager (SCEM) training program and grant: This program provides
a thorough understanding of the key energy issues facing the building and industry sectors. It helps
participants develop the technical skills and competencies needed to manage energy issues of theorganisations that they serve. A training grant is also offered to cover about 80% of the training costs.

Energy Efficiency National Partnership (EENP) Program: This is a voluntary outreach program toassist companies in improving their energy efficiency and reducing energy wastage. The EENP
promotes the adoption of energy management systems, such as ISO 50001, at the organisational leveland provides a platform for training and sharing best practices under the EENP Learning Network.
EENP partners who have implemented excellent energy management practices and demonstrated
tangible results will be recognised through the EENP Award.

Other initiatives aimed at building energy efficiency capabilities include incentive schemes for small and mediumsized enterprises (SMEs) (E2PO, 2015b). Singapore intensified such efforts in 2013 when it required energyintensive industrial companies with annual energy consumption of 54 terajoules (TJ) or more to comply with
the Mandatory Energy Management Requirements.
Finally, Singapore’s energy-intensive industries are required, as of April 2013, under the ECA to registerwith the NEA within six months of qualifying as a registrable corporation and to implement mandatory energy
management practices as follows: appointing an energy manager; monitoring and reporting energy use andgreenhouse gas emissions annually; and, submitting energy efficiency improvement plans annually (E2PO,
2015b).
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TRANSPORT

Singapore’s has sought to increase its transport sector’s energy efficiencies through a variety of measures. Thisobjective has manifested in the economy’s land transport strategies, which seek to integrate transport and landuse planning, promote the 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, a green vehicle rebate to encourage more fuel-efficient vehicles and trials of green
technologies such as diesel hybrid buses and electric vehicles.
Decreasing the role of private vehicles in favour of more-fuel efficient MRT has been a major componentof Singapore’s efforts towards the mentioned objectives as well as reducing its carbon footprint. The economy
is currently constructing new MRT lines and adding new stations to existing lines (LTA, 2015).
Singapore’s major efforts to increase sector energy efficiencies include the following:Carbon Emissions-Based Vehicle Scheme (CEVS): The CEVS was introduced in January 2013 toimprove the number of green vehicles purchased, with cars enjoying rebates for having low carbon
emissions, while those with high carbon emissions having to pay a surcharge. Replacing the green
vehicle rebate (GVR), the results of CEVS has been encouraging with more than 50% of the new cars
registered in 2013 receiving CEVS rebates, whereas about 10% paid the surcharge. The CEVS will be
extended until July 2015 before the full impact of the scheme will be refined.



Fuel Economy Labelling Scheme (FELS): As of 2009, passenger cars and light goods vehicles that are
sold in Singapore must be affixed with a fuel economy label. With the fuel economy information, carbuyers are able to make better-informed decisions on fuel efficiency when purchasing new cars.

Green Mark for Rapid Transit System: The rapid transit system (RTS) is the backbone of Singapore’s
public transport system and is also the most energy efficient means of transporting a large number ofcommuters. By 2020, the RTS network will be doubled to 278 km. The objectives of the green markfor the RTS framework are to promote sustainable and environmentally friendly RTS design as well as
to provide guidance in the formulation of engineering standards for conceptualisation, design andconstruction of new RTS lines. The framework has three key pillars—the effective use of energy, water
conservation, and environmental protection and sustainable development—and covers various aspectsof an RTS line (rolling stock, electrical and mechanical systems, civil works, station design as well as
operational considerations).



Trial of Diesel Hybrid Buses: LTA and public transport operators are collaborating on a trial of diesel
hybrid buses. Diesel hybrid buses have been found to be effective in other cities in reducing both thecarbon emissions and particulate matter (PM) emissions of the bus fleet. If the trial is successful, morediesel hybrid buses may be deployed in the future.



Facilitating Cycling: Cycling does not consume external energy. To facilitate cycling as an alternativemode of transport for short-distance, intra-town trips, programs are progressively being rolled out todesign and construct dedicated cycling paths in seven selected housing development board (HDB)
towns (Tampines, Yishun, Sembawang, Pasir Ris, Taman Jurong, Bedok and Changi-Simei) as well as
Marina Bay. More and better-designed bicycle parking facilities are being provided near MRT stations
to help cyclists transfer to the public transport system for longer distance travel. Foldable bicycles areallowed on buses and trains during off-peak hours.

Park and Ride (P&R) Scheme: The scheme allows people who have vehicles to park their vehicles atdesignated car parks located near an MRT station, bus interchange or bus stop, and continue theirjourney hassle-free by bus, MRT or LRT. The purpose of this scheme is to allow motorists to switch tothe more energy efficient public transport for part of their journey in a convenient way.



The Green Vehicle Rebate (GVR) Program: The program offers incentives to promote green vehicles
that are more fuel-efficient and emit less air pollutants than their conventional petrol or diesel
equivalents (NEA, 2015c).

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BUILDINGSSingapore has plans to improve the energy efficiency of the building sector as a major energy consumer, forwhich a major consideration is achieving a sustainable environment as a key factor for its sustainable
development. To realise this vision, the Building and Construction Authority (BCA) and the NEA set out toaccelerate the adoption of environmentally friendly green building technologies and building design practices,and to encourage energy efficiency in buildings.
Singapore’s energy efficiency initiatives include the following:EASe for Buildings: The EASe scheme is available to building owners and operators.

Singapore Certified Energy Manager (SCEM) for buildings: This initiative, consisting of both a programand grant, is available to professionals who wish to build their careers as energy managers in the building
sector.



BCA Green Mark Scheme: Launched in January 2005, the BCA green mark scheme is a green building
rating system that promotes the adoption of green building design and technologies to improve energy
efficiency and reduce the impact of buildings on the environment. Under the BCA green mark scheme,
buildings are assessed for energy efficiency, water efficiency, indoor environmental quality andenvironmental protection as well as other green features and innovations.



Building Control (Environmental Sustainability) Regulations: The regulations took effect in 2008 to
require new buildings and existing ones undergoing major retrofitting with a gross floor area greaterthan 2 000 square metres to achieve the minimum green mark certified level.

Green Mark Gross Floor Area (GM GFA) Incentive Scheme: To encourage the private sector todevelop buildings that attain higher tier green mark ratings (i.e. Green Mark Platinum or Green Mark
GoldPLUS), BCA and URA introduced the green mark gross floor area incentive scheme on 29 April
2009 for a period of five years. For developments attaining Green Mark Platinum or Gold PLUS, URA
will grant additional floor area over and above the master plan gross plot ratio (GPR) control.

Green Mark Incentive Scheme for New Buildings (GMIS-NB): On 15 December 2006, a sum of
SGD 20 million was set-aside for the green mark incentive scheme for new buildings for a period of
three years. The scheme offered cash incentives to developers, building owners, project architects andengineers who made an effort to achieve at least a BCA Green Mark Gold rating or higher in the designand construction of new buildings. The fund was fully committed.

Green Mark Incentive Scheme for Existing Buildings (GMIS-EB): A sum of SGD 100 million was setaside for the green mark incentive scheme for existing buildings on 29 April 2009 for a period of five
years. The GMIS-EB provides a ‘cash incentive for an upgrading and retrofitting’ scheme that co-funds
up to 35% (capped at SGD 1.5 million) of the costs of energy-efficient equipment installed to improvethe energy efficiency of existing buildings. In addition, the GMIS-EB includes a ‘health check’ scheme;
this is an energy audit, which determines the efficiency of a building’s air-conditioning plants. BCA cofunds 50% of the cost for conducting this health check; the remaining 50% is borne by the building
owner.

The Design Prototype (GMIS-DP): A sum of SGD 5 million was set-aside for the GMIS-DP on 1
December 2010 for a period of four years. GMIS-DP aims to encourage developers and building owners
to strive for greater energy efficiency in buildings by placing more emphasis on this at the design stage.
The scheme provides funding support for the engagement of environmentally sustainable design (ESD)
consultants to conduct collaborative design workshops and to help in simulation studies early in the
project to achieve an optimal design for green buildings. The developments must aim to exceed thegreen mark platinum standards, demonstrating energy savings of at least 40% or better than the current
base code or equivalent.



Building Retrofit Energy Efficiency Financing (BREEF) Scheme: In September 2011, BCA announced
a new pilot scheme called the Building Retrofit Energy Efficiency Financing (BREEF), which provides
loans to building owners and energy services companies to enable them to carry out energy retrofits.
BCA and participating financial institutions committed to sharing the risk of any loan default. The pilot
scheme took effect 1 October 2011 for a period of two years.
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Higher Green Mark Standards for Land Sales Conditions in Strategic Growth Areas: To achieve higher
green mark standards (i.e. Green Mark Platinum or Green Mark GoldPlus) for projects developed on
government-sold sites, the higher green mark standards will be set as part of the land sale conditions
for all new developments in selected new strategic growth areas. This will ensure these land sale projects
are truly green, high quality and distinctive. The aim is to accelerate the adoption of environmentallyfriendly green building technologies and building design practices to enable the development of more
economically viable green buildings in the future.



Public Sector Taking the Lead: The public sector is committed to environmental sustainability and takes
a long-term view of resource efficiency. Public sector agencies have put in place environmental
sustainability measures that encompass energy efficiency, water efficiency and recycling. New public
sector buildings with an air-conditioned area of greater than 5 000 square metres must attain the GreenMark Platinum rating, while existing public sector buildings with an air-conditioned area of greater than
10 000 square metres must attain the Green Mark Gold Plus rating by 2020.

Among the most recent initiatives is the introduction of legislation in 2012 aimed at achieving a sustainablebuilding environment to ensure the continuity of efficient operation of existing buildings throughout their life
cycle (E2PO, 2015a) as follows.


Building Control Act’s Chapter 29 Part IIIB—Environmental Sustainability Measures for Existing
Buildings: The Act requires building owners to comply with the minimum environmental sustainability
standard (green mark standard) for existing buildings; submit periodic energy efficiency audits ofbuilding cooling systems; and submit information in respect to energy consumption and other related
information as required.

HOUSEHOLDS

Improving energy efficiency of households has been a major target for Singapore as part of its commitment tosustainable development demanding reductions in fossil energy consumption and CO 2 emissions. Accounting
for about a sixth of the electricity consumed in Singapore, households are encouraged to purchase energyefficient appliances and adopt energy-efficient habits. Energy efficiency programs for households include:

The 10% Energy Challenge: To increase public awareness of ways to be more energy efficient, the 10%
Energy Challenge was launched in April 2008. The aim of the challenge was to teach households simple
energy saving habits to reduce their energy use by 10% and save money. By doing so, they also help
fight climate change.

Mandatory Energy Labelling Scheme (MELS) and Minimum Energy Performance Standards (MEPS):
To assist households in making better energy choices, the MELS was introduced for the two mostenergy intensive appliances, namely, air conditioners and refrigerators, in January 2008. The scheme was
extended to clothes dryers in 2009. Under the Environmental Protection and Management Act, allhousehold refrigerators, air conditioners and clothes dryers sold in Singapore must be affixed with anenergy label. In addition, MEPS were introduced in September 2011 for household air-conditioners andrefrigerators. The MEPS remove the most inefficient appliance models from the market by prohibiting
the sale of models that fall short of specified minimum energy efficiency levels, and encourage suppliers
to bring in more energy-efficient appliances as technology improves.



Residential Envelope Transmittance Value Standard: As set in place in 2008, residential buildings witha gross floor area of 2 000 square metres or more must comply with the BCA residential envelope
transmittance value standard.
RENEWABLE ENERGY

Singapore has very limited options in terms of renewables due to its geological and geographical situations.
Hydro, wind, geothermal and tidal energy are not feasible and there are limits to solar expansion. Apart from alimited expansion of grid-connected rooftop solar panels, waste-to-energy is Singapore’s main renewable energy
source, accounting for 3.7% of Singapore’s power mix in 2014 (EMA, 2015a). Due to such constraints, Singapore
is pursuing growth opportunities in waste-to-energy and, to the extent possible, solar for power generation. It
has also been producing biodiesel since 2010 to help diversify its liquid energy demand.

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Several renewable energy initiatives are underway to help the economy diversify its energy mix and reduce
its heavy dependency on fossil energy as follows.
Singapore’s modern, electricity-generating incineration plants make use of renewable waste-to-energy
technologies, annually consuming about 2.7 million tonnes of waste, which generates a growing amount of green
energy from four 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). These plants generated 691 ktoe of electricity in 2014 (EMA,
2015a).
Regarding solar energy, Singapore has embarked on R&D and test-bedding initiatives to help companies
and researchers advance the development of the required technologies. Singapore’s test-bedding efforts seek toimprove the understanding of the best practices for optimising the performance of solar PV systems in tropical,
urbanised environments.
Households are a major beneficiary of solar energy for electricity generation. For that matter, The HDB
has test-bedded solar PV systems at two existing public housing precincts in Serangoon and Wellington,
generating 220 kWh of electricity per day for each precinct in the process. The government agency has beenutilising the rooftop space of residential buildings to set up solar systems in land-scarce Singapore.
As of the second half of 2014, there were 636 grid-connected PV installations with the total capacity of
33 MWp, comprised of 226 residential (2.3 MWp) and 410 non-residential (30.8 MWp) installations (EMA,
2015a). The HDB will install solar panels over 900 HDB blocks and eight government buildings by the end of2017 through a tender (EMA, 2015f).
The government agency has been investing substantially in solar R&D. Under its USD 31 million Solar
Capability Building Program, HDB has been test-bedding different solar capabilities to build up expertise on
solar installations. It has also helped to promote data sharing with other government agencies and the industry.
These include learning points such as those on procurement and solar aggregators.
The HDB is also promoting solar leasing, a business model in which the agency buys only the electricity
generated (EMA, 2015f). The power produced could be used to power lifts, corridors and staircase lights incommon areas, for instance. Under a solar leasing model, a private company will design, finance, install, operate
and maintain 2 MWp of solar PV systems. The Pasir Ris-Punggol Town Council will pay Sunseap for solar power
generated and consumed at a rate that is not higher than the retail electricity tariff rate.
Added to HDB efforts to expand solar energy, the EDB and Public Utilities Board (PUB) will pilot a SGD
11 million floating PV project at Tengeh Reservoir, which aims to assess the feasibility of installing floating solar
PV systems (2 MW) as an alternative to rooftop-based installations (NEA, 2015d). This is the first project of
this nature in South-East Asia.
Singapore has also launched the SolarNova Programme to aggregate demand for solar energy ‘acrossgovernment buildings and spaces, to yield 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).
The EMA has increased the Intermittent Generation Threshold from 350 MWp to 600 MWp to help
expand solar energy growth (EMA, 2015g). This threshold covers power generation from renewables that varies
for natural reasons (sunshine in the case of solar) and require fossil fuel-fired generators as back-up.
Finally, the ‘Handbook for Photovoltaic (PV) Systems’ has been published by the EMA and the BCA tofacilitate the implementation of solar PV systems in Singapore. The handbook provides information on licensing,market and technical requirements, and building and structural issues relating to solar installations.
Biodiesel production is also a vibrant sector. In November 2010, the Finnish oil refining and marketingcompany Neste Oil opened its 800 000 tonnes per year renewable diesel refinery in Singapore at the cost of EUR
550 million. The refinery uses Neste’s proprietary NEXBTL technology to produce a renewable diesel productsuperior to regular biodiesel and fossil-based diesel. Renewable diesel reduces greenhouse gas emissions by over
50% compared to fossil-based diesel (Neste Oil, 2012). The refinery is the world’s largest of its kind along with
Neste Oil’s Rotherdam facility (Neste Oil, 2015).

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S I N G AP O RESUSTAINABLE DEVELOPMENT

Singapore’s IMCSD unveiled its Sustainable Development (SD) Blueprint on 27 April 2009. The SD Blueprintcontains strategies and initiatives for achieving both economic growth and a good living environment forSingapore 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 contributeto enhance the city-state’s competitiveness in the long run. Under the blueprint, efforts will be 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 as Singapore 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 from the 2005 levels(NEA, 2013).
In 2015 Singapore released ‘an extension of the efforts outlined in the 2009 edition’, namely, the Sustainable
Singapore Blueprint 2015 (MEWR, 2015). The document takes into consideration feedback obtained from morethan 130 000 people through recent initiatives, including the Land Transport Master Plan 2013 and the Urban
Redevelopment Authority’s Master Plan 2014 (MEWR, 2015). Its emphasis is on sustainable housing andtransportation aimed at reducing waste to zero through reduction of consumption, recycling and reuse of allmaterials and adopting greener practices by businesses (MEWR, 2015). The objective is to turn Singapore intoa ‘hub for the cutting-edge business of sustainable development’ to achieve three objectives: a liveable andendearing 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 as the only viable type of renewable for Singapore, apart from waste-to-energy, by
facilitating its growth. Among others, the EMA has taken steps towards this end, including setting 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 pre-feasibility
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 presently available, though safer than the older designs still in use in many countries, were notsuitable 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 waste-to-energy and a very small amount of solar)
and nuclear 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 business-as-usual (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 2010 as a dedicated agency under the Prime Minister's Office to coordinate its domestic andinternational policies, plans and actions on climate change (NEA, 2014).
Ahead of the pending conclusion of a legally binding global agreement, the economy has begun to
implement measures that are expected to lead to a 7–11% reduction in emissions from BAU levels. Apart fromincreasing the share of solar in its power generation energy mix, which is currently very small (33 MWp in 2014),
it has significantly reduced its grid-generated emissions through greater use of natural gas for electricity
generation by increasing its share of the power mix. Singapore has switched from fuel oil to natural gas as themain energy source for such generation as it produces the least carbon emissions per unit of electricity generated
among fossil fuel-fired power plants. By increasing the share of natural gas used in electricity generation fromonly 19% in 2000 to 96% in 2015, Singapore has substantially reduced its emissions growth over the last 10 years(NEA, 2014). Singapore’s efforts have resulted in improving its average operating margin grid emission factor
from 0.4 kg CO2/kWh in 2013 to 0.4 kg CO2/kWh in 2014 (EMA, 2015a).
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Singapore is also intensifying efforts to promote more efficient energy use to decrease its 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 is a remarkable objective as Singapore is already one of the least carbon-intensive economies in theworld, ranking 113 out of 140 countries (IEA, 2014).
N OTA B L E E N E RG Y D E V E L O P M E N T S
PREPARING FOR FUTURE POWER GENERATION INVESTMENTS IN SINGAPORE

In October 2015, the EMA released a consultation paper, Preparing for Future Power Generation Investments
in Singapore (EMA, 2015h). The document’s rationalization is based on a need for a long-term view on theoutlook of the energy landscape in Singapore given the high capital cost, significant lead time and long payback
period for power generation investments. Towards that end, the EMA’s document seeks to share with theindustry the EMA’s view of the long-term outlook of the sector, including ‘projected growth of electricity system
demand, as well as an indicative mix of generation sources (gas-fired plants, solar, electricity imports, etc.) in
2030 based on technology developments, evolving business models and broader policy considerations’.
This is part of the EMA’s objective of working ‘with the industry to further facilitate power generation
investment decisions in Singapore through making available more information and providing greater visibility toinvestors’.
The consultation paper consists of three key sections: i) proposed information that the EMA hopes to put
out on the long-term outlook of the energy market; ii) proposed enhancements to the regulatory approval
process for new and existing generation assets to give greater visibility to the capacity coming onstream; and iii)
a proposed framework to allocate land for new generation assets.
GRANT CALLSThe EMA rolled out a series of grant calls in 2015 covering areas including smart grids, power utilities (gas/LNG)
and energy storage (EMA, 2015i). This was part of its plan to catalyse R&D of innovative technologies andsolutions. The main objective was to ‘address industry-relevant challenges and opportunities in the energy sector
and lead to long-term solutions for Singapore's energy challenges’.
POST-3 MTPA LNG IMPORT FRAMEWORKOn 30 June 2014, the EMA launched a request for proposal (RFP) to appoint up to two LNG importers to
supply Singapore with LNG beyond the first 3 Mtpa from BG Singapore Gas Marketing Pte. Ltd (EMA, 2015j).
The RFP was conducted in two stages. Its Stage One closed on 31 December 2014. At that point, the EMA
shortlisted four companies to participate in Stage Two, namely, BG Singapore Gas Marketing Pte. Ltd, Pavilion
Gas Pte. Ltd, Sembcorp Industries and Shell Eastern Petroleum [Pte] Ltd).
On 29 May 2015, Stage Two was opened followed by the EMA releasing Corrigendum No. 1 on 2
November 2015, as per the following extract:
EMA will extend the closing date of Stage Two of the Post-3 Mtpa Request-for-Proposal (‘RFP’) in
response to feedback from some LNG market stakeholders that it would be useful to provide more time fornegotiations and for entering into binding commitments. The four shortlisted companies will now have tosubmit their proposals to EMA by 30 June 2016 instead of 29 February 2016. EMA will thereafter appoint up
to two companies to import LNG for Singapore.
INAUGURATION CEREMONY OF REMEX INCINERATION BOTTOM ASH (IBA) METALRECOVERY FACILITY

On 1 December 2015, REMEX Minerals Singapore Pte Ltd inaugurated its metal recovery facility located at
Tuas Marine Transfer Station (TMTS) (NEA, 2015e). The facility recovers ferrous and non-ferrous metals fromthe incineration bottom ash (IBA) generated by the waste-to-energy (WTE) incineration plants in Singapore. It
is the first IBA metal recovery facility in Asia and part of the NEA’s long-term strategy to manage solid wastein Singapore.
ENERGY STORAGE PROGRAMMEIn October 2014, the EMA announced a SGD 25 million Energy Storage Programme to support thedevelopment and integration of large scale, cost-effective Energy Storage Systems (ESS) for Singapore's power
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system. In Singapore, ESS could be used to reduce demand during peak periods; as reserves for frequency
regulation; and to support the deployment of intermittent generation sources like solar energy.
SEMBCORP-EMA ENERGY TECHNOLOGY PARTNERSHIPThe EIPO established a Sembcorp-EMA Energy Technology Partnership (SEETP) under the EIRP October
2014 (SEETP, 2015). Thus, the EMA partnered with Sembcorp in a SGD 10 million (about USD 8 million)
initiative to encourage the translation and commercialisation of energy research into technologies and solutions
to address Singapore’s energy needs. Through this partnership, researchers and companies have the opportunity
to develop new technologies that could potentially be test-bedded at Sembcorp's facilities and leverage
Sembcorp's strong business networks for commercialization (SEETP, 2015).
The SEETP is an entity, which ‘encourages the translation of ideas from the laboratory to market andaddresses a current gap where the potential of promising technologies is often not exploited beyond the researchand development (R&D) stage’ (SEETP, 2015).
PULAU UBIN MICRO-GRID TEST-BED

The EMA is conducting a micro-grid test-bed on the island of Pulau Ubin to assess the impact of intermittent
energy sources, such as solar, on grid operations. Phase 1 of the test-bed was successfully completed andlaunched by Minister S. Iswaran on 10 October 2013 to supply electricity to end-users at the Pulau Ubin jetty
area. Under Phase 2, the micro-grid will offer companies and research organisations a platform to develop andpilot innovative, close-to-market energy technologies for Singapore (in areas such as energy analytics, energy
storage and grid asset management). Awarded projects will be announced by the second half of 2015.
BIOMASS CLEAN COAL COGENERATION PLANT

Currently, Tuas Power operates the Biomass Clean Coal (BMCC) cogeneration plant, as part of the Tembusu
multi-utilities complex that serves the industries on Jurong Island. The increased efficiencies of cogenerationand the use of biomass help reduce the carbon emissions of the plant per unit of electricity and steam generated.
Further, to ensure that environmental sustainability is not compromised, low-sulphur and low-ash coal is usedin the BMCC plant to substantially reduce the emissions of sulphur dioxide and the amount of waste generated.
The bulk of the fuel used in the plant is renewable biomass, natural gas and diesel. The facility has been in use
since 2013 and will be fully operational in 2017 to generate 160 MW of electricity in addition to steam (EDB,
2014b).
NEW GENERATION CAPACITY

On 26 October 2015, the NEA signed a Waste-to-Energy Services Agreement (WESA) with TuasOne Pte Ltd
to build Singapore’s sixth WTE plant scheduled to be operational in 2019 (NEA, 2015f). The plant will beSingapore’s largest WTE plant with the capacity to incinerate 3 600 tonnes of waste per day to generate 120 MWof electricity per day. TuasOne Pte Ltd is a company formed by the consortium of Hyflux Ltd and Mitsubishi
Heavy Industries Ltd (MHI). 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 electricity-generating companies are Senoko Energy, YTL Power Seraya, Tuas Power
Generation, SembCorp Cogen, Keppel Merliamu Cogen and PacificLight Power (SGC, 2014b). PacificLightPower started operation in June 2014 and is Singapore’s first fully LNG operated power plant. This state-of-theart 800 MW plant was built at a cost of USD 1.2 billion.
Keppel has entered into an agreement with Singapore’s NEA to provide additional incineration capacity
for the Senoko WTE plant. Thus, the plant will undergo upgrading, currently planned to take place between thethird quarter of 2015 and the third quarter 2016, to increase by up to 10% its current capacity of 2 100 tonnes
per day (Keppel, 2014a).
Keppel completed the expansion of its co-generation Keppel Merlimau Cogen Plant located at theTembusu sector of Jurong Island in 2013. Since the beginning of its operation in 2007, its total generation
capacity has now increased to 1 300 MW. It supports the needs of the surrounding industries with electricity,
steam supply and demineralised water requirements (Keppel, 2014b).
Keppel secured financial closure in 2011 for its two 420 MW combined cycle power plant project at Jurong
Island in Singapore. The engineering, procurement and construction contract, as well as the associated long206

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term service agreement, were signed in 2010. The power plants entered into commercial operation in 2013
(Keppel, 2011).
Sembcorp completed the construction of the first phase of a gas-fired combined cycle co-generation power
plant in July 2014. Being located in the Tembusu sector of Singapore’s Jurong Island, the plant’s total generation
capacity is 815 MW, the first phase electricity capacity of 400 MW and the steam production capacity of 200
tonnes per hour (Sembcorp, 2014). Its second phase is due for completion in the near future.
Senoko Energy announced in late 2009 the commencement of its Stage 2 repowering project to convert
three 30-year-old 250 MW oil-fired steam plants into two 431 MW LNG/gas-fired combined cycle plants thatare technologically modern and environmentally friendly. The plants, which make extensive re-use of the existing
equipment and infrastructure, entered commercial operation in 2012 (Senoko, 2012).
Tuaspring Pte Ltd, a subsidiary of Hyflux, was awarded the contract in late 2011 for a new 411 MW natural
gas-fired combined cycle power plant to supply electricity to the Tuaspring Desalination Plant in Tuas,
Singapore; its excess power will be sold to the power grid. Tuaspring signed a water purchase agreement to
supply the PUB with 318 500 cubic metres per day of desalinated water over a 25-year period from 2013 to 2038,
under a design, build, own and operate (DBOO) model. The Tuaspring Desalination Plant is Singapore’s secondand largest seawater reverse osmosis desalination plant (Hyflux, 2012).
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https://www.mti.gov.sg/NewsRoom/Pages/Mr-Teo-Ser-Luck-at-the-World-Engineers-Summit-onClimate-Change-2015.aspx
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–– (2014). Climate Change. www.nea.gov.sg/energy-waste/climate-change–– (2015a). SEI,
http://www.nea.gov.sg/training-knowledge/singapore-environment-institute/sei–– (2015b). Clean Development Mechanism. http://www.nea.gov.sg/energy-waste/climate-change/cleandevelopment-mechanism–– (2015c).Green Vehicle Rebate. www.nea.gov.sg/grants-awards/green-technology/green-vehicle-rebate–– (2015d).Singapore Announces Region's First Floating Photovoltaic Pilot Project at Solar Pioneer Awards
Ceremony. https://www.edb.gov.sg/content/edb/en/other-pages/news-archives/2011/singaporeannounces-regions-first-floating-photovoltaic-pilot-project.html–– (2015e). Inauguration Ceremony of Remex Incineration Bottom Ash (IBA) Metal Recovery Facility.
https://www.nea.gov.sg/EVENTSPROGRAMMES/EVENTS/PAST_EVENTS/INAUGURATION-CEREMONY-OF-REMEXINCINERATION-BOTTOM-ASH-(IBA)-METAL-RECOVERY-FACILITY–– (2015f). NEA and TuasOne Sign Agreement for Sixth Waste-to-Energy Plant, www.nea.gov.sg/eventsprogrammes/events/past_events/nea-and-tuasone-sign-agreement-for-sixth-waste-to-energy-plant
Neste Oil (2012). Neste Oil celebrates the grand opening of its ISCC-certified renewable diesel plant in
Singapore. www.nesteoil.com/default.asp?path=1,41,540,1259,1260,16746,17030–– (2015). Katie Fletcher. Neste Oil Reports More Renewable Diesel Capacity in Q1 Results.
http://biomassmagazine.com/articles/11875/neste-oil-reports-more-renewable-diesel-capacity-in-q1results
NUS (National University of Singapore). (2015a). National University of Singapore (NUS). (2015). Energy
Innovation Research Programme (EIRP). www.nus.edu.sg/dpr/energy/Research/fundingopportunities.htm–– (2015b). Competitive Grant Call for Directed Research in Energy Storage.
www.nus.edu.sg/dpr/energy/Research/funding-opportunities.htm–– (2015c). Competitive Grant Call for Directed Research under Sembcorp-EMA Energy Technology
Partnership (SEETP). www.nus.edu.sg/dpr/energy/Research/funding-opportunities.htm
SEETP (2015). Sembcorp-EMA Energy Technology Partnership.
http://research.ntu.edu.sg/researchgrant/GrantCalls/Pages/details.aspx?URL=http://research.ntu.edu.
sg/news/Pages/SEETP-2015.aspx&Guid=a7da3d67-3710-40e0-968ec880b5ee09a0&Category=Grant+Calls
Sembcorp. (2014). Energy: Power Generation. www.sembcorp.com/en/business-utilities-energy.aspx/
Senoko Energy (2012). www.senokoenergy.com/
SGC (Singaporean-German Chamber of Commerce) (2014a). Singapore Infrastructure Projects.
www.sgc.org.sg/fileadmin/ahk_singapur/DEinternational/IR/diffIR/Infrastructure_Projects_Singapore_2014_May.pdf–– (2014b). Singapore Electricity Market.
www.sgc.org.sg/fileadmin/ahk_singapur/DEinternational/IR/diffIR/Electricity_market_in_Singapore_2014.pdf
SingStat (Singapore Department of Statistics), (2015a). M013841 - Gross Domestic Product At Current Market
Prices, By Industry, Annual,
http://www.tablebuilder.singstat.gov.sg/publicfacing/createDataTable.action?refId=1425
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S I N G AP O RE–– (2015b). Yearbook of Statistics Singapore
2013,http://www.singstat.gov.sg/publications/publications_and_papers/reference/yearbook_of_stats_2013.html
SLNG (Singapore LNG Corporation) (2014a). Terminal Development. www.slng.com.sg/our-developmentscurrent.html–– (2014b). Future Development. www.slng.com.sg/our-developments-future.html
USEFUL LINKS

BG Group—www.bg-group.com
Department of Statistics Singapore—www.singstat.gov.sg
Economic Development Board—www.edb.gov.sg/
Energy Market Authority—www.ema.gov.sg
Economic Strategies Committee (ESC) Recommendations—www.mof.gov.sg/Resources/EconomicStrategies-Committee-ESC-Recommendations
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
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 TAIPEII N T ROD U C T I ON

Chinese Taipei is an archipelago consisting of Taiwan, Penghu, Kinmen and Matsu, located off the southeast coast of China and south-west of Japan. With an area of 36 193 square kilometres (km2), Chinese Taipei
represents a natural gateway to East Asia. Although only one-quarter of the land is arable, the subtropicalclimate permits multi-cropping of rice and the growing of fruit and vegetables perennially.
In 2013, Chinese Taipei’s gross domestic product (GDP) was USD 942 billion, and its per capita
income was USD 40 368 (2010 USD purchasing power parity [PPP]). Its GDP grew on average at a rate of
4.7% from 2000–13. Within the past few decades, Chinese Taipei’s economic structure has changed
substantially, shifting from industrial production to the services sector, wherein the latter constituted 65%of the GDP, followed by industry (33%) and agriculture (1.7%) in 2013 (BOE, 2015). Chinese Taipei is oneof the most densely populated areas in the world, but its population growth rate has been relatively flat; theeconomy’s population of 23 million grew at a rate of 0.4% in 2013 compared with 2012 (EGEDA, 2015).
Lacking natural resources, Chinese Taipei is highly dependent on energy imports to meet domesticenergy demand. According to the U.S. Energy Information Administration, Chinese Taipei holds only 2.3
million barrels and 6.2 billion cubic metres, respectively, of oil and gas reserves. 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, 2013
Key dataa, bEnergy reservesc

Area (km2)

36 193

Oil (million barrels)

2.3

Population (million)

23

Gas (billion cubic metres)

6.2

GDP (2010 USD billion PPP)

942

Coal (million tonnes)–

GDP (2010 USD PPP per capita)

40 368Uranium (kilotonnes of U)–

Sources: a. EGEDA (2015); b. National Statistics (2015); c. EIA (2015).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLYAs mentioned earlier, Chinese Taipei relies heavily on overseas energy resources for its needs. In 2013,energy imports accounted for 98% of total primary energy supply (TPES) in Chinese Taipei (BOE, 2014a),
indicating the low energy self-sufficiency rate as well as fragile energy security.
The growth of the TPES in Chinese Taipei is stable and has largely remained unchanged over the past
few years, rising from 107 457 kilotonnes of oil equivalent (ktoe) in 2012 to 108 440 ktoe in 2013, an increaseof 9.1%. Regarding the composition of the TPES, fossil fuels continue to be the dominant fuel with 88%
of the total supply. By fuel type, oil contributes the largest share (39%), followed by coal (34%), natural gas(15%) and other fuels (13%) (EGEDA, 2015).
In 2013, Chinese Taipei imported 45 million barrels of crude oil, 15% lower than the 53 million barrels
imported in 2012. The Middle East is the major supplier, accounting for 82% of total oil imports, followed
by Angola (8.4%) and the Republic of Ghana (2.8%). To prevent supply disruption, the Petroleum
Administration Act 2001 requires Chinese Taipei’s refiners to maintain stocks of more than 60 days of sales
volumes.
With regard to coal, Australia and Indonesia are the major suppliers, respectively, accounting for 45%
and 40.4% of total coal imports worth 0.9 million tons in 2013. Most of this fuel is used for power generation.
As indigenous natural gas only accounts for 1.9% of the total natural gas supply in Chinese Taipei,
almost the entire gas demand is met by imports of liquefied natural gas (LNG). Qatar, Malaysia andIndonesia are the largest suppliers, accounting for 44%, 21% and 16% of the supply, respectively, in 2013.
The total LNG import in 2013 was 12.5 million tonnes (Mt), 4.7% higher than the 12.4 Mt imported in 2012
(BOE, 2015).
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Table 2: Energy supply and consumption, 2013
Primary Energy Supply (ktoe)

Final Energy Consumption (ktoe)

Power Generation (GWh)

Indigenous production

13 880Industry sector

22 664

Total power generation

Net imports and others

97 378Transport sector

11 792

Thermal

194 912

Total primary energy supply

108 440

Other sectors

11 931

Hydro

8 610

Coal

36 797

Non-energy

22 125

Nuclear

41 639Oil

41 740Total final energy consumption

68 513

Others

7 089

Gas

16 338

Coal

7 380

Others13 566

Oil

38 732Gas

2 809

Electricity and others

19 592252 250

Source: EGEDA (2015).

In 2012, electricity generation in Chinese Taipei reached 252 352 gigawatt-hours (GWh). Of the total
electricity production, the hydropower generated by the Taiwan Power Company (TPC) comprised 3.4%,
thermal power 48% (25% coal, 2.1% oil and 20% LNG), nuclear power 16.5%, wind power 0.3%,
cogeneration 16% and independent power producers (IPPs) 16%. In terms of the generating capacity, theTPC dominates Chinese Taipei’s electric power sector with 68% and IPPs account for 16% of the total
capacity. IPPs are required to sign power purchase agreements with the TPC, which distributes power toconsumers. To expand foreign participation, in January 2002, the government permitted foreign investors
to own up to 100% of an IPP (BOE, 2015).
FINAL ENERGY CONSUMPTION

Final energy consumption in Chinese Taipei was 68 513 ktoe in 2013, 3.8% higher than in 2012. The
industrial sector consumed 33% of the total energy used, followed by the transport sector (17%). The othersectors, including residential and services, consumed 48% of the total energy used. By energy source,
petroleum products accounted for 57% of total final energy consumption, followed by electricity (29%),
coal (11%) and gas (4.1%). In comparison with 2012, the energy consumption in 2013 was 2.6% higher(EGEDA, 2015).
ENERGY INTENSITY ANALYSIS

Chinese Taipei is committed to reduce its energy intensity by 12% and 18% of the 2010 level respectively
by 2020. In terms of the TPES, Chinese Taipei showed an improvement with a reduction of 1.3%, declining
from 131 tonnes of oil equivalent per million USD (toe/million USD) in 2012 to 130 toe/million USD in2013. However, the final energy consumption intensity showed a slight increase of 1.5%, from 81
toe/million USD in 2012 to 82 toe/million USD in 2013, which was mainly contributed by the non-energy
sector since the energy intensity of all the other sectors declined from 2012 to 2013.
Table 3: Energy intensity analysis, 2013
EnergyChange (%)

Energy intensity (toe/million USD)
2012

2013

2012 vs 2013

Total primary energy supply

131

130

1.3

Total final energy consumption

81

82

1.5

Industry

27.0

27.1

0.3

Transportation

14.4

14.1

2.2

Others

14.5

14.2

1.7

Non-energy

25

26

6.8

Source: EGEDA (2015).

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P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKThe Bureau of Energy (BOE) is responsible for formulating and implementing Chinese Taipei’s energy
policy. There are three fundamental energy policies. The Framework of Taiwan’s Sustainable Energy Policy
was released in 2008. It is based on three core beliefs, namely energy security, environmental protection andeconomic growth, creating the first step toward sustainable energy development for the economy (BOE,2008). Later, in 2011, the New Energy Policy of Taiwan was released in response to the nuclear disaster inFukushima, Japan, its objective being to ‘Ensure Nuclear Security, Steadily Reduce Nuclear Dependence,
Create a Low-carbon Green Energy Environment & Gradually Move towards a Nuclear-free Homeland’(BOE, 2014b). Lastly, to cope with the worldwide energy challenges, in 2012, the BOE released Guideline
on Energy Development. Given that it is based on the Energy Administration Act, which enshrines theprinciples of ensuring energy security, protecting the environment and promoting economic development,
the guideline serves as the primary reference to the economy’s energy policy (BOE, 2012).
The three fundamental energy policies mentioned above encompass the specific acts for each energy
market and its management, including the Energy Administration Act, ‘The Electricity Act’, ‘Petroleum
Administration Act’, ‘Natural Gas Enterprise Act’ and ‘Renewable Energy Development Act’. These acts
aim to supervise energy enterprises, plan energy supply and demand, establish energy information systems,
promote energy saving measures, promote research and development (R&D) in the energy sector as well as
boost international energy cooperation.
The Framework of Taiwan’s Sustainable Energy Policy includes:
Policy objectives to create a win-win-win solution for the energy sector, the environment and theeconomy, and to set targets for improving energy efficiency, developing clean energy and securing
a stable energy supply;

Policy principles to establish a high efficiency, high value-added, low-emissions and low
dependency energy consumption and supply system;A two-part strategic framework for a cleaner energy supply and rationalised energy demand;

Follow-up work for government agencies to formulate concrete action plans which clearly set
carbon-reduction targets, to build monitoring and follow-up mechanisms to regularly review theeffectiveness and performance of the action plans and to establish quantitative objectives for eachtask in order to measure performance and facilitate implementation;



Targets for energy conservation, which aim to reduce energy intensity by 20% by 2015 (based on
2005 base levels), with a further reduction of 50% by 2025 through technology breakthroughs andappropriate administrative measures;

Targets for reducing carbon dioxide (CO2) emissions such that they return to the level in 2008
between 2016 and 2020, and reduce further to the level in 2000 by 2025; andPlans to establish a secure energy supply system to meet economic development goals.

Chinese Taipei declared the year 2010 as the ‘Year for Energy Conservation and Carbon Reduction’.
In order to promote the Framework of Taiwan’s Sustainable Energy Policy, Chinese Taipei set up a
Committee of Energy Conservation and Carbon Reduction in the Executive Yuan (the executive branch of
the government). The committee acts as the highest authority with regard to the State Energy Conservation
and Carbon Reduction Projects. The committee is chaired by the Vice Premier of the Executive Yuan withmembers from each ministry. The State Energy Conservation and Carbon Reduction Projects cover 10
major sectors and 35 landmark projects are underway to emphasise and implement key energy policies.
The New Energy Policy of Taiwan notes the following as the economy’s major strategies on nuclear
power (BOE, 2014b):Comprehensive safety examinations of nuclear power plants to ensure nuclear safety;

Steady reduction of nuclear energy dependence by actively reducing electricity demand and peakloads, and promoting alternative energy sources to ensure a stable power supply;

Refusal to grant any extension to the life spans of existing plants and proceeding with plant
decommissioning as planned;
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C H I N E S E T AI P E IRigorous security checks of the Fourth Nuclear Power Plant prior to its commercial operation;and

Early termination of operations at the First Nuclear Power Plant if the two reactor units of the
Fourth Nuclear Power Plant reach steady state before 2016.

Lastly, the Guideline on Energy Development reiterates the issues of security, efficiency and clean
policies for future energy supply and demand in Chinese Taipei. Apart from diversifying the sources andmethods of acquiring energy and enhancing the rate of its own energy production, Chinese Taipei is
promoting energy development and proliferation of energy new technologies. However, high costs andstability of supply continue to pose difficult questions. The development of accessible and affordable clean
energy domestically is a major challenge for technological research and will require new technology
breakthroughs (BOE, 2012).
ENERGY SECURITY

Since Chinese Taipei relies heavily on energy imports, the government has been striving to enhance overseas
supply security. To stabilise oil supply, the Petroleum Administration Act requires that refiners andimporters maintain 60 days of sales volumes (calculated from the average domestic sales and private
consumption over the preceding 12 months). The government uses the Petroleum Fund to finance thestorage of oil and also stockpiles 30 days of oil demand. The Act mandates that a liquid petroleum gas
stockpile of more than 25 days of supply be maintained (BOE, 2014a).
For many years, the Chinese Petroleum Corporation (CPC) has engaged in cooperative exploration
with governments and large international oil companies in operations throughout the Americas, the Asia–
Pacific region and Africa under the banner Overseas Petroleum and Investment Corporation (OPIC).
Following the rising cost of oil in recent years, the CPC has made strenuous efforts to develop upstream
exploration to secure oil sources. 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 in the hope of discovering new reserves of oil and natural gas.
As of the end of 2014, this cooperation extended to 22 fields spread over 8 economies.
Within Chinese Taipei, the CPC completed seismic surveys of about 48 km2 and geological surveys of
73 km2 and repaired four wells in 2014. There are currently 37 producing oil and gas wells in the Tiezhenshan,
Qingcaohu, Jinshui, Chuhuangkeng and Guantian fields, yielding 387 million cubic metres of natural gas
and 9 000 kilolitres (kL) of condensate annually.
In its future strategic deployment, the CPC will seek to leverage its situation in overseas explorationand production by optimising the value of its existing overseas oil and gas field assets, establishing core areas
with high rates of growth, participating actively in bidding for open blocks, seeking opportunities to takeover fields from major oil companies and pursuing opportunities for mergers and acquisitions in new oil
and gas fields so as to add further reserves (CPC, 2015).
ENERGY MARKETSELECTRICITY MARKETSThe government of Chinese Taipei aims to secure a total electricity supply with a reserve capacity of 15%(BOE, 2014a) based on peak demand. During the 1990s, some of the TPC’s new power plants were unable
to meet their construction schedules because of environmental issues and complex government approval
processes, thus reducing the total electricity supply below the required reserve capacity between 1990 and2004.
From 1990–95, the actual reserved capacity was between 4.7% and 7.4%, considerably lower than thethen targeted reserved capacity of 20%; therefore, the government decided to open the power generation
sector to IPPs, wherein the electricity produced by IPPs must be sold to the TPC through its transmission
lines. In 2013, the TPC provided 66% of the total installed capacity in 2012, sourcing 17% from IPPs and
17% from cogeneration plants.
In order to enhance the stability of the electricity supply, the TPC continues to improve its transmission
and distribution system. As of the end of 2013, several substation and transmission facilities underwent
retrofitting, including 87 units of transformers, 426 transmission towers, 543 circuit kilometres (ckt-km) of
overhead transmission lines, 301 ckt-km of ground lines and 46.9 ckt-km of overhead transmission linesthat were changed to underground cables. Modifications were also made to the distribution system by adding
512 newly expanded feeders (i.e. 44% of the total feeders were automated). These improvements are
expected to greatly reduce the duration of forced power outages. The System Average Interruption Duration
Index (SAIDI) was 18 minutes/customer-year and the System Average Interruption Frequency Index214

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C H I N E S E T AI P E I(SAIFI) was 0.27 frequency/customer-year in 2013. Despite the increase in power supply from the south to
the north, the line loss was controlled at a high standard of 4.3% (TPC, 2015).
To comply with the schedule for privatising the TPC and promoting the liberalisation of the domestic
power market, the Ministry of Economic Affairs (MOEA) has completed a program for the liberalisationof the electricity industry. Based on this program, a draft amendment to the Electricity Act was submitted
to the Legislative Yuan for review and was passed in the Executive Yuan on 16 July 2015. The draft notesthat:

IPPs will be allowed to sell power to consumers directly or via power distributors;

An independent system operator (ISO) will be established to dispatch power in a fair andtransparent manner; and

The TPC will continue to enjoy a monopoly in the power transmission sector.
FISCAL REGIME AND INVESTMENT

Chinese Taipei has limited indigenous energy resources and thus has no formal policy on investment in
upstream assets. However, in order to secure new energy sources, Chinese Taipei has invested in oil
exploration both in the Taiwan Strait and abroad through the state-owned enterprise, the CPC. Chinese
Taipei also welcomes the participation of foreign investors in bidding in the IPP electricity market.
ENERGY EFFICIENCYIn 2013, the total energy consumption classified by sector amounted to 33% for the energy and industrial
sectors, 17% for the transportation sector, 17% for the other sectors and 32% for non-energy uses. The
government considers it important to improve the energy efficiency of all industry sectors, especially energy
management in energy-intensive industries, and among major energy users. It amended the Energy
Management Act 1981 to establish an evaluation mechanism for energy development and utilisation to foster
gradual improvements in energy efficiency in newly constructed or expanded factory plants via advanced
management mechanisms (BOE, 2014a; EGEDA, 2015).
The major activities and achievements of Chinese Taipei with regard to energy intensity reduction andattaining government targets included the following (BOE, 2014a).
Successful completion of energy audits of major energy users and providing them assistance inestablishing internal energy auditing systems and reporting the results to the government: A totalof 4 658 high-energy users (3 242 manufacturers and 1 416 non-manufacturers) were audited by
the government in 2013. The audits showed that major energy users made energy savings of about
54 million litres of oil equivalent (Mloe).



Creation of an energy service team and provision of energy technology services to help energy
users diagnose their energy systems and improve their energy efficiency: A total of 592 companies
were visited in 2013, amounting to a potential energy savings of up to 107 Mloe.



Promotion of voluntary accreditation of high energy-efficient products and an energy labellingsystem since 2001: A total of 45 product categories were included in the energy labelling system,and 369 manufacturers and 7 671 brands gained accreditation by the end of 2013. In addition,
more than 165 million labels were issued in 2013.



Introduction of a mandatory multi-level energy efficiency labelling mechanism since July 2010:
Four product categories were included in the first stage, namely, air conditioning units,
refrigerators, vehicles and motorcycles. Humidifiers were included in March 2011, and fluorescentlamps, in July 2011. The program was scheduled to be expanded to gas stoves and instantaneous
gas water heaters in December 2012. In 2013, mandatory energy label applications were passed for
7 929 air conditioner, 1 159 refrigerator, 280 dehumidifier, 1 700 compact fluorescent lamp (CFL),
3 143 gas-fired water heater and 3 684 gas-fired furnace models.



Promotion of a series of demonstration projects pertaining to light-emitting diodes (LEDs) from2008: In 2011, the replacement of incandescent lighting with LED traffic lights saved an estimated247 GWh of energy, equivalent to nearly 0.2% of total electricity consumption by the sector. By
2013, nearly 300 000 mercury vapour streetlights had been replaced by LEDs, saving an estimated120 GWh of electricity.

Introduction of more technology and capital for energy saving through the promotion of Energy
Service Companies (ESCOs) by the BOE: The BOE extended support to the operations of the
Taiwan Association of Energy Service Companies and Taiwan ESCO Business Association. In
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2006, the BOE established an ESCO office to assist government institutions, schools and hospitals
with regard to utilizing ESCOs. Later, it expanded the program to the private sector, including the
low-carbon community and service industry. This program is estimated to have saved 55 GWh,amounting to an energy bill of TWD 190 million.
Continued focus on technology R&D programs: The major programs and achievements in the
R&D area included (BOE, 2014a):o Key technologies for smart energy-saving network systems: This program integrates energy
management technology, sensing and monitoring technology and information communication
technology to develop the key technologies, products and components for smart energy
network systems. The technology can be employed in existing systems without changing any
equipment and enables more flexible management of energy-efficient living environments andefficiency in the industrial manufacturing process. By 2012, this system was already employedin 1 570 convenience stores in Chinese Taipei and is ready for export or technology transfer toother economies. A total of 108 manufacturers are involved in this initiative, amounting to arevenue of TWD 1.8 billion in 2013.
o Air conditioning and refrigeration technologies: The air conditioning industrial chain in Chinese
Taipei is considerably advanced as most of the companies have their own R&D capability andare able to offer high efficiency products in accordance with government policy. Major projects
in this area include energy efficiency management for chillers as well as the development ofhighly efficient oil-free impellers with magnetic bearings. Other major achievements in 2013
were:





Promotion of the inverted impeller technology, wherein the test efficiency of the R-134a
500RT inverted impeller compressor reached CPO6.2 and IPLV9.7, both exceeding the2015 international standard.



Successful development of the 180RT impelled chiller with magnetic bearings: After the
US, Chinese Taipei was the second economy in the world to have achieved this milestone.
The chiller has been in operation in Industrial Technology Research Institute’s 64 thbuilding.

Establishment of an energy efficiency management network platform and an inspection
unit: Twelve chiller efficiency qualified logos have been issued and energy efficiency
inspection for chillers has officially started.

Advanced lighting technology: Given its various advantages (namely, energy saving, ecofriendliness, small volume, and easy control) solid-state lighting technology is the most promisingtechnology in terms of green lighting in the 21st century. In the past three years, there have beenmajor improvements in white-light LED technology, which now surpasses fluorescent light bulbs
in terms of efficiency. Thus, LED lighting has become one of the major projects of interest for
the green energy industry. The major achievements in this area in 2013 were:o Development of highly efficient white-light LED lighting technology, including advancements
in red phosphorescent material science, attaining a luminous efficiency of 22.4 lumens/watt @1 150 nits and an external quantum efficiency (EQE) of 14% at a wavelength (λ) of 604 nm.
o Development of smart LED surface light sources, LED intelligent lighting, and high-value
solid-state lighting luminary and system applications.
RENEWABLE ENERGY

The three main renewable energy (RE) industries in Chinese Taipei are photovoltaic (PV) power, wind
power and bioenergy. Chinese Taipei has chosen Penghu Island as a low-carbon demonstration site for the
economy. The government’s major efforts to promote RE industries in 2013 included the solar, wind andbioenergy sub-sectors, as detailed below (BOE, 2014a; 2015).
PHOTOVOLTAIC SYSTEMS

After the Renewable Energy Development Act was passed in 2009, a feed-in tariff mechanism replaced thesubsidies formerly used to promote RE. The new mechanism has attracted more private sector investment
to install PV systems. At the end of 2013, the total installed capacity was 392 megawatts (MW), withelectricity generated reaching 338 GWh.

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Chinese Taipei’s PV industry is based on crystalline silicon solar cell materials and components,
combined with upstream semiconductor materials and downstream industrial power systems. In 2013, the257 companies in this sub-sector earned a revenue of about TWD 157 billion. To increase the value andcompetitiveness of its PV industry in the global market, the government provides partial subsidies for theapplication of a building-integrated photovoltaic (BIPV) demonstration system.
WIND POWER SYSTEMSThe development of the wind power industry is vital mainly for the domestic market. The TPC and private
wind energy developers continue to develop onshore wind turbine systems. By the end of 2013, Chinese
Taipei had installed 311 sets of wind turbines domestically, with a total installed capacity of 614 MW and anannual output of 1 640 GWh of electricity. For offshore wind energy, a demonstration incentive program
was announced in July 2012, and in January 2013, three companies were selected to receive subsidies tobuild offshore wind demonstration projects.
BIOENERGY

The bioenergy industry includes the biodiesel, bio-methane, bio-heat and power industries. From June 2010,
the government of Chinese Taipei mandated the addition of 2% biodiesel in diesel used by transportation
vehicles. By the end of 2013, the consumption of biodiesel reached 96 000 KL and 11 companies wereapproved as qualified biodiesel manufacturers. The biodiesel industry mainly uses waste cooking oil as its
raw material (BOE, 2014a). Chinese Taipei also successfully conducted a demonstration project for adding
3% methane to gasoline used by transportation vehicles in major cities. In 2013, 14 gasoline stations
provided bio-methane whose total consumption reached 237 KL in 2013.
In addition to the application of biodiesel in the transportation sector, Chinese Taipei has a total of 740
MW of installed capacity employing bioenergy or waste as the input fuel, which generated 256 GWh ofelectricity in 2012.
RESEARCH AND DEVELOPMENT PROGRAMSThe Chinese Taipei Government continues to focus on technology R&D programs. The major
programs and achievements in this area in 2013 were as follows (BOE, 2014a).
Photovoltaic technology
The R&D focus included the development of high-efficiency silicon solar cells and thin-film devices, nextgeneration silicon solar cells and modules and dye-sensitised solar cell technology. The major achievements
in 2013 were:

Development of thin silicon wafer solar cell fabrication using atomic layer deposition of thickness
150 micrometres (µm), efficiency 19.5% and silicon material of specification 5.1 grams/watt.



Development of heterojunction silicon-based solar cells passivation technology and improved
wafer carrier lifetime, enhancing the open circuit voltage of the solar cells and increasing cell
efficiency by up to 20%.



Mass production of a 60 × 120 centimetres chemical bath deposition apparatus; the related
technology and patent authorization is under discussion with solar cell and apparatus companies.

Bioenergy
R&D in this area focusedmicroalgae biofuel technologies.

on

the

lignocellulosichydrolysis

technology

and

key

Wind power
R&D in this sub-sector focused on developing offshore wind power engineering technology and equipment,
and the establishment of a comprehensive systems analysis and integration design capacity. Chinese Taipei
also conducts R&D on product differentiation and energy security, to develop specific projects forenhancing the global competitiveness of the local wind power industry. The major achievements in 2013
were as seen below.
Onshore wind power: Established a monitoring platform that collects operational status of theeconomy’s wind farm and wind turbines, providing the maintenance companies auxiliary
information to maintain the wind farms and wind turbines.

Offshore wind power: Completed development of offshore wind farm operation and maintenance(O&M) technology, evaluated 30 sets of 3.6 MW wind farms located 5–10 km offshore, anddevised appropriate maintenance strategies for the same.
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Fuel cell and hydrogen applications
To promote hydrogen and distributed power generation technologies, the first R&D project in this area
focused on the development of fuel cell applications using hydrogen, supported by advanced production
and storage technologies for hydrogen. The major achievements in 2013 included:Completion of the palladium membrane mass production test, which enhanced the production
rate fourfold compared to the original rate.

Successful mass production of low-cost bipolar plate material and a smart cell stack manufacturingsystem.
NUCLEAR ENERGY

Since Chinese Taipei is short of indigenous energy, the government encourages developments in nuclear
energy to diversify its power generation mix. Currently there are four nuclear power plants in Chinese Taipei,
of which three are operational and one is under construction. In 2013, the total installed capacity of thethree operational nuclear power plants was 5 144 MW, accounting for 17% of the economy’s total power
generation mix.
In response to the Fukushima accident in 2011, Chinese Taipei released a New Energy Policy on 3
November 2011 to ‘ensure nuclear security, steadily reduce nuclear dependence, create a low-carbon green
energy environment and gradually move towards a nuclear-free homeland’. This policy aims to steadily
reduce nuclear dependence by lowering electricity demand and peak loads, and by promoting alternative
energy sources to ensure a stable power supply.
The new policy prohibits life-span extensions for existing nuclear plants and outlines decommissioning
plans as follows: Units 1 and 2 of the first plant will be decommissioned in 2018 and 2019; Units 1 and 2 ofthe second plant, in 2021 and 2023; and Units 1 and 2 of the third plant, in 2024 and 2025.
Construction of the Fourth Nuclear Power Plant was halted as a result of public concern over thesafety of building such a unit in an earthquake-prone region. The government has stated that this suspension
does not necessarily mean an abandonment of its plans to construct the plant; however, the future of the
Fourth Plant remains undecided.
CLIMATE CHANGE
GREENHOUSE GAS EMISSIONS

Chinese Taipei produces CO2 emissions that account for about 1% of global emissions. Therefore, thegovernment believes it has a moral obligation to reduce emissions even though the economy is not a memberof the United Nations, and as a consequence is not eligible to sign the Kyoto Protocol or directly required
to adhere to its 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 thus necessary for Chinese Taipei to seek
alternative ways to reduce the impact of its carbon emissions (BOE, 2008).
In 2011, Chinese Taipei established the ‘Energy Conservation and Carbon Reduction Service Team’,
which includes a ‘Technology Service Group’, an ‘Advocacy Group’ and a ‘Volunteer Group’, to provide
technology consulting services to all energy users and the public. By the end of 2011, the Service Team had
acted on 2 860 calls for field assistance, organised 198 training workshops and seminars, and answered 12
128 remote help calls via the telephone or internet.
In 2008 and 2009, total CO2 emissions showed negative growth for the first time in 20 years. Carbon
intensity also showed a decrease of 3.6% for 2010 and 1.7% for 2011.
Emissions from fossil fuel combustion are the major source of greenhouse gas (GHG) emissions in
Chinese Taipei. The economy emitted 250 Mt of CO2 in 2013, 0.7% higher than 2012. Between 2008 and2013, CO2 emissions amounted to 245 Mt to 250 Mt, an annual reduction of 0.4%. In 2013, the economy
reduced CO2 emissions by 5 Mt, exceeding the stated reduction target of 4.16 Mt by 121%. To reduce theenvironmental impact of its development, Chinese Taipei must seek the most advantageous development
objectives for the economy from among the various policies on environmental protection, industrial
development and energy supply (BOE, 2014a).
PROMOTION OF LOW-CARBON ENERGY TECHNOLOGY AND INDUSTRY

Chinese Taipei’s green energy industry has achieved several key milestones. However, if it is to continue
responding to future developments and competition, it needs to gain full access to key and innovativetechnologies. Faced with fierce competition globally, the economy is strengthening its R&D and innovation
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capabilities so that it can master niche technologies and enhance the economy’s competitiveness. Chinese
Taipei has been ranked sixth by the International Institute for Management Development in terms ofcreating competitive advantages in the green technology industry.
The development of emerging industries such as the green energy industry depends on the economy
changing its traditional focus from export processing to an industrial model that involves the aggressive
development of key technologies. The latter will compensate for the lack of independent intellectual
property rights development in the past. Chinese Taipei has gradually changed its mainstream industrial
model from that of original equipment manufacturer (OEM) to that of original design manufacturer (ODM).
The focus now is on enhancing the integration of the industrial chain and transforming development strategy
from one concerned with manufacturing key components into one that utilises vertical system integration.
This will enhance the international competitiveness of the economy’s green energy industry and help
entrench the importance of value creation over production output.
To create an energy-efficient society and low-carbon economy, in 2009, Chinese Taipei selected sevengreen energy industries that showed development potential in terms of their information technology (IT)status and human resources. The PV and LED lighting industries are regarded as the most significant of
those seven green energy industries. Other promising industries include the wind power, biomass, hydrogenand fuel cell, energy information communication technology (EICT) and electric vehicle industries. Total
revenue from these green energy industries was TWD 420 billion in 2013, recording a growth of 163%
compared with 2008. Cumulative new investments from 2009 to 2012 amounted to TWD 275 billion,
accompanied by the creation of new employment opportunities for 68 250 people from 2008 to the end of2013.
N OTA B L E E N E RG Y D E V E L O P M E N T S
THE MILLION SOLAR ROOFTOP PROGRAM

In response to public concerns about nuclear safety after the Fukushima earthquake, Chinese Taipei
comprehensively reviewed the possibility of expanding the development of RE from mid-2011. The BOE
established an office to promote the ‘Million Solar Rooftop Program’ on 28 March 2012. The Promotion
Office intends to foster a PV-friendly environment in Taiwan and assist governments and industries inpromoting solar PV installations, the aim being to reach a capacity of 6 200 MW by 2030 (BOE, 2014c).
By integrating related resources for harnessing solar energy, the Promotion Office helps resolve
barriers hindering the installation of solar energy generation systems. The Promotion Office was established
as a single window for total solutions for local solar energy businesses, city and county governments, andsystem installation contractors in the utilisation of solar energy.
Due to the decreasing cost of solar PVs, their installation in Chinese Taipei has increased significantly.
The total installed PV capacity in 2013 was 392 MW and grew rapidly to 620 MW in 2014. In 2015, theinstallation target for PVs was revised from 6 200 MW to 8 700 MW by 2030.
THE THOUSAND WIND TURBINES PROGRAM

Chinese Taipei has an estimated wind potential of more than 15 GW. To accelerate the development of thewind energy industry, Chinese Taipei plans to shift its focus from onshore wind energy to offshore windenergy, and set up more than 1 000 wind turbines by 2030. The accumulated capacity of wind energy willthus reach 4 200 MW by 2030 (BOE, 2014c).
The economy intends to begin by developing superior onshore wind energy farms before harvestingfrom secondary wind energy farms. A demonstration incentive scheme was announced to encourage
developers to set up three pioneering offshore wind energy farms in shallow waters (at depths below 20
metres) by 2015. The capacity of each wind farm is 100–200 MW. Chinese Taipei has earmarked TWD 250
million toward wind farm development, which includes an equipment subsidy of 50% for the first two
turbines of each wind farm. The economy plans to learn from the experiences gained from thesedevelopments before exploiting areas with deeper water (depths above 20 metres) at the mass production
scale. By 2030, the economy plans to develop 450 onshore wind turbines of 1 200 MW and 800 offshore
wind turbines of 4 000 MW, respectively. The total accumulated capacity would add up to 5 200 MW,
comprising about 30% of Chinese Taipei’s RE targets (TWTP, 2015).

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REFERENCES

BOE (Bureau of Energy, Ministry of Economic Affairs) (2008), Framework of Taiwan’s Sustainable Energy
Policy, http://web3.moeaboe.gov.tw/ECW/english/content/Content.aspx?menu_id=1524.
–– (2012), Guideline on Energy Development (Chinese Version),
http://web3.moeaboe.gov.tw/ECW/populace/news/News.aspx?kind=2&menu_id=56&news_id=2565.
–– (2014a), 2014 Annual Report,
http://web3.moeaboe.gov.tw/ECW/populace/content/ContentLink.aspx?menu_id=137.
–– (2014b), New Energy Policy of Taiwan,
http://web3.moeaboe.gov.tw/ECW/english/content/Content.aspx?menu_id=969.
–– (2014c), Million Solar Rooftop Program,
http://web3.moeaboe.gov.tw/ECW/english/content/SubMenu.aspx?menu_id=1832.
–– (2015), Energy Statistics Handbook 2014,
http://web3.moeaboe.gov.tw/ECW/english/content/SubMenu.aspx?menu_id=1537.
CPC (Chinese Petroleum Corporation) (2015), CPC 2015 Annual Report,
http://en.cpc.com.tw/annual_reports.aspx.
National Statistics (2015), National Statistics, R.O.C. (Taiwan),
http://eng.stat.gov.tw/mp.asp?mp=5.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), website‘APEC Energy Database’ page, http://www.ieej.or.jp/egeda/database/database-top.html.
EIA (Energy Information Administration) (2015), International Energy Statistics,
www.eia.gov/countries/country-data.cfm?fips=TW.
TPC (Taiwan Power Company) (2015), TPC Disclosure of Information,
www.taipower.com.tw/content/new_info/new_info-a52.aspx?LinkID=5.
TWTP (Thousand Wind Turbines Project) (2015), Project Introduction – Targets,
www.twtpo.org.tw/eng/intro/goal.aspx.
USEFUL 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
Industrial Development Bureau, Ministry of Economic Affairs—www.moeaidb.gov.tw
Ministry of Economic Affairs—www.moea.gov.tw
Ministry of Transportation and Communications—www.motc.gov.tw
Taiwan Power Company—www.taipower.com.tw

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THAILANDI N T ROD U C T I O NThailand has been known as ‘the window to South-East 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 sharesborders with Malaysia to the south. Thailand had an area of 513 115 square kilometres (km2) and a
population of about 67.5 million in 2013. Its GDP that year reached USD 915 billion (2010 USD purchasing
power parity [PPP]), a 2.9% increase from USD 889 billion in 2012. In the same period, GDP per capita
increased 2.5%, from USD 13 236 (2010 USD PPP) to USD 13 561 (2010 USD PPP). The largest
contributors to its GDP were the services (41%) and manufacturing (29%) industries (NESDB, 2015).
Thailand has limited energy resources. At the end of 2013, Thailand had proved reserves of 427 million
barrels of oil, 285 billion cubic metres of natural gas, and 1 239 million tonnes of coal. Based on its
production rate in 2013, it will deplete its domestic supply very soon―oil resources within three years andnatural gas in six years (BP, 2015). Most coal in Thailand is lignite, which is a low rank coal with highemissions. Notwithstanding its resources, Thailand is highly dependent on energy imports, particularly oil,with about 85% of its oil supply coming from imported stock in 2013, as well as 22% of its gas supply(DEDE, 2015a).
Table 1: Key data and economic profile, 2013
Key dataa

Energy reservesb

Area (thousand km2)

513

Oil (million barrels)

462

Population (million)

67.5

Gas (billion cubic metres)285

GDP (2010 USD billion PPP)

915

Coal (million tonnes)

GDP (2010 USD PPP per capita)

13 561

1 239

Uranium (kilotonnes of U)

Sources: a. EGEDA (2015); b. BP (2015).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLY

Thailand’s total primary energy supply in 2013 was 114 888 kilotonnes of oil equivalent (ktoe), which
represented an increase of 3.5% from 2012. Oil accounted for 39.4% of the total primary supply, while gas,coal and others accounted for roughly 42%, 13% and 5.5%, respectively. It is the first time that the gas
supply surpassed the oil supply. As most of Thailand’s proved coal reserves are lignite coal with lower
calorific values, imported stock is needed to meet the energy demand for both power and industry sectors.
In 2013, coal supply was 15 345 ktoe, up 3.5% from the previous year.
Natural gas supply in 2013 was 48 002 ktoe, a 5.1% increase from 45 658 ktoe in 2012. Althoughnatural gas is mostly used for power generation in Thailand, it is also promoted in the transport sector as areplacement for conventional petroleum products such as fuel oil, 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 2013, total electricity generation was 197 629 gigawatt-hours (GWh). Thermal generation, mostly
from natural gas and coal, accounted for nearly all of its power generation (83%), 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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Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

64 088 Industry sector

19 018 Total power generation

197 629

Net imports and others

55 635 Transport sector

22 916

Thermal

164 145

Total primary energy supply

114 888 Other sectors

15 092

Hydro

8 642

Coal

15 345 Non-energy

22 611

Nuclear–Oil

45 275 Total final energy consumption

79 636

Others24 843Gas

48 002

Coal

5 563

Others

6 266

Oil

51 960Gas

7 928

Electricity and others

14 185

Source: EGEDA (2015).
NATURAL GAS

Thailand’s proved gas reserves at year-end 2014 amounted to 7.8 trillion cubic feet (Tcf), consisting of 7.4
Tcf in gas fields in the Gulf and 0.3 Tcf in onshore areas. Compared with the previous year, the proved gas
reserves fell by 0.7 Tcf (about 7.9%). The main reason for this drop was continued production without new
field discoveries (DMF, 2015). Natural gas production in Thailand began in 1981 in the Erawan field; todate, additional major gas fields have been discovered: Bong Kot, JDA (Thailand-Malaysia Joint
Development Area), Arthit and Pailin. In 2014, domestic natural gas production was at a level of 4 703
million standard cubic feet per day (MMscfd), accounting for 80% of Thailand’s gas. The remaining 20%
was imported from Myanmar, 843 MMscfd, and imported LNG, 182 MMscfd, for a total natural gas supply
in Thailand of 5 098 MMscfd. LNG was imported in Thailand starting in May 2011 (EPPO, 2015a).
CRUDE OIL AND CONDENSATEAt the end of 2014, Thailand’s proved reserves of oil and condensate reserves stood at 387 million barrels(Mbbl), of which 326.5 Mbbl came from the Gulf and 60 Mbbl from onshore areas. The total proved
reserves fell by 53.9 Mbbl (12%) from the previous year. Condensate reserves in the Gulf fell similarly tonatural gas reserves. Falling oil prices, which made platforms with low production rates uneconomic,
resulted in a reduction of proved reserves, despite the new production areas, including the Manora Field in
the Gulf, which came on line in late 2014, and Wichian Buri (onshore), which included the discovery of new
volcanic reservoirs (DMF, 2015). The accumulated domestic oil production in 2014 was 138 758 barrels perday (bbl/d). The major crude oil fields in Thailand are comprised of Benjamas, Sirkit, Tantawan, Jasmin and
the Big Oil Project of Unocal (Thailand) Co. Ltd (EPPO, 2015a).
COAL/LIGNITE

Thailand has lignite (low-grade coal), which can be utilised for 70 years. Domestic lignite production is fromtwo major sources. One source is the mines of the Electricity Generating Authority of Thailand (EGAT)
and the other is the mines of private producers. There are two sources of EGAT’s lignite. The first is theMae Moh mine in Lampang province, used as fuel for power generation at the Mae Moh Power Plant for
the northern part of Thailand. The second source is the Krabi province, which serves the demand from theindustrial sector in southern Thailand. Most of the imported coal is sub-bituminous and bituminous. The
amount of coal imports have been increasing continuously because domestic lignite concessions have begun
to expire and the price of coal is cheap compared with other energy prices (EPPO, 2015a).
ELECTRICITYThe EGAT used to be the sole power producer in Thailand. Later, the government promoted the private
sector role in power generation in order 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, resulting in an improvement in power generation and service quality.
Currently, the use of renewable energy in power generation has been promoted, resulting in a growing
number of very small power producers (VSPP) using renewable energy as main fuel to supply power to thegrid. In the last decade, Thailand’s overall electricity capacity has been increasing. The electricity capacity of
EGAT decreased proportionally from 60% in 2005 to 45% in 2014, whereas there was a large increase in
IPP, SPP and imported electricity. In 2014, Thailand’s power generating capacity stood at 34 668 megawatts
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(MW), divided into the generating capacity of EGAT, 45%; IPP, 38%; SPP and VSPP, 10%; and imported
electricity from Lao PDR and exchange with Malaysia, 7% (EPPO, 2015a).
FINAL ENERGY CONSUMPTION

Thailand’s total final energy consumption in 2013 was 79 636 ktoe, an increase of 7.1% from the previous
year. The transport sector was the largest energy-consuming sector, accounting for 22 916 ktoe, or 29% of
total final energy consumption. The second largest energy consumer was the industrial sector, which
consumed 19 018 ktoe in 2013, an increase of 0.8% from 2012. Beside the energy-consuming sectors, nonenergy products, which are mostly used in the industry sectors as feedstock, account for 28% of the total
final energy consumption, or 22 611 ktoe. By fuel type, oil accounted for 65% (51 960 ktoe) of total energy
consumption in 2012, followed by electricity and others (18%), gas (10%) and coal (7%).
Natural gas demand increased significantly by 18%, from 6 703 ktoe in 2012 to 7 928 ktoe in 2013. Oilconsumption also increased by 10.2%, from 47 158 ktoe in 2012 to 51 960 ktoe in 2013. In contrast, coalconsumption decreased significantly by 16%, from 6 643 ktoe in 2012 to 5 563 ktoe in 2013. Domestic
electricity and other energy demand in 2013 increased by 2.3% from 13 871 ktoe in 2012 to 14 185 ktoe in
2013. The growth in demand in 2013 was mainly due to increased consumption in the transport sectors andthe use of non-energy products.
ENERGY INTENSITY ANALYSIS

Thailand’s energy intensity (energy consumption/GDP) of its primary energy in 2013 was 126 tonnes of oil
equivalent per million USD (toe/million USD), which increased by 0.6% from 125 toe/million USD in2012. The energy intensity of final energy demand increased 4.1%, from 84 toe/million USD in 2012 to 87
toe/million USD in 2013. The energy intensity of the industry and transport sectors decreased by 2.1% and1.2%, respectively, while the energy intensity of the others sector, which mainly include the commercial andresidential sectors, decreased significantly by 5.4%. The energy intensity of the non-energy products sector
increased significantly by 26%. When excluding non-energy products, the energy intensity of the final energy
demand decreased 2.7% from the previous year.
Table 3: Energy intensity analysis, 2013
Change (%)

Energy Intensity (toe/million USD)

Energy2012

20132012 vs 2013

Total primary energy supply

125

126

0.6

Total final energy consumption

84

87

4.1

Industry

21.2

20.8

–2.1

Transportation

25.4

25.1

–1.2

Other sectors

17

16

–5.4

Non-energy

20

25

26

Source: EGEDA (2015).
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:

establishing energy 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; and

supporting energy developments domestically and internationally while simultaneously protecting
the environment and mitigating climate change.
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The Ministry of Energy is the main government institution responsible for energy policy in Thailand.
Under the Ministry, there are six departments and four state enterprises as follows.


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—regulates energy quality and safety standards, environment andsecurity, and improves the standards to protect consumers’ interests;



Department of Mineral Fuels—facilitates energy resource exploration and development;Energy Policy and Planning Office (EPPO)—recommends economy-wide energy policies andplanning;Electricity Generating Authority of Thailand (EGAT)—the state power generating enterprise;Petroleum Authority of Thailand (PTT) Exploration and Production (E&P) Public Company
Limited and the Bangchak Petroleum Public Company Limited—two autonomous publiccompanies;Energy Fund Administration Institute—a public organisation; andEnergy Regulatory Commission (ERC) and the Nuclear Power Program Development Office—
two independent organisations.

According to the recent energy policy established under the government of Prime Minister Prayuth
Chan-o-cha and presented to the National Legislative Assembly of Thailand on 12 September 2014, theenergy price structure would be reformed to reflect actual costs and taxes for different types of fuels anddifferent groups of consumers. This reformation of the energy price structure would lead to energy
efficiency, consumer awareness and behaviour changes. On the supply side, the government will proceedwith new surveys and exploration for oil and gas, both onshore and off. Additionally, the construction of
new power plants using fossil fuels and all renewable energy by state-owned enterprises and the private
sector will be pursued continuously through open consultation with the public, transparency and fairness aswell as accounting for environmental concerns. The development of energy resources together withneighbouring countries is also 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, 2015b), under the three principles of economy, ecology and security. The
blueprint consists of five long-term plans including the Power Development Plan (PDP2015) (EPPO,
2015c), the Energy Efficiency Development Plan (EEDP2015) (EPPO, 2015d), the Renewable andAlternative Energy Development Plan (AEDP2015), the Gas Plan 2015 and the Oil Plan 2015. All the plans
have been updated and developed to cover the same time period, 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 thetotal generating capacity by 2036.

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Figure 1: The Development of Thailand 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 to achieving a sufficient and stable energy supply. It will do this by:advancing the exploration and development of energy resources at domestic and international
levels;

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 fuel mix and setting reserve margins
greater than 15%. The PDP2015 has already included energy savings from the EEDP2015, which identifies
89 672 GWh of electricity saving. The building sector is expected to deliver the biggest savings through avariety of measures such as building energy codes, minimum energy performance standards (MEPS)/highenergy performance standards (HEPS) and promotion of LED use. Electricity demand will be reduced
through the EEDP2015 by 89 672 GWh or 22% compared to BAU (business as usual). The targets of power
generation from renewable energy under the AEDP are also included in the PDP2015. Generating capacityof 20 GW from solar, biomass, wind, hydro and 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 along-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 years. To maintain a degree of energy security, the economy mustpursue new explorations quickly. Since 1971, the Department of Mineral Fuels (DMF) has launched 20
concession-bidding rounds, the latest announced in 2007. In 2014, the DMF invited bids for explorationand production 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 theconcession-biddings (DMF, 2015).
To secure a natural gas supply for the long-term, the PTT Public Company Limited entered into acontract to buy 2 million tonnes of LNG per year for the next 20 years from the Qatar Liquefied Gas
Company Limited (Qatargas). The first stock of imported LNG was delivered to Thailand in January 2015.
The Ministry of Energy 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 power from Lao PDR. The latest projectis the Hong Sa coal power plant, which expects to connect 1 500 MW to the grid in 2016.

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FISCAL REGIME AND INVESTMENT
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 an appropriate fuel price structure that supports the development of energy products andthat 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 supervising energy prices through market mechanisms to ensurethat domestic energy prices are stable, fair and affordable, and reflect the actual production costs. The energy
costs for Thai people must not be higher than those in neighbouring economies. The government issupervising the pricing policies and price structures of oil, LPG and natural gas to align them with world
market mechanisms and to reflect actual costs; ensuring fairness for the general public through the efficientuse 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 reduceenergy 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 Investor Relations Office, 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 rigs.
ENERGY EFFICIENCY

The first long-term energy policy on energy efficiency, namely the EEDP, was launched in 2011 with a target
to reduce energy intensity (EI) by 25% in 2030 from 2010 levels, or equivalent to a reduction in final energy
consumption of 24% in 2030 (38 200 ktoe). The EEDP set the targets of energy reduction for major
economic sectors including transportation, industry, and commercial and residential in six strategic areas:

Apply a number of combined measures, for example mandatory measures via rules, regulations andstandards, and promotional and supportive measures via incentive provision;

Introduce measures that will have a wider impact in terms of raising awareness and changing
behaviour related to the energy consumption of consumers, including the decision-making
behaviour of business operators, as well as market transformation;Support the potential and important role of the private sector in the public-private partnership topromote and implement energy conservation measures;Delegate tasks related to the promotion of energy conservation in public and private
agencies/organisations that are readily equipped with resources and expertise, such as power
utilities and industrial associations, with backup support from the Ministry of Energy;Use professionals and energy services companies (ESCO) as important tools to provide consultancy
and to implement energy conservation measures in which the use of more advanced technology is
involved; andIncrease self-reliance in indigenously developed technology to reduce technological costs and toincrease access to energy-efficiency technology including the promotion of highly energy-efficient
product manufacturing processes.

To implement the plan, 16 specific measures were established under five overarching approaches. The
approaches and measures are as follows.

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MANDATORY REQUIREMENTS VIA RULES, REGULATIONS AND STANDARDSEnforce the Energy Conservation Promotion Act B.E. 2535 (1992), which would put in effect anenergy management system based on energy consumption reporting and verification imposed on
designated buildings and factories;

Introduce mandatory energy efficiency labelling to provide options for consumers to buy or use
highly energy-efficient equipment/appliances, vehicles and buildings;

Enforce the MEPS for equipment/appliances, buildings and vehicles to prevent the distribution
and use of low energy-efficient products;



Determine the Energy Efficiency Resource Standards (EERS), or the minimum standards for large
energy businesses to implement energy conservation measures, encouraging their customers to use
energy efficiently, which will be an important mechanism for providing both technical and financial
assistance to small and medium enterprises (SMEs).

ENERGY CONSERVATION PROMOTION AND SUPPORT

Promote a ‘voluntary agreement’ to save energy within the public and commercial/industrial sectors,
especially among various business associations and large-scale businesses;



Support and incentivise provision to encourage voluntary energy-efficiency labelling for highly
energy-efficient equipment/appliances, buildings and vehicles;Promote travelling by mass transit systems as well as goods transportation by highly energy-efficientlogistics systems;

Subsidise investment in the implementation of energy conservation measures by (a) providing
subsidies for the amount of energy saved that can be verified, as per the project proposals approved
under the DSM (demand-side management) bidding scheme for large-scale businesses, and (b)providing subsidies for the amount of energy saved and/or reduction of peak load that can beverified or accurately assessed for SMEs, as per the project proposals submitted under the Standard
Offer Program (SOP) scheme, which requires no bidding;Support the operation of ESCO companies (e.g. the use of funding from the Energy Conservation
Promotion Fund to increase credit lines given by the ESCO Fund) to alleviate the technical andfinancial risks of entrepreneurs wishing to implement energy conservation measures.

PUBLIC AWARENESS CREATION AND BEHAVIOURAL CHANGE

Promote public relations and the dissemination of knowledge about energy conservation to thegeneral public via the teaching/learning process at educational institutions, fostering youth
awareness and other public awareness activities such as eco-driving;Put forth the concepts and promotional activities related to the development of a low carbon
society and low carbon economy; this will bring about cooperation between local administration
organisations and the business sector in the planning and implementation of activities that can leadto a reduction of GHG emissions and efficient use of energy;

Set energy prices that reflect actual costs and application of tax measures as an important tool topromote energy conservation with a view to fostering public awareness and changing energy
consumption behaviour.

PROMOTION OF TECHNOLOGY DEVELOPMENT AND INNOVATIONPromote research and development (R&D) that improves energy efficiency and reduces
technological costs, particularly those related to equipment/appliances with large markets andmanufacturing in Thailand including production processes and materials as well as buildings andhousing that are energy efficient;Promote demonstrations of energy-efficient technologies that have been technically proven but not
yet commercialised in the domestic market including the support for any necessary preparation to
implement wide commercial deployment of such technologies.

HUMAN RESOURCES AND INSTITUTIONAL CAPABILITY DEVELOPMENTSupport the development of professionals in the energy conservation field so that they will havethe needed skills to be responsible for energy management and operation, verification and
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monitoring, consultancy and engineering services provision and the planning, supervision andpromotion of the implementation of energy conservation measures;Support the development of the institutional capabilities of agencies/organisations in both the
public and private sectors responsible for the planning, supervision and promotion of theimplementation of energy conservation measures.

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) andendorsed by the cabinet in early 2013. The plan includes 67 major measures/projects. Most of the measures
are sector-wide. The rest are sector-specific measures that include 18 in the transport sector and fivemeasures in each of the following sectors: industry, large commercial building and small commercial building
and residential. The total amount of energy saved by the plan is expected to be 38 845 ktoe, with 16 257
ktoe from the industry 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
directions in line with the EEAP and EEDP framework.
Recently, the EEDP has been updated using the same timeframe with other energy plans (e.g. 2015–36) and is now known as the ‘Energy Efficiency Plan 2015’ or ‘EEP2015’. The EEP2015 set a target to
reduce energy intensity (EI) 30% by 2036 from 2010 levels. This savings target equals 56 142 ktoe, which iscomprised of 7 41 ktoe of electricity (or 89 672 GWh) and 44 059 ktoe of heating. It also equates to a 30%
reduction in BAU energy consumption in 2036 (EPPO, 2015d).
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 renewable
and alternative development plan during the last 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 the Thai Government will encourage the use of indigenous resources,
including renewable and alternative energy (particularly for power and heat generation), and supports theuse of 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 and continuously promotes
R&D in all forms of renewable energy.
To achieve these targets, Thailand has set up incentive programs and mechanisms to encourage
investment, such as the Fund for Energy Services Companies, which act as special-purpose vehicles forrenewable energy development projects, and investment grants from the Energy Conservation Fund. Someof the previously successful self-workable measures, such as the Revolving Fund that provides low interest
rates, will be terminated.
Recently, the AEDP has been updated for the time frame 2015–36, now called AEDP2015. The
AEDP2015 sets a target for renewable energy share of 30% of total final energy consumption by 2036. Thistarget is equal to 39 389 ktoe, which can be divided into power generation of 19 684 ktoe, heating of 25 088
and biofuels of 8 712 ktoe. The breakdown of this target is shown in Table 4.

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Table 4: The AEDP’s Targets by 2036
Type of Energy

Targets in 2036

Electricity
1. Municipality Waste
2. Industrial Waste
3. Biomass
4. Biogas (Sewage/Waste)
5. Small Hydro Power
6. Biogas (Energy crop)
7. Wind
8. Solar
9. Large Hydro Power
Heating
1. Waste to Energy
2. Biomass
3. Biogas
4. Solar
5. Others
Biofuels
1. Biodiesel
2. Ethanol
3. Pyrolysis-Oil
4. Compressed biogas (CBG)
5. Others
Renewable Energy Consumption

5 588

ktoe

19 684

MW

500
50
5 570
600
376
680
3 002
6 000
2 904

MW
MW
MW
MW
MW
MW
MW
MW
MW

25 088ktoe

495
22 100
1 283
1 200
10

ktoe
ktoe
ktoe
ktoe
ktoe

8 712

ktoe

14
11
0.5
4 800
10

million litre/day
million litre/day
million litre/day
tonne/day
ktoe

39 388ktoe

Source: AEDP2015, DEDE (2015b).
NUCLEAR ENERGY

Nuclear power is recognised as one of the alternative energy resources, which provides low emissions andcheaper prices compared with fossil fuels and renewable energy. The Thailand 20-Year Power Development
Plan (PDP2010) had included 5 GW of nuclear power, with the aim to ensure sufficient energy supply anddiversify the power energy mix. After the Fukushima Daiichi Nuclear Power Plant disaster caused by theearthquake and tsunami in March 2011, the Second Revision 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 out 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 total generation capacity. The latest PDP2015, which encompasses the time frame
2015–36, includes 1 GW of nuclear power to the grid in 2035 and another 1 GW in 2036.
CLIMATE CHANGE

Climate change is one of the important policies in Thailand, even though in 2012 Thailand contributed toonly 0.8% of the global GHG emissions. In terms of GHG emissions per capita and per GDP, Thailand islower than the world average. In Thailand’s Second National Communication, it indicated that 67% of its
total GHG emissions comes 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 its
Climate Change Master Plan 2015–50 states. The master plan provides a continuous framework formeasures and actions over the long-term that 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 UNFCCC.
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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
THAILAND’S INTEGRATED ENERGY BLUEPRINTThe Ministry of Energy has achieved one of its significant milestones in accordance with the government’s
policy to ensure domestic energy security. It has established a comprehensive energy plan, namely the TIEB,
under 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 process of theseplans is 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 on 3–7 August 2015. The final report was endorsed by the EWG (Environmental Working Group)
members December 2015. There are 48 recommendations to Thailand on energy efficiency intransportation, covering six key issues including: 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.
REFERENCES

BP (2015). Statistical Review of World Energy 2015. www.bp.com/statisticalreview.
DEDE (Department of Alternative Energy Development and Efficiency) (2015a). Energy Balance ofThailand. Ministry of Energy. www.dede.go.th–– (2015b). Alternative Energy Development Plan: AEDP2015. Ministry of Energy. www.dede.go.th
DMF (Department of Mineral Fuels) (2015). Annual Report 2014. Ministry of Energy. www.dmf.go.th
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, http://www.ieej.or.jp/egeda/database/database-top.html.
EPPO (Energy Policy and Planning Office) (2015a). Energy Statistics of Thailand 2015. Ministry of Energy.
www.eppo.go.th.
–– (2015b). Thailand Integrated Energy Blueprint 2015-2036. Ministry of Energy. www.eppo.go.th–– (2015c). Power Development Plan (PDP2015). Ministry of Energy. www.eppo.go.th–– (2015d). Energy Efficiency Plan (EEP2015). Ministry of Energy. www.eppo.go.th
NESDB (Office of the National Economic and Social Development Board) (2015). National Accounts ofThailand 2013, Office of the Prime Minister, www.nesdb.go.th.
ONEP (Office of Natural Resources and Environmental Policy and Planning) (2015). Thailand’s Intended
Nationally Determined Contribution (INDC).
Sutabutr, T. (2015). Overview of Thailand Integrated Energy Blueprint. Presented at the APERC Annual
Conference, 9–10 June 2015.
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.
USEFUL 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.th230

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Ministry of Energy (MoEN)—www.energy.go.th
Prime Minister’s Office—www.opm.go.th231

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UNITED STATESI N T ROD U C T I ON

The United States (US) is the world’s largest economy with a GDP of USD 15.9 trillion (2010 USD
purchasing power parity [PPP]) in 2013 (EGEDA, 2015). The US spans 9.9 million square kilometres (km2)
and has a population of 316.5 million people. The economy’s population growth rate has continued to
decline from the rate of 1.1% in 2000 to 0.8% in 2013 (EGEDA, 2015).
The US enjoyed a long economic expansion from 1990 to 2000, recording a growth of 3.4% in realterms, which then slowed down to a rate of 1.7% from 2000–13. In 2013, economic growth declined slightly,
from 2.3% to 2.2%, compared with 2012 (EGEDA, 2015).
The US is the second-largest producer and consumer of energy in APEC. It is rich in energy resources.
In 2013, the US had 49 billion barrels of proven oil reserves, 9.6 trillion cubic metres (tcm) of natural gas
reserves and 237 billion tonnes of coal reserves (BP, 2015).
Table 1: Key data and economic profile, 2013
Key dataa

Energy reservesb, c

Area (million km2)

9.9

Oil (billion barrels)

49

Population (million)

316.5

Gas (trillion cubic metres)

9.6

GDP (2010 USD billion PPP)

15 902

Coal (billion tonnes)

237

GDP (2010 USD PPP per capita)

50 224

Uranium (kilotonnes of U)

472

Sources: a. Census (2010); b. EGEDA (2015); c. BP (2015); d. NEA (2014).
E N E RG Y S U P P LY A N D D E M A N D
PRIMARY ENERGY SUPPLYThe total primary energy supply in the US in 2013 was 2 189 million tonnes of oil equivalent (Mtoe). In
terms of fuel type, 36% of supply came from crude oil and petroleum products, 28% from natural gas, 20%from coal and the rest from other sources such as nuclear energy, hydropower and geothermal energy. Only
14% of the economy’s primary energy requirements in 2013 were from net imports. The share of energy
imports declined from 32% in 2006 (EGEDA, 2015).
The economy’s total primary energy supply in 2013 increased by 2.3% compared to the 2012 level of
2 141 Mtoe. The increase resulted mainly from the 3% increase in gas supply, 2% increase in coal supply aswell as the increase in the supply of oil by 1%. Likewise, a substantial reduction in the net imports of theeconomy, namely an 18% reduction from the previous year, was recorded in 2013 (EGEDA, 2015). The
economy has showed constant reduction in import dependency since 2006, recording an average annual
decline of 11% over the last seven years, which was brought about by the increase in crude oil production
by North Dakota and Onshore Texas, mainly from shale and other tight (having very low permeability)
formations (EIA, 2013). In 2013, the US remained the third-largest crude oil, natural gas liquids andcondensates producer in the world, with production averaging 10 million barrels per day (bbl/d), a 13%
increase from the previous year (BP, 2015).
The US’ primary natural gas supply totalled 610 Mtoe in 2013. While the economy’s natural gas supply
has grown modestly from 1990 to 2013, with an annual growth rate of 1.4%, the primary natural gas supply(including net imports in 2013) grew by 2.5% from the 2012 level (EGEDA, 2015). In recent years, rapid
production of cheap 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 for coal by power
producers have helped lower emissions from power generation.

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Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Indigenous production

1 881 624 Industry sector

Net imports and others308 315 Transport sector

Power generation (GWh)
258 975 Total power generation

4 286 903

608 895

Thermal2 907 720

2 189 230 Other sectors

507 075

Hydro

270 856

Coal

432 406 Non-energy

119 093

Nuclear822 004

Oil

780 582 Total final energy consumption

1 494 038

Others286 323Gas

609 933

Coal

20 209Others366 308

Oil

762 203Gas

332 975

Electricity and others

378 651

Total primary energy supply

Source: EGEDA (2015).

The US held about 5.1% of the world’s natural gas reserves in 2013 (BP, 2015). As of 2014, theeconomy’s natural gas pipeline transmission network was more than 485 000 kilometres (km) long (PHMSA,
2016). In 2013, approved major pipeline projects amounted to 466 km and 0.2 billion cubic metres (bcm)
per day. The corresponding numbers for 2014 and 2015 were 679 and 765 km and 0.3 and 0.4 bcm per day(FERC, 2015a). Underground gas storage capacity in the US has grown only slightly since the mid-1970s,
and the total end-of-year stock in 2015 stood at about 77% of the working gas-designed capacity of the 390
active storage fields (EIA, 2016a, 2016b).
From 2006, the introduction of horizontal drilling in combination with hydraulic fracturing enabled
the economic extraction of unconventional gas, largely from shale formations. In particular, shale gas
production in the US has increased rapidly, from about 8% of gross withdrawals in 2007 to 44% in 2014
(EIA, 2015a, 2015b). The size of proved unconventional gas reserves, including shale gas and coalbed
methane, is estimated to be 6.1 tcm or over 50% of total reserves as of year-end 2014 (EIA, 2015c), andthus, further increases in shale gas production are anticipated. Interest in liquefied natural gas (LNG) exports
has grown thanks to abundant supplies and its relatively low price compared with other LNG supplies. By
2019, 104 million tonnes per year of exporting capacity would be added, if all the export terminals approvedby the Federal Energy Regulatory Commission are completed (FERC, 2016). .
The primary energy supply of coal in the United States totalled 432 Mtoe in 2013. In 2013, primarycoal supply increased by 1.7% over the previous year’s level of 425 Mtoe (EGEDA, 2015). The US’ coalreserves are concentrated east of the Mississippi River in Appalachia and in several key western states (EIA,
2015d).
In 2013, the United States was the fourth-largest coal exporter in the world, behind Indonesia,
Australia and Russia (EIA, 2015e). In 2013, coal exports amounted to 118 million short tons, a 6.4%
reduction from 2012. Coal imports have steadily declined from a peak of 36.3 million short tons in 2007 to
8.9 million short tons in 2013 (EIA, 2015f). More than 55% of exported coal is metallurgical, with the rest
being steam coal. Europe is the largest importer of coal from the US, accounting for almost 45% of net
exports (EIA, 2015g).
In 2013, the US produced 4.3 million gigawatt-hours of electricity, 68% of which came from fossil fuelplants, 19% from nuclear power and 13% from renewable energy and other sources (EGEDA, 2015).
The US generates more nuclear power than any other economy. Currently, five new nuclear reactors
are being constructed (EIA, 2015h). The Three Mile Island accident in 1979 raised concerns about nuclear
power plant safety. Ad hoc regulatory responses to those concerns drove up the cost of new plants. Thus,
both factors deterred further expansion. In 2007, work resumed on the partially built Watts Bar 2 reactor,
construction on which had been suspended in 1985. The commercial operation of this reactor is expected
to begin in 2016 (TVA, 2015). In 2014, the average utilisation rate of the US’ 99 operable commercial nuclear
units (down from a peak of 112 units in 1990) rose to 91.7%, and it has continued to rise since then (EIA,
2015f). Many nuclear plants have applied to the Nuclear Regulatory Commission (NRC) for 20-year
extensions of their operating licences, which would enable them to operate until the plant completes
60 years. In early 2016, the NRC had approved licence extensions for 83 nuclear reactor units and had
applications for another 11 extensions under review, while another 5 units had informed the Agency of theirintention to seek extensions between 2016 and 2022 (NRC, 2016).
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Recently, nuclear energy has suffered a major setback with the first closures of operating plants in 15
years. Four nuclear power plants were closed earlier than expected. Two of the reactors, one each in
Vermont and Wisconsin, cited stiff economic competition as the reason for their closing, and the other two
plants, one each in California and Florida, closed owing to structural damage and safety concerns. However,in late 2014, the Department of Energy (DOE) issued the Advanced Nuclear Energy Projects loan guarantee
solicitation, which provides USD 12.5 billion to support innovative nuclear energy projects as a part of the
Administration’s All-of-the-Above Energy Strategy.
Total renewable energy production in the US in 2013 was approximately 235 Mtoe, or 11% of the total
primary energy supply, according to the Energy Information Administration (EIA). Production from nonhydro (or new and renewable) sources increased 16.0% from the previous year, recording an annual growthrate of 14.2% since 2005 (EIA, 2015h, 2015f).
By consumption of renewable energy type in 2013, biomass, as a whole, represented 49.9% of the total;hydroelectric power, 27%; geothermal energy, 2.3%; wind, 17% and solar photovoltaic, 3.3%. There has
been a particularly rapid expansion of wind power; between 2000 and 2013, wind power recorded an averageannual growth rate of 29.2% (EIA, 2015f). Government incentives, including the subsidies and renewableenergy mandates discussed below, in addition to cost reductions relative to fossil-fuelled alternatives, spurred
the growth of renewable energy production.
FINAL ENERGY CONSUMPTION

In 2013, total final energy consumption in the US was 1 494 Mtoe, an increase of 4.1% from the previous
year. The transport and other sectors accounted for 40.8% and 33.9%, respectively, of the total demand,with the remaining share consumed by the industrial sector (17.3%) and non-energy sector (8%). In termsof fuel, petroleum accounted for more than 51% of the final consumption, while electricity and natural gas
accounted for 25.3% and 22.3%, respectively. Coal contributed a modest 1.4% (EGEDA, 2015).
ENERGY INTENSITY ANALYSISThe energy intensity of the US for 2013 has improved considerably across all sectors. Primary intensity in2013 worsened by 0.1% from the previous year’s value of 137.6 tonnes of oil equivalent per million USD(toe/million USD). However, the final energy consumption worsened by 1.9% compared with the previous
year’s energy demand level. The decline in the final energy intensity was mainly due to the increases in theintensity of the ‘other’ and ‘non-energy’ sectors in 2013 (Table 3).
Table 3: Energy intensity analysis, 2013
EnergyEnergy intensity (toe/million USD)
2012

2013

Change (%)
2012 vs 2013

Total primary energy supply

137.6

137.7

0.1

Total final energy consumption

92

94

1.9

Industry

16.0

16.3

1.6

Transportation

38.5

38.3

–0.4

Others

31

32

2.7

Non-energy

6.7

7.5

12

Source: EGEDA (2015).
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 andconsumption of energy is shared by several agencies in the executive branch. Supervision of the use ofnatural resources falls under the Department of the Interior. Energy-related research, development anddeployment (RD&D) takes place under the auspices of the DOE. The Federal Energy Regulatory
Commission (FERC) oversees the interstate transmission of energy, and the Environmental Protection
Agency (EPA) regulates the environmental impacts of energy transformations throughout the economy.
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The Department of Transportation (DOT) also plays an important role as the regulator of vehicle fueleconomy. A new White House Office of Energy and Climate Change Policy was created in 2009 tocoordinate some of the activities of these agencies.
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 sets the rules for energy markets. Since the1970s, several major legislative packages have been introduced to define the US’ energy policy. The National
Energy Act of 1978 included legislation to promote energy conservation, shift towards alternative energy
sources, create a market for independent power producers and give FERC greater authority over natural gas
markets (DOE, 2013.). The Energy Policy Act of 1992 further opened electricity markets to competition,encouraged integrated resource planning by utilities, targeted improved energy management in federal
agencies, promoted alternative transportation fuels, and required RD&D of technologies to enhance theproduction and efficient utilisation of renewable, fossil and nuclear energy resources (US House, 1992).
In 2005, the new comprehensive Energy Policy Act of 2005 (EPAct) was introduced as the successor
to the Energy Policy Act of 1992. This was followed shortly after by the Energy Independence and Security
Act of 2007 (EISA). Together, these recent legislative packages substantially define the current US federal
energy policy. The American Recovery and Reinvestment Act of 2009 (ARRA) is also noteworthy for having
dramatically increased funding for many federal energy programs. Key elements of these recent acts aredescribed in the following thematic discussions.
ENERGY SECURITY

Given the high dependence of the US on imported oil, policies meant to improve energy security have often
focused on three areas:Improving efficiency in the transportation sector, where more than 70% of oil products are
consumed,Enhancing domestic production of liquid fuels, and

Advancing transportation technologies that are less dependent on liquid fuels, such as hybrid
electric vehicles (HEVs).

In order to improve energy security in the transportation sector, the EPA and the DOT’s National
Highway Transportation Safety Administration (NHTSA) jointly developed vehicle greenhouse gas (GHG)
emissions standards and fuel economy standards of 23.2 km per litre (54.5 miles per gallon) for passenger
cars, light-duty trucks and medium-duty passenger vehicles to be manufactured in 2025 (MY 2025)(EPA, 2012a). As part of the Climate Action Plan announced in June 2013 (see below), the EPA andNHTSA set fuel economy standards for the first time for medium- and heavy-duty vehicles and engines.
The first phase is expected to reduce GHG emissions by nearly 250 million metric tons and save
approximately 500 million barrels of oil over the life of vehicles sold during 2014 to 2018. (EPA, 2010) The
second phase under development for 2018-2027 seeks to reduce CO2 emissions by 1 billion metric tons
and save 1.8 billion barrels of oil (EPA, 2016a).
The 2005 EPAct promoted the domestic production of oil by removing some regulatory barriers andoffering incentives for production from deep-water resources, low-production wells and unconventionalsources. One regulatory change was to exclude the underground injection of hydraulic fracturing fluids fromthe Safe Drinking Water Act of 1974, which allowed the exploitation of tight sand and shale hydrocarbon
resources. While making changes to this Act, Congress also clearly stated that development of
unconventional oil resources should be encouraged in order to reduce US dependence on foreign oil imports(DOE, 2005).
Biofuels, which represent another avenue for improving the US’ energy security, have received strong
policy support. While the development of vehicles powered by alternative fuels and biofuel production isalready promoted under the 2005 EPAct, in 2007, EISA brought biofuels to the forefront of the US’ energy
security policy. EISA mandated a fivefold increase from previous biofuel use targets by 2022, requiring fuelproducers to use a minimum of 136 billion litres (36 billion gallons) of biofuel, up from 42 billion litres(11 billion gallons) in 2009. This included the increase in advanced biofuels usage (that is, renewable fuels
other than ethanol derived from corn starch whose lifecycle GHG emissions are at least 50% less thanbaseline lifecycle GHG emissions) from 2.3 billion litres (0.6 billion gallons) in 2009 to 79 billion litres(21 billion gallons) by 2022. EISA also stipulates that the production of advanced biofuels should be
encouraged by a grant program. Most of the new biofuel is to be produced domestically, and the target
includes provisions to reduce the required volumes if the costs are judged to be too high or if supplies are
inadequate (CRS, 2007). Since this law was passed, U.S. consumption of oil has, in fact, declined in recent
years, causing the biofuel blend ratio in gasoline to rise unexpectedly. Many auto manufactures have stated235

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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). As a result, biofuel production is already tracking below the current targets. Nearly all of U.S.
gasoline contains 10 percent ethanol. EPA mandated that more than 18 billion gallons of biofuels overall
be blended into the fuel supply for 2016, still short of the 22.25 billion gallons envisioned by Congress in2007 (EPA, 2015).
The Recovery Act sought to advance the commercialisation of electric vehicles by investing in facilities
manufacturing batteries and other electric vehicle components. The government has invested more than
USD 2 billion in nearly 50 different electric vehicle and component manufacturing projects (DOE, 2010a).
Electric vehicles offer energy security benefits by shifting transportation energy demand from oil toelectricity. Total HEV sales during 2014 amounted to 452 172 (94% cars and 5.9% light trucks), down 8.7%
from 2013, but electric vehicle sales rose steadily from 2000 (DOE, 2015).
Coal-fired power plants provide less than half of the US’ electricity. Coal is a domestically abundantresource and thus provides energy security benefits. However, coal’s high carbon dioxide (CO 2) emissions
present a challenge for the US’ climate policy, as discussed below.
ENERGY MARKETSIn 2013, American consumers spent an estimated USD 1.4 trillion on energy purchases (EIA, 2015f). The
government plays many roles in this large market, such as resource owner, industry regulator and supporterof research and development (R&D).
UPSTREAM DEVELOPMENTThe Department of Interior’s (DOI) Bureau of Land Management (BLM) administers over 2.8 million km2
of mineral estate, of which about 180 000 km2 is currently leased for oil and gas development (BLM, 2010).
The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), another office of
the DOI, leases another 174 000 km2 of offshore energy and mineral resources (BOEMRE, 2010). The
BLM and BOEMRE also lease public 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 mineralrights, it is not the sole owner of such rights. States and individuals also own and lease surface lands andunderground mineral rights for energy extraction (BLM, 2009).
State and federal governments share regulation pertaining to upstream development. In some cases,
the division between state and federal responsibility is clear. For example, state oil and gas commissions
prevent the waste of resources and protect public safety in state territories (IOGCC, n.d.). In the federal
offshore territory, the offices of the DOI exercise similar responsibilities. However, such clear divisions may
not always exist. For example, the state offices of environmental protection monitor environmental impacts
and enforce state environmental laws. At the same time, the EPA acts as a backstop on environmental issues,ensuring that, at a minimum, upstream activities comply with federal laws such as the Clean Air Act of 1970
and the Clean Water Act of 1972. In cases where state and federal regulatory responsibilities overlap,
coordinating the activities of both agencies becomes an important task (EPA, 2012b).
ELECTRICITY AND GAS MARKETSThe federal government regulates the interstate transmission of electricity and gas, as well as wholesale salesof electricity, under FERC. FERC’s mandate is to ‘ensure supplies of energy at just, reasonable and not
unduly discriminatory or preferential rates’. In regulating wholesale electric power markets, 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
number of wholesale suppliers connected across a regional grid. Competitive wholesale electricity markets
function using distinct models in different regions. Regional transmission organisations and independent
system operators administer transmission networks and operate wholesale markets across large parts of the
US and Canada. In other regions, 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. There are thousands of retail electricity providers
in the US, and they operate under a variety of regulations. Seventy-two per cent of retail customers areserved by regulated, investor-owned utilities, 15% by public power systems and 13% by cooperatives (EIA,
2015i). State regulators ensure that these providers serve their customers at rates that are ‘fair, reasonable
and non-discriminatory’ (NARUC, 2009). In the 1990s, many states began to explore options for
restructuring retail electricity markets to create competition among electricity providers while continuing toregulate distribution networks as natural monopolies. In 2014, 21 states allowed some customers a choiceof electricity service provider, but efforts to deregulate retail electricity markets slowed in 2000 and 2001,
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when California’s newly deregulated retail market proved vulnerable to abuse, leading some customers’ bills
to quickly triple and forcing some distribution utilities into bankruptcy (DOJ, et al., 2007; EIA, 2015i).
Natural gas markets are similar to electricity markets, with competitive wholesale markets supplying
federally regulated transmission pipelines and delivering to state-regulated distribution networks. FERC used
to set natural gas prices, but wellhead prices were fully deregulated in 1993.
Presently, FERC’s pricing activities for natural gas are limited to determining pipeline rates for gas
transmission. The DOT’s Pipeline and Hazardous Materials Safety Administration regulates gas
transmission pipelines to ensure they are operated safely. The pricing and safety of natural gas distribution
networks are regulated by state agencies (FERC, 2015b; EIA, 2009).
RESEARCH 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. Though 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 21 laboratories and technology centres, aswell as the research conducted at universities across the US. Currently supported research ranges fromparticle physics to pilot projects for carbon capture and sequestration (CCS) (DOE, 2010b). Total
government spending for energy-related R&D remained relatively stable at around USD 3 billion a year (inUSD 2005 terms) from the 1990s until 2009, which saw the enactment of the Recovery Act (Dooley, 2008).
The Recovery Act changed this by investing billions more in R&D facilities, pilot projects and the new
Advanced Research Projects Agency for Energy (DOE, 2010c). However, the Recovery Act was a one-time
economic stimulus. After hitting an all-time high in FY09 at USD 3.79 billion, U.S. federal funding forenergy R&D slid downward for the four years to USD 2.29 billion in FY 13 before modestly increasing to
USD 2.41 billion in FY 14 and an estimated USD 2.43 billion in FY 2015, still above pre-Recovery Act levels(NSF, 2015). Some business leaders in the US have argued that to confront the energy challenges that the
US faces, the government should more than triple spending on clean energy R&D (AEIC, n.d.)
FISCAL REGIME AND INVESTMENTThe US’ fiscal policy is quite complex, particularly as it relates to the energy sector. This section provides alimited introduction to the taxation of energy commodities and to the multitude of fiscal incentives thatshape energy-related investments. Energy-producing businesses are taxed like other US corporations, at a
maximum statutory federal rate of 35%, while state rates range from 0% to 10%. However, tax rules resultin very different effective tax rates (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 13.2 billion inroyalty and other payments in Fiscal Year 2014 (ONRR). Downstream, sales of some important energy
commodities, such as gasoline and diesel, are taxed by state and federal governments. The federal tax on
gasoline and diesel is about USD 0.05 per litre (18.4 cents per gallon) and USD 0.06 per litre(24.4 cents per gallon), respectively. On average, state taxes on these fuels are similar to the federal taxes,
but there is considerable variation among the states (API, 2012). 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 toreduce their tax burden by some fraction of the amount invested. Similarly, PTCs reduce the taxpayer’s tax
burden, but 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 hydrogen refuelling stations.
Tax credits for investments in renewable energy or in energy-efficient home improvements are alsoavailable to individuals. At the state level, reduced sales and property tax rates are often granted to preferredenergy technologies (DSIRE, 2016). Some of these incentives are described in the following sections onenergy efficiency and renewable energy.

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ENERGY EFFICIENCY

Incentives to promote energy efficiency exist at the federal, state and local levels. Federal tax credits andloans support residential efficiency improvements. Taxpayers could claim a tax credit of up to 30% of thecost of a residential efficiency measure through the end of 2010. Homeowners can also obtain loans fromthe federal government to finance energy-efficiency measures in new or existing homes (DSIRE, 2016).
Much of the Recovery Act allocation for energy efficiency was distributed through state energy programs
that provide loans, grants and other assistance for energy-efficiency projects in homes, businesses and public
facilities (CRS, 2009). Locally, utilities are generally required to consider energy efficiency on an equal basiswith new generation in their planning, and many utilities administer demand-side management programs
that provide incentives and technical assistance to reduce demand for electricity and natural gas(DSIRE, 2016; US House, 1992).
RENEWABLE ENERGY

In 2014, the US’ cumulative wind energy capacity reached 64 850 megawatt (MW) or approximately 6.1%of total electricity generating capacity in the US. In 2014, the total wind energy installation amounted to 4
878 MW, and from 2007 to 2011, wind installations accounted for roughly 35% of all new electricity
generating capacity in the US (AWEA, 2012). Another significant change under the Recovery Act is thatnew renewable energy (NRE) facilities may select either the PTC, a 30% business energy ITC or, for alimited period, a cash grant equal to the value of the ITC. Manufacturers of renewable energy technologies
are also eligible for tax credits under the Recovery Act, to offset investments in new or expanded
manufacturing capacity. New solar facilities do not qualify for the PTC as a result of the 2005 EPAct, butthey are eligible for the ITC. A related individual tax credit of 30% is available for residential solar electric
system expenditures without cap, as are similar tax credits for small residential wind and geothermal systems.
Several federal loan and loan guarantee programs also exist to encourage the development of renewableenergy and other advanced energy facilities (DSIRE, 2016).
Many state and local governments have established financial measures that complement federal
incentives for NRE investment. In addition to subsidies, state legislation has also provided significant
indirect incentives for NRE 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. Thirty-eight states, the District of Columbia, Guam, Puerto Rico, the Virgin Islands, the N. Mariana
Islands and the Federated States of Micronesia had enacted the RPS legislation with varying degrees ofstringency by the end of 2015 (DSIRE, 2016).
Other measures have also been introduced to support NRE development, such as generation
disclosure rules, mandatory utility green power options, green power purchasing policies and the use of
public benefit funds (DSIRE, 2016).
NUCLEAR ENERGYThe US Government has enhanced its support for the nuclear industry through various means, including
legislative and financial ones. For example, the EPAct of 2005 included several provisions considered
important to revitalising the American 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,
introduced loans to cover costs incurred by legal or regulatory project delays, and established a public–
private project to design and construct a pilot Next Generation Nuclear Plant. The Act also continued
support for R&D in nuclear energy, and established a loan guarantee program intended to improve accessto financing for new nuclear plants and other energy projects that reduce air pollution emissions or introduce
new technologies (DOE, 2005). Thus, as authorised by its Title XVII, the Advanced Nuclear Energy
Projects Solicitation provides ‘loan guarantees to support construction of innovative nuclear energy andfront-end nuclear projects in the US that reduce, avoid or sequester greenhouse gas emissions’ (DOE,
2014a). In February 2014, the DOE issued USD 6.5 billion in loan guarantees to support the constructionof two Westinghouse AP1000 Generation III+ reactors at the Alvin W. Vogtle Electric Generating Site,
which currently has two older generation 4-loop pressurised water reactors in operation (DOE, 2014b).
Since the Energy Reorganisation Act of 1974, the DOE has held responsibility for the development
and promotion of nuclear energy, and the NRC has served as the regulatory 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. However, a suitable site remains to be found(NRC, 2011). The partially completed waste depository facility in Yucca Mountain, Nevada was recently
abandoned, and there is no viable long-term storage option for nuclear waste. The US Government handles
the financial burden of storing spent fuel and currently compensates utilities for storing their nuclear waste
on-site. However, the US Court of Appeals for the District of Columbia Circuit’s ruling in June 2012 banned
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the NRC from issuing new reactor licenses or renewals until it sufficiently assessed the risk of storing spentradioactive fuel at nuclear plant sites, and thus, the environmental consequences of not building a permanent
waste repository. This ruling prompted the NRC to issue an order in August 2012, suspending actions related
to issuing license renewals and new operating licenses (EIA, 2014a).
The US has the world’s largest nuclear energy sector, consisting of 99 operating reactors generating
797 000 million kilowatts of electricity in 2014 (EIA, 2015f), as well as five under-construction reactors. The
NRC has the authority to issue initial operating licenses to newly built reactors for a period of 40 years after
which they need license renewals to extend their lifetime for an additional 20 years of operation. Given the
majority of these reactors were built before the 1990s (mainly in the 1960s and 1970s), they have alreadyundergone lifetime extensions or need to go through this process in this decade or the next. After about
two years of deliberation, as requested by the mentioned court ruling, on 18 September 2014, the NRC
issued the revised and renamed Continued Storage of Spent Nuclear Fuel Rule, effective on 20 October
2014. Consequently, it may now legally resume issuing license renewals as well as new operating licenses. In
fact, the NRC resumed license issuance in October 2014 when it renewed the operating licenses for Limerick
Generating Station Units 1 and 2 located in north-west of Philadelphia. It extended their license expiration
dates by 20 years, to 2044 and 2049, respectively (EIA, 2014a). Over time, the NRC has granted 20-year
license renewals to 83 of the 100 operating American reactors, enabling them to operate for a total periodof 60 years. Currently, the NRC is reviewing license renewal applications for an additional 11 reactors while
expecting to receive 5 more applications in the next few years (NRC, 2016).
The American reactors could operate beyond 60 years (for up to 20 additional years), if their operatingcompanies apply for and receive a Subsequent License Renewal (SLR) from the NRC (EIA, 2014b). In
August 2014, backed by the May 2014 findings of the NRC’s Advisory Committee on Reactor Safeguards,
the NRC determined that the ‘existing license renewal regulations were sufficient to support the SLR
process’ (EIA, 2014b).
The March 2011 accident at Japan’s Fukushima Daiichi Nuclear Power Plant prompted thestrengthening of the American nuclear safety regulations as well as operating standards of its nuclear power
plants to avoid similar accidents in the US. The NRC and the US’ nuclear industry have been working
together towards this end. Thus, in the aftermath of the accident, they initiated ‘an immediate coordinatedresponse to the accident, as well as long-term actions’ meant to ensure the safety of the existing and planned
American nuclear reactors (EIA, 2014c). One of the subsequent major activities was the NRC’s
comprehensive review of its own processes and regulations, leading to the release of a report by its NearTerm Task Force, namely, Recommendations for Enhancing Reactor Safety in the 21st Century. It consisted of 12
recommendations covering short- and long-term actions, which were followed by the NRC’s issuing an
additional three orders with respect to the short-term recommendations in March 2012. The orders, whichappear below, required the implementation of the following measures while requiring the affected nuclear
power plants’ operators to submit their initial status reports in 60 days and their integrated plans by February
2013 (EIA, 2014c).
All boiling-water reactors (BWRs) with Mark I and II containment systems must have reliablehardened containment venting capability to reduce pressure and hydrogen build-up. This may
require improving or replacing existing containment ventilation systems,

Reactors must have enhanced instrumentation installed to monitor water levels in their spent fuelpools in the event of an emergency, and

Nuclear power plants must be capable of responding to multiple simultaneous events and ensuringthat reactors and spent fuel pools remain cooled. The order specifies a three-phase approach
involving use of installed on-site resources, use of portable on-site equipment and indefinite use ofoff-site resources.

For its part, the American nuclear industry has taken certain measures. They include developing its
FLEX strategy through the Nuclear Energy Institute (NEI). It is a ‘comprehensive, flexible and integrated
plan to mitigate the effects of severe natural phenomena and to take steps to achieve safety benefits quickly’.
Scheduled to become fully operational by 2014, the plan provides for two regional response centres to belocated near Memphis, Tennessee, and Phoenix, Arizona, from where ‘critical emergency equipment can bedelivered to nuclear power plants within 24 hours’ (EIA, 2014c).
CLIMATE CHANGE

As a part of the United Nations Framework Convention on Climate Change (UNFCCC), the US has
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26–28% below 2005 levels by 2025 in response to the UN Secretariat’s request in Lima. As of 2015, theClean Air Act, the Energy Policy Act, and the Energy Independence and Security Act are the key federal
government legislation that address the economy’s carbon emissions, both through higher emissions
standards and lower energy demand. State and local governments have developed their own goals and actionplans. Several state and regional initiatives incorporate a price for carbon emissions (e.g. the plans
implemented in California and north-eastern US).
GREENHOUSE GAS ENDANGERMENT FINDINGS

There are two ways that GHGs may be regulated at the federal level in the US. First, Congress may pass alegislation to control GHG emissions. Alternatively, the EPA may issue a ruling (an ‘endangerment finding’)that CO2 poses a danger to human health and should therefore be regulated under existing air quality
legislation. The former solution offers a more flexible approach to reducing emissions. However, a 2007
decision by the Supreme Court judged that GHGs are pollutants that should be covered under the Clean
Air Act. This decision required the EPA to determine whether to issue an endangerment finding. In
December 2009, the EPA issued an endangerment finding, which gave it the authority to issue rules to limit
GHG emissions. The EPA has used this authority to make vehicle emission standards more stringent andto define GHG permit requirements for large CO2 emitters (EPA, 2012a). The EPA engenderment finding
was challenged through the Court of Appeals but upheld in mid-2012. Further appeals are underconsideration in the US Supreme Court. The outcome of this ruling and subsequent plans to limit GHG
emissions will have major implications for future energy development in the US.
Principally, the EPA proposes to limit CO2 emissions in the power sector. The proposed standard
restricts CO2 emissions to a maximum of 454 kg (1 000 lb) for every megawatt-hour of electricity produced.
These proposed restrictions apply to new generating units and currently exclude existing units in operationor under construction. However, the EPA attempted to set CO2 emission limits for existing generating units.
Accounting for each state’s energy mix, the so-called Clean Power Plan (CPP) was announced in September
2015. The final rule was issued a few months later, and the Supreme Court stayed the implementation
pending further judicial review. The emission regulation was aimed at limiting climate change by enforcing
the use of modern and more efficient fossil fuel generation technologies (EPA, 2012c, 2016b). The carbon
restriction would essentially require new coal plants to operate using the latest high-efficiency technology,
employ biomass co-firing fuels or utilise carbon sequestration.
In addition to the GHG emissions limits, the EPA enforced emission standards on mercury and toxic
pollutants in 2012 to be fully enforced by 2015. After a decision by the U.S. Supreme Court that EPA must
consider cost in the finding supporting the standards. EPA undertook studies and in April 2016 issued afinal finding that it is appropriate and necessary to set standards for emissions of air toxics from coal- andoil-fired power plants (EPA, 2016c). This will have a major impact on reducing toxic emissions from coal,primarily in the electricity sector (EPA, 2012a). The new standards will require expensive technologicalretrofits to existing facilities and will affect almost half the coal generating capacity. Most of the affectedcoal facilities are over 40 years old, and the new standards are likely to result in extensive capacity retirements,
which may exceed 50 gigawatts.
STATE- AND CITY-LEVEL CLIMATE CHANGE INITIATIVESIn the absence of an economy-wide roadmap to reduce GHG emissions, a number of regional, state andcity level initiatives were undertaken since 2010.
In California, the Global Warming Solutions Act (AB 32) was signed into law in September 2007. Thislaw builds upon the 2000 California Climate Action Registry and the 2005 Executive Order S-3-05, which
noted that the state was particularly vulnerable to the impact of global warming, citing impacts to ‘watersupply, public health, agriculture, the coastline, and forestry’. The Act sets a mandatory state-wide GHG
emissions cap equal to 1990 levels by 2020, with penalties for non-compliance (ARB, 2014). In December
2008, the California Air Resources Board approved the implementation of a climate action plan, which
includes regulations, market mechanisms, voluntary actions and other measures, with the option of adopting
a cap-and-trade program in the period 2012–20 (ARB, 2008).
Nine states in the north-eastern US are members of the Regional Greenhouse Gas Initiative (RGGI).
This initiative has a narrower scope than the California Plan, as it focuses on reducing CO 2 emissions fromthe power sector by 45% of 2005 levels by 2020. The first permit auction for the cap-and-trade system wasconducted in September 2008, and the first three-year compliance period began in January 2009
(RGGI, 2009). Six New England states are also party to the New England Governors/Eastern Canadian
Premiers Climate Change Action Plan, whose 11 members have resolved to reduce the region’s GHG
emissions to 10% below 1990 levels by 2020 (NEG & ECP, 2008).
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The Midwestern Greenhouse Gas Reduction Accord, signed in November 2007, with members
including six US states and one Canadian province, aims to establish GHG reduction targets and possible
regulatory or market mechanisms that might be used to achieve them (MGA, 2007).
A host of other regional initiatives focusing on climate change or clean energy have formed between
the US, Mexican states and Canadian provinces. Examples include the Western Governors’ Association
Clean and Diversified Energy Initiative, the Southwest Climate Change Initiative, the West Coast
Governors’ Global Warming Initiative and the Western Climate Initiative (comprising six states and two
Canadian provinces aiming to reduce emissions to 15% below 2005 levels by 2020) (WCI, 2007). These
regional initiatives represent attempts to actively collaborate on goal setting and the development of actionplans. Except for the RGGI in the north-east, all the initiatives are still in the design phase. In 2015, Canada,
Mexico and the United States announced the establishment of a North American Energy Ministers’ Working
Group on Climate Change and Energy. It is facilitating expanded cooperation to deploy innovative
renewable energy technologies, modernize the grid, and increase energy efficiency to combat climate change
and reach greenhouse gas targets while growing low-carbon economies in North America (DOE, 2015b).
Municipal governments have undertaken other GHG initiatives, notably the US Mayors’ Climate
Protection Agreement, launched in Seattle in 2005. By December 2009, there were 1 016 signatories to thevoluntary agreement, under which US mayors strive to meet or beat the Kyoto Protocol targets in their own
communities, urge state and federal governments to meet the US’ Kyoto Protocol GHG emissions targets,and commit to taking actions within their own communities that will help to comply with or exceed Kyoto
Protocol targets (USCM, 2009).
VEHICLE EMISSION STANDARDSIn 2007, EISA mandated a 40% increase in combined car and light truck fleet fuel economy (CAFE)
standards by 2020, to reach 14.9 km per litre (35 miles per gallon), and required further study into
commercial vehicle fuel economy (CRS, 2007). In 2009, the administration proposed a plan to speed theintroduction of the new CAFE standards. In July 2011, a new US CAFE standard was agreed to by 13 major
automakers 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 automakers
together account for over 90% of all vehicles sold in the US (NHTSA, 2011). In addition, the EPA andNHTSA are completing phase one (2014-2018) increases for heavy duty vehicles, which are expected toreduce the fuel consumption of heavy-duty vehicles by 10–20% between 2014 and 2018 (EPA, 2011). EPA
and NHTSA released proposed standards for Phase 2 (2018-2027) in April 2016. Based on projected fuelsavings, vehicle owners are expected to recover the additional upfront costs of the more efficient vehicles
in one to five years (NHTSA, 2011).
The new standards, however, have several loopholes, which may inhibit their effectiveness. The chief
concern is the use of a size-weighted average fuel economy, where larger vehicles have lower fuel efficiency
targets. This policy was included to eliminate penalties, which favour the sales of small vehicles over large
vehicles. However, sales of larger vehicles in the market share may increase and reduce real fuel efficiency
improvements. A published study suggests that average vehicle sizes, particularly for light trucks, may
increase between 2% and 32% under the new standards. This would result in a net reduction in the average
fuel economy of between 1 and 4 miles per gallon (between 0.4 and 1.7 km per litre) (Whitefoot & Skerlos,
2011). Other uncertainties that may reduce the standards’ effectiveness include low fees for non-compliance,overstated fuel economy ratings and low targets for heavy trucks. These negative effects are expected to belimited and real efficiency improvements are likely to accelerate under these rules, but perhaps at a lower
than anticipated rate.
PROGRAMS UNDER THE AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009

As of late 2015, over USD 31 billion was spent on energy-related projects under ARRA (DOE, 2016). Major
investment programs include the Weatherisation Assistance Program, which invests in energy efficiency
improvements in low-income family homes. Other notable projects include the development of electricvehicles and smart grid technology as well as greater support for renewable energy. ARRA provides tax
credits for the purchase of alternatively fuelled vehicles. ARRA also provides USD 800 million for researchand development on clean coal projects, including carbon capture and sequestration (EIA, 2014d).

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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
CLIMATE ACTION PLAN

On 25 June 2013, President Obama announced the Climate Action Plan for tackling climate change. The
President’s Climate Action Plan consists of a wide variety of executive actions and the following three key
pillars (The White House, 2013):


Cut Carbon Pollution in America
In 2012, even as the economy continued to grow, the US’ carbon emissions fell to their lowest
level in two decades. In order to build on this progress, the Obama Administration is introducing
tough new rules to cut carbon pollution.

Prepare the US for the Impacts of Climate Change
Besides taking new steps to reduce carbon pollution, the Plan also addresses preparations forfacing the impacts of the changing climate, which are already being felt across the economy.
Moving forward, the Obama Administration will help state and local governments to strengthen
roads, bridges and shorelines, to better protect people’s homes, businesses and way of life fromsevere weather.



Lead International Efforts to Combat Global Climate Change and Prepare for its Impacts
It is understood that no economy is immune from the impacts of climate change and no
economy can meet this challenge alone. Hence, it is imperative for the US to couple action athome with international leadership. The US must help forge a truly global solution to this global
challenge by galvanising international action to significantly reduce emissions (particularly among
the major emitting countries), prepare for climate impacts and drive progress throughinternational negotiations.
QUADRENNIAL ENERGY REVIEWOn 9 January 2014, President Obama issued a Presidential Memorandum directing his Administration to
conduct a Quadrennial Energy Review (QER). The effort aims to establish a comprehensive and integrated
energy strategy to ensure clean, affordable and secure energy and services that are essential in improving the
US’ economic productivity, protecting the environment and ensuring the economy’s security (DOE, 2014b).
The first instalment of the QER examined ways to modernise the US’ energy infrastructure to promoteeconomic competitiveness, energy security and environmental responsibility. Its primary focus was energy
transmission, storage and distribution, gas and oil pipelines, wires, waterways, railroads and other facilities.
The QER identified vulnerabilities in the US’ energy system and provided major policy recommendations
and investments to replace, expand and modernise infrastructure, where appropriate. The second instalment
is conducting a comprehensive review of the nation’s electricity system, from generation to end use. It is
including a more comprehensive look at electricity transmission, storage, and distribution infrastructure, andconsidering the roles and activities of all relevant actors, industries, and institutions integral to continuing to
supply reliable, affordable electricity at a time of dramatic change in technology development (DOE, 2016).
THE 2015 UNITED NATIONS CLIMATE CHANGE CONFERENCE

The 2015 United Nations Climate Change Conference (COP21) took place in Paris in November–
December 2015. In December 2015, the US signed the COP21 Agreement on Climate Change, which aims
to ‘keep a global temperature rise this century well below 2 degrees Celsius and to drive efforts to limit thetemperature increase even further to 1.5 degrees Celsius above pre-industrial levels’. However, theAgreement remains to be ratified. In addition, at COP21, the US along with 19 others, including the APEC
Member Economies of Australia, Canada, Chile, China, Indonesia, Japan, Mexico and Korea, announced
they would double investment in clean energy R&D over five years as part of a long-term response to sharedclimate challenges (MI, 2015).

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REFERENCES

AEIC (American Energy Innovation Council) (n.d.), A Business Plan for America’s Energy Future,
www.americanenergyinnovation.org/.
API (American Petroleum Institute) (2012), Motor Fuel Taxes, www.api.org/oil-and-natural-gasoverview/industry-economics/fuel-taxes.aspx/.
ARB (California Air Resources Board) (2008), Climate Change Scoping Plan,
www.arb.ca.gov/cc/scopingplan/scopingplan.htm/.
–– (2014), Assembly Bill 32 Overview, www.arb.ca.gov/cc/ab32/ab32.htm/.
AWEA (American Wind Energy Association) (2012), U.S. Wind Industry Statistics,
www.awea.org/learnabout/industry_stats/index.cfm/.
BLM (Bureau of Land Management) (2009), Federal Oil and Gas Leasing and Development in Montana,
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–– (2014a), website ‘Department of Energy Issues Draft Loan Guarantee Solicitation for Advanced Nuclear Projects’
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–– (2015a), website ‘Light Duty Electric Drive Vehicles Monthly Sales Updates’ page, www.anl.gov/energysystems/project/light-duty-electric-drive-vehicles-monthly–– (2015b), North American Energy Ministers Establish a Working Group on Climate Change and Energy,
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U N I T E D S T AT E S–– (2016), website, ‘Recovery Act,’ page, www.energy.gov/recovery-act
DOJ, et al. (US Department of Justice, Federal Energy Regulatory Commission, Federal Trade
Commission, Department of Energy, Department of Agriculture) (2007), Report to Congress on
Competition in Wholesale and Retail Markets for Electric Energy,
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DSIRE (Database of State Incentives for Renewables and Efficiency) (2016), website ‘Database of State
Incentives for Renewables and Efficiency’ page, www.dsireusa.org/.
EGEDA (Expert Group on Energy Data Analysis, APEC Energy Working Group) (2015), APEC Energy
Database, www.ieej.or.jp/egeda/database/database-top.html.
EIA (Energy Information Administration) (2009), Major Legislative and Regulatory Actions (1935–2008),
www.eia.doe.gov/oil_gas/natural_gas/analysis_publications/ngmajorleg/ngmajorleg.html.
–– (2013), website ‘Today in Energy – USA’ page, www.eia.gov/todayinenergy/detail.cfm?id=10171/.
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Nuclear Power Plants’ page. www.eia.gov/todayinenergy/detail.cfm?id=18591.
–– (2014b), website ‘Today in Energy: Almost all U.S. Nuclear Plants Require Life Extension Past 60
Years to Operate Beyond 2050’ page, www.eia.gov/todayinenergy/detail.cfm?id=19091/.
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–– (2014d), Assumptions to the Annual Energy Outlook 2014,www.eia.gov/forecasts/aeo/pdf/0554(2014).pdf.
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–– (2015c), website, ‘U.S. Crude Oil and Natural Gas Proved Reserves’ page,www.eia.gov/naturalgas/crudeoilreserves.
–– (2015d), website, ‘U.S. Coal Reserves’ page, www.eia.gov/coal/reserves.
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page, www.eia.gov/electricity/data/eia861/index.html.
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EPA (US Environmental Protection Agency) (2010), EPA and NHTSA Propose First-Ever Program to Reduce
Greenhouse Gas Emissions and Improve Fuel Efficiency of Medium- and Heavy-Duty Vehicles: Regulatory
Announcement, www.nhtsa.gov/staticfiles/rulemaking/pdf/cafe/CAFE_2014-18_Trucks_FactSheetv1.pdf–– (2011), FACTSHEET: Paving the Way Toward Cleaner, More Efficient Trucks,
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http://epa.gov/carbonpollutionstandard/index.html.
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U N I T E D S T AT E S–– (2015), Renewable Fuel Standard Program: Standards for 2014, 2015, and 2016 and Biomass-Based
Diesel Volume for 2017, https://www.epa.gov/sites/production/files/2015-11/documents/rfs2014-2015-2016-annual-rule-frm.pdf–– (2016a), Overview Fact Sheet: Cutting Carbon Pollution, Improving Fuel Efficiency, Saving Money,
and Supporting Innovation for Trucks,
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Pollutantsfrom
CoalandOil-FiredElectric
Utility
SteamGenerating
Unitshttps://www3.epa.gov/mats/pdfs/20160414_mats_ff_fr.pdf
FERC (Federal Energy Regulatory Commission) (2008), website ‘Wholesale Competition in Regions with
Organised Electric Markets’ page, www.ferc.gov/industries/electric/indus-act/rto/maj-ord.asp.
–– (2015a), website ‘Approved Major Pipeline Projects (2009-Present)’ page,www.ferc.gov/industries/gas/indus-act/pipelines/approved-projects.asp.
–– (2015b), ‘What FERC Does,’ page, www.ferc.gov/about/ferc-does.asp–– (2016), website, ‘North American Import/Export Terminals—Approved’ page, April 18, 2016,www.ferc.gov/industries/gas/indus-act/lng/lng-existing.pdf.
IOGCC (Interstate Oil and Gas Compact Commission) (n.d.), website ‘2004 Model Oil and Gas
Conservation Act’ page, www.iogcc.state.ok.us/model-statutes/.
J. J. Dooley (2008), U.S. Federal Investments in Energy R&D: 1961–2008, Pacific Northwest National
Laboratory, 2008, www.pnl.gov/main/publications/external/technical_reports/PNNL-17952.pdf.
K. Whitefoot and J. Skerlos (2011), Design Incentives to Increase Vehicle Size Created from the US Footprint-based
Fuel Economy Standards, http://autocaat.org/WebForms/ResourceDetail.aspx?id=1529.
MGA (Midwestern Governors Association) (2007), Midwestern Greenhouse Gas Accord,www.midwesternaccord.org/midwesterngreenhousegasreductionaccord.pdf.
MI (Mission Innovation (2015), http://mission-innovation.net/
NARUC (National Association of Regulatory Utility Commissioners) (2009), website ‘About NARUC’page, www.naruc.org/about.cfm.
NEA (Nuclear Energy Agency) (2014), Uranium 2014: Resources, Production and Demand, https://www.oecdnea.org/ndd/pubs/2014/7209-uranium-2014.pdf.
NEG & ECP (2008), website ‘32nd Conference of New England Governors and Eastern Canadian
Premiers, Bar Harbor, Maine’ page, www.negc.org/index3.htm/.
NHTSA (National Highway Traffic Safety Administration) (2011), website ‘President Obama Announces
Historic 54.5 mpg Fuel Efficiency Standard’ page,www.nhtsa.gov/About+NHTSA/Press+Releases/2011/President+Obama+Announces+Historic+
54.5+mpg+Fuel+Efficiency+Standard/.
NRC (US Nuclear Regulatory Commission) (2011), website ‘Our Governing Legislation’ page,www.nrc.gov/about-nrc/governing-laws.html/.
–– (2016), website ‘Status of License Renewal Applications and Industry Activities’ page,www.nrc.gov/reactors/operating/licensing/renewal/applications.html/.
NSF (National Science Foundation) (2015), Federal R&D Funding, by Budget Function: Fiscal Years
2014–16, http://www.nsf.gov/statistics/2016/nsf16303/pdf/tab23.pdf.
ONRR (Office of Natural Resources Revenue) (2016), website, ‘Statistical Information’ page,
http://statistics.onrr.gov/.
PHMSA (Pipeline and Hazardous Materials Safety Administration) (2016) webpage, ‘Annual Report
Mileage for Natural Gas Transmission & Gathering Systems’ page,www.phmsa.dot.gov/pipeline/library/data-stats/annual-report-mileage-for-natural-gas-transmissionand-gathering-systems.
RGGI (Regional Greenhouse Gas Initiative) (2009), The Regional Greenhouse Gas Initiative (RGGI) Is …,
www.rggi.org/docs/RGGI_Executive%20Summary_4.22.09.pdf.
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U N I T E D S T AT E S

The White House (2007), (2013), The President’s Climate Action Plan,
www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
TVA (Tennessee Valley Authority) (2015), website ‘Watts Bar Unit 2 Issued Operating License’ page,www.tva.com/Newsroom/Watts-Bar-2-Project.
USCM (US Conference of Mayors) (2009), website ‘US Conference of Mayors Climate Protection
Agreement’ page, http://usmayors.org/climateprotection/agreement.htm.
US House (1992), H.R.776-Energy Policy Act of 1992, https://www.congress.gov/bill/102ndcongress/house-bill/776
WCI (Western Climate Initiative) (2007), Western Climate Initiative Statement of Regional Goal,
www.westernclimateinitiative.org/component/remository/func-startdown/91/.
USEFUL LINKS

American Recovery and Reinvestment Act of 2009—www.recovery.gov
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

VIET NAM
I N T ROD U C T I ON

Viet Nam, in the centre of South-East Asia, is bordered by China to the north, Laos and Cambodia to thewest, and the East Sea and Pacific Ocean to the east and south. Viet Nam has a land area of 330 967 square
kilometres (km2) with diverse geography and an exclusive economic zone stretching 200 nautical miles fromits 3 260-km coastline (excluding islands). As it is in a tropical monsoon zone and profoundly impacted by
the East Sea, Viet Nam has warm weather, abundant solar radiation, high humidity and generous seasonalrainfall.
Viet Nam is a dynamic, emerging economy with a population of 89.8 million (32% live in cities and
68% in rural areas) (GSO, 2015) and a gross domestic product (GDP) of USD 450 billion (2010 USD atpurchasing power parity [PPP]) in 2013 (World Bank, 2015a). Over the past 30 years, with its transformationfrom a centrally planned economy in 1986 to its current open, socialist-oriented market economy and active
international integration (especially, after the removal of US economic embargos in 1994), Viet Nam’s GDP
grew continuously, at an annual rate of over 7% between 1990 and 2008, and 5.8% during the global financial
crisis and recession period of 2008–15. Its economic structure has gradually changed through contributions
from the industry and service sectors, expanding from representing 62% of the economy in the early 1990s
to 80% in 2013. Major exports have diversified with more manufactured products, such as electronics,
machinery and vehicles (28% of total exports in 2014) and textiles, garments and footwear (21%), in contrast
to traditional fishery products, coffee and rice (nearly 10%) and crude oil (nearly 5%) (Viet Nam Customs,
2015). Population growth slowed to about 1% per year during 2009–14, below the Association of Southeast
Asian Nations (ASEAN) average, contributing further to improvements in Viet Nam’s per capita income.
The economy reached the World Bank’s lower-middle income classification in 2010 and is today among themost successful economies in realising the Millennium Development Goals (UNDP, 2015)
As of 2015, Viet Nam’s business environment ranking has risen above the East Asia and Pacificaverage according to the World Bank’s assessment (World Bank, 2015b). Comprehensive legislative andinstitutional reforms have accelerated since 2010 when the government engaged in a series of multilateralhigh-profile negotiations for free trade cooperation that extended beyond 2015, including the ASEAN
Economic Community (AEC), the Viet Nam–Customs Union of Russia, Belarus and Kazakhstan free trade
agreement (FTA), the EU-Viet Nam FTA, the Trans-Pacific Partnership (TPP) and the Regional
Comprehensive Economic Partnership (RCEP). These reforms focus particularly on stabilising the macroeconomy and implementing a free, competitive business environment based on market mechanisms,
transparent, fair and effective governance and sustainable environmental development. The government haspromoted ‘Green growth’ since 2012 for Viet Nam’s new phase of industrialisation and modernisation.
Table 1: Key data and economic profile, 2013
Key data a, b
Area (km2)

Energy proven reserves c, d
330 967

Oil (billion barrels)

4.4

Population (million)

89.8

Gas (billion cubic metres)

600

GDP (2010 USD billion PPP)450

Coal (million tonnes)

150

GDP (2010 USD PPP per capita)

5 021

Uranium (kilotonnes U)

1

Sources: a. GSO (2015); b. EGEDA (2015); c. BP (2015); d. WEC (2010).

Viet Nam is endowed with diverse energy resources, such as oil, gas and coal, as well as renewables.
Fossil energy potential is estimated to be moderate, although thorough 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 2013,
Viet Nam’s proven fossil energy reserves were 4.4 billion barrels of oil, 600 billion cubic metres (bcm) ofgas and 150 million tonnes (Mt) of coal (BP, 2015). Surveys and assessment for renewable energy’s potential
are still at preliminary stages, except for large hydropower. The economic and technical potential of largehydro is estimated at 95–100 terawatt-hours (TWh)/year or 25 gigawatts (GW). Technical potential of smallhydropower (less than 30 megawatts [MW]) is about 7 GW (MOIT, 2015c). Other renewable sources under
the government’s consideration for deployment over the next 15 years include wind, solar, biomass andmunicipal solid wastes (MSW). Potential capacity for wind power developments is 6 GW, solar 12 GW
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VIET NAM(PMVN, 2016), biomass 2 GW and municipal solid wastes (MSW) 320 MW (MOIT, 2015c). The energy
sector is important in attracting significant foreign investment and boosting industry growth, export earnings
and science and technology development.
E N E RG Y D E M A N D A N D S U P P LY
PRIMARY ENERGY SUPPLY

Viet Nam’s total primary energy supply (TPES) in 2013 was 45 900 kilotonnes of oil equivalent (ktoe), which
is a slight increase of 2.8% from the 2012 level and 78% higher compared to the 2005 level (EGEDA,
2015)14. By energy source, 38% of the supply came from coal, 34% from oil, 19% from natural gas and 10%
from other sources.
COAL

Viet Nam’s coal production and exports had average annual growth rates of 21% and 39%, respectively,
during 2000–07, and then slowed down to –0.6% and –11.9% per year, respectively, during 2008–13,
reflecting changes in government policy prioritising coal conservation for long term domestic uses rather
than boosting exports for generating foreign currencies. In 2013, Viet Nam produced about 22 985 ktoe ofanthracite and semi-anthracite coals, which is 3.2% less than what it produced in 2012. With increasing
domestic demand for coal, coal exports have steadily declined to 7 169 ktoe in 2013, about 31% of theeconomy’s production and roughly 40% of its export peak in 2007.
Viet Nam had about 49 billion tons as of 2010 in estimated potential coal resources (PMVN, 2012b).
The sub-bituminous-rich coal basin of the Red River Delta (in the provinces of Thai Binh, Hung Yen andNam Dinh) accounts for 81%. The anthracite-rich coal basin in the north-east (in the provinces of Quang
Ninh, Bac Giang and Hai Duong) accounts for 18%. Additionally, the share of the other mines in theprovinces of Hai Phong, Thai Nguyen, Lang Son, Nghe An and Quang Nam account for about 7%. Peatcoal in the Mekong delta accounts for about 1%. Until now, Viet Nam’s domestic coal has been produced
and supplied mainly by opencast and underground mines in the Quang Ninh province. Vinacomin (VietNam National Coal and Mineral Industries Holding Corporation Ltd) is the dominant coal producer in Viet
Nam with output accounting for about 95% of Viet Nam’s total coal production. Exploration activities in
the Red River Delta coal basin are still preliminary, and given its characteristics of complex geologicalconditions and a sensitive environmental and economic area, the exploitation of coal resources in this basin
is predicted to take place only after 2020.
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 incentral and southern parts of Viet Nam (PMVN, 2016).
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 grew
1.8% from 17 518 ktoe in 2012 to 17 834 ktoe in 2013 (15% down from a peak of 20 940 ktoe in 2004),
49% of which was exported. As of the end of 2013, there were 23 oil-producing fields in Viet Nam (PVN,
2014). 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 and then it will
decline since major fields in the Cuu Long basin matured.
Viet Nam is a net crude oil exporter but a net importer of petroleum products. There were 9 178 ktoe
of imported petroleum products in 2013 and they continue to account for the majority (59%) of Viet Nam’s
total primary oil supply. Petroleum product imports have shown a downward trend since 2009 as the firstrefinery in Viet Nam, the 140 000 billion barrels per day Dung Quat refinery, began operation during that
period. According to the government’s existing master plan for refinery development through 2025, five
new refinery construction projects (the Dung Quat expansion, Nghi Son, Vung Ro, Long Son and Nhon
Hoi) will be added. This expansion expects to increase Viet Nam’s refining capacity to 25 Mt by 2020 and
45–58 Mt by 2025.

14EGEDA excludes non-commercial energy sources such as traditional biomass, wood waste, etc.

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VIET NAM

NATURAL GAS

Viet Nam is self-sufficient in terms of natural gas supply. There are three offshore gas pipeline systems built
to deliver gas from Viet Nam’s oil and gas fields in the petroleum basins of Cuu Long, Nam Con Son and
Malay-Tho Chu to shores in the south-east and south-west regions of Viet Nam. They are:


Rang Dong-Bach Ho with 1.5 bcm per year capacity and in operation since 1995;

Nam Con Son with 7 bcm per year capacity and operating since 2003; and

PM3-Ca Mau with 2 bcm per year capacity and operating since 2007.

In 2013, 13 oil and gas fields produced an annual natural gas supply of 9.8 bcm, a 4.2% increase overthe 2012 level (PVN, 2014). Growth in the electricity, fertiliser and petrochemical industries have driven
demand for natural gas. Under the government’s orientation, PVN and PVGas are preparing for thedevelopment 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 and central markets beyond 2020
(PMVN, 2016, PVN, 2014). Viet Nam also has plans 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 2015 (PMVN, 2014; MOIT, 2015a).
POWER GENERATION

In 2013, with a total installed power capacity of nearly 31.7 GW (VNEEP, 2015a), Viet Nam produced
127 329 gigawatt-hours (GWh) (or 10 950 ktoe), increasing 8.3% from its 2012 level, and equal to almost
five times its output in 2000. Of this total electricity output, about 41% came from hydropower plants and
59% from thermal power plants (EGEDA, 2015). During 2008–13, according to Viet Nam’s energy
statistics, the installed hydropower capacity doubled from 6 GW to 15 GW, reflecting average annual growthof 17%, higher than for the overall thermal power plants, which was 13% per annum. As a result,hydropower’s share of Viet Nam’s total installed capacity increased significantly from 38% in 2008 to 48%
in 2013. Among thermal power sources, gas-fired power plant contribution remained the largest in terms of
capacity in absolute value (stable at 7.7 GW since 2009); however, coal-fired power plants recorded thefastest growth in development, averaging 24% per year from 2008–13. With an installed capacity of 7 GW,
coal power’s share increased considerably to 23% in 2013 from 4% in 2008. Growing deployment ofhydropower and coal power led to relative reductions in the roles of gas and oil power plants in Viet Nam’s
electricity system. Gas power plants experienced a sharp decline in share, from a record level of 41% in 2008
down to 25% in 2013. The share of oil power plants decreased slightly, from 6% to 4% in the same period.
In order to optimise the electricity supply and cost-effectiveness in all regions in the economy, since2004, Viet Nam has also relied on power sources from biomass and electricity imports from neighbouring
economies and countries such as China and Laos. However, these sources were still very marginal in its
economy’s power system during 2008–13.
Table 2: Energy supply and consumption, 2013
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

53 810 Industry sector

16 208 Total power generation 127 329

Net imports and others–6 535 Transport sector

10 527

Thermal

75 131

Total primary energy supply

45 900 Other sectors

8 294

Hydro

51 955Coal

17 239 Non-energy

1 946

Nuclear–Oil

15 470 Total final energy consumption

36 975

Others

243

Gas

8 522

Coal

10 559

Other

4 668

Oil

14 969Gas

1 460

Electricity and others

9 988

Note: Industrial energy consumption includes petroleum products and natural gas used as feedstock
Source: EGEDA (2015)

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VIET NAM

FINAL ENERGY CONSUMPTION

In 2013, Viet Nam’s total commercial final energy consumption (TFEC) was 36 975 ktoe, up 5% from 2012.
By fuel source, oil contributed the largest share (41%), followed by coal (29%), electricity and others (27%)
and gas (3.9%). Between 2008 and 2013, consumption of coal and oil continued to be constrained; thisrepresented, on average, 5% and 1.6% per year, respectively; by contrast, gas and electricity grew rapidly,with average annual growth of 22% and 11%, respectively.
Industry15 is an important sector in GDP growth and has represented the largest segment of TFEC atnearly 44%. This sector consumed mainly coal at 49%, electricity at 29%, petroleum products at 13% andnatural gas at 8%. The transport sector was the second largest energy-consuming sector, accounting for 29%
of TFEC and remained the main consumer of petroleum products at 70% of the economy’s totalrequirement. The other sector’s (residential, agricultural and commercial) consumption represented 22% of
TFEC. In this sector, electricity accounted for 57%, oil 24% and coal 19%. Demand for electricity grew
rapidly in the residential sector, reflecting improvements in household income and creating an increase inelectric appliance use and power supply quality.
ENERGY INTENSITY ANALYSIS

In 2013, Viet Nam’s energy intensity (primary energy consumption/GDP) was 102 tonnes of oil equivalent
per USD million GDP (toe/million USD), which is a decrease of 2.5% from 104 toe/million USD in 2012,
yet still 11% higher than 2005 levels. There were however only slight improvements in energy efficiency
from end-use sectors. The transport sector recorded the fastest decline in energy intensity, at–6.7% in 2013 from its level of 25 toe/million USD in 2012. The industry sector (including fuels used as
feedstock) increased its energy intensity 0.3% compared to the previous year and remained the sector withthe highest level of energy intensity. Other sectors had the lowest energy intensity at 18.4 toe/million USD
in 2013, which is an increase of 2.1% from 2012 levels.
Table 3: Energy intensity analysis, 2013
EnergyEnergy intensity (toe/million USD)
2012

2013

Change (%)
2013 vs 2012

Total primary energy supply

104

102

–2.5

Total final energy consumption

82.4

82.1

–0.4

Industry

35.9

36.0

0.3

Transportation

25

23

–6.7

Other sectors

18.0

18.4

2.1

Non-energy

3.5

4.3

25

Note: Industry includes petroleum products and natural gas used as feedstock
Source: EGEDA (2015)
P OL I C Y OV E RV I E W
ENERGY POLICY FRAMEWORKIn 2007, Viet Nam issued the National Energy Development Strategy to 2020, with a vision to 2050 (PMVN,
2007a), which addresses the Vietnamese government’s energy development key objectives, major policies
and measures to be realised up to 2020 in energy industries. Meanwhile, detailed development strategy andmaster plans by energy subsectors include the following:

Viet Nam Oil and Gas Development Strategy to 2015, with a perspective to 2025 (PMVN, 2006b);

15 In the EGEDA statistics, Viet Nam’s industrial energy demand includes petroleum products and natural gas used as

feedstock as well.

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VIET NAM



Viet Nam Gas Development Master Plan to 2015, with a perspective to 2025, also known in brief
as the GMP2011 (PMVN, 2011b);

Viet Nam Power Development Master Plan for the period 2010–20, with a perspective to 2030,
also known as PDP7 (PMVN, 2011c and PMVN, 2016 for the revised version);

Viet Nam Coal Development Master Plan to 2020, with a perspective to 2030 (PMVN, 2012b).

Viet Nam Renewable Energy Development Strategy to 2030, with a vision to 2050 (PMVN, 2015b)

Below is the summary of some of the main targets for energy development in Viet Nam over the next
10–15 years:
Ensuring a sufficient and high quality supply of energy to meet the demands of socio-economic
development, in which primary energy is expected to reach 100–110 million tonnes of oil equivalent(Mtoe) in 2020 and 310–320 Mtoe in 2050;

Ensuring the phased development of refineries to meet domestic demand for petroleum products
and increasing the capacity of refineries to about 25–30 Mt of crude oil in 2020;

Ensuring strategic oil stockpiling adequate for 60 days in 2020 and 90 days in 2025;



Achieving a share of renewable energy (including large hydropower) in the total primary energy
supply of 31% in 2020, 32% in 2030 and 44% in 2050; Renewable power development (including
large hydro and pumped-storage hydropower) of about 24 GW in 2020 and 49 GW in 2030.

Completing the rural electrification program for rural, mountainous and remote island areas
increasing the proportion of rural households with access to electricity to 100% in 2020;



Changing the electricity, coal and oil and gas sectors to operate in competitive markets with state
regulation; establishing a functioning competitive retail market by 2015 for coal and petroleum
products and for electricity after 2022; and

Carefully reviewing safety issues and actively preparing conditions for the first unit of a nuclear
power plant operation in 2028; then gradually expanding the role of nuclear power in the economy’senergy structure.

The Ministry of Industry and Trade (MOIT) oversees all energy industries. Formed in 2007 out of themerger of the Ministry of Industry and the Ministry of Trade, it operates currently in accordance withfunctions, tasks and powers as defined in the government’s Decree 36/2012/ND-CP dated 18 April 2012
and the government’s Decree 95/2012/ND-CP dated 12 November 2012. It drafts laws, policies,
development strategies, master plans, economy-wide target programs, technical-economic programs andimportant projects for all energy sectors. It submits these to the government and the Prime Minister for
issue or approval. The Ministry administers the implementation of these laws, policies and plans. It takes on
responsibility for issuing technical regulations and standards, eco-technical norms and guidelines on theimplementation of approved law and policies. The Ministry carries out the state management of public
services, state-owned enterprises in energy sectors and is in charge of communicating the government’s
policies as well as reporting on sector development results.
Within the MOIT, the General Directorate of Energy (GDE) and the Energy Regulatory Authority ofVietnam (ERAV) are two key advisory and executive units assisting the MOIT’s Minister with the
management of the energy sectors.
On 25 October 2011, the Prime Minister of Viet Nam’s (PMVN) Decision 50/2011/QD-TTg
established the GDE and it commenced operation (PMVN, 2011a). It focuses on formulating law, policy
and planning, and generally managing all energy sectors.
The PMVN’s Decision 258/QD-TTg, signed on 19 October 2005 (in accordance with Provision 66
of Electricity Law 2004), and the PMVN’s Decision 153/2008/QD-TTg, dated 28 November 2008,
established the ERAV. The ERAV specialises in regulatory activities in the electricity sector in order toensure a safe and high-quality supply of electricity for the economy. It also fosters the economical andefficient consumption of electricity and upholds the equity and transparency in the sector in compliancewith the law. ERAV’s concrete tasks include:251

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

Implementing regulatory activities relating to the electricity market and tariffs (including approving
the Termed Bilateral Purchase Power Agreements (PPA));

Reviewing provincial/city power development master plans and power development projects;Monitoring and making the mid- and long-term forecasts for the electricity supply-demand balance;Granting permits for power businesses; andOverseeing the inspections of electricity activities.

PVN, the Viet Nam National Petroleum Group (Petrolimex), Viet Nam Electricity (EVN) and
Vinacomin are the leading state-owned enterprises (SOEs) in the energy industries in Viet Nam. They
actively contribute to formulating and implementing development strategies, master plans and annual plansissued by the government in energy sectors. In particular, PVN still participates in some regulatory activities
relating to oil and gas exploration and exploitation and gas distribution; EVN owns and is directly involvedin many key operations (such as dispatch direction, monitoring and measurement for the national powersystem) of the Viet Nam electricity competitive market. The government has gradually restructured theSOEs to operate on a commercial basis and with transparency in terms of their business performance andfinancial information (GOV, 2013)
ENERGY SECURITY

The government of Viet Nam’s energy security priorities include:Synchronously developing various energy sources;

Exploiting and using domestic energy sources in an economical and efficient manner;



Reducing dependence on imported petroleum products,



Exporting a rational quantity of coal (in the immediate future, reducing annual coal exports);

Connecting to regional energy systems;

Expanding stockpiles of petroleum products; andCombining energy security with the economy’s general defence and security assurance.

To lessen dependency on oil imports and to ensure energy security, the government has implemented
the following detailed policies and measures:Strengthen domestic energy supply capacity through legislative reforms (specifically in terms ofprice, fiscal systems, equity among enterprises forms and information transparency) and the
expansion of infrastructure;

Apply preferential policies for financing and expanding international cooperation to strengthen the
exploration and development of indigenous resources, thereby increasing reserves and the
exploitability of oil, gas, coal and new and renewable energy;Improve energy efficiency, reduce energy losses and implement extensive measures for theconservation of energy;

Encourage Viet Nam’s oil companies to invest in exploration and the development of oil and gas
resources overseas;Intensify regional and international energy cooperation and diversify energy import sources; andDevelop clean energy, especially new and renewable energy.
ENERGY MARKETSELECTRICITY MARKET

Viet Nam’s electricity market is characterized by the active participation of several SOEs and various private
players who are involved in power generation and distribution on a BOT (Build-Operate-Transfer) and IPP(Independent Power Producer) basis. As the leading SOE in the Viet Nam’s power sector, EVN is entrusted
to manage the development and operation of the national power transmission system. In 2014, the electricity
generation structure by ownership was as follows (EVN, 2015):
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

EVN’s power plants accounted for 60.2% of the total 34 GW installed capacity;

PVN’s power plants accounted for 13%;

Vinacomin’s power plants accounted for 4.4%; andVarious other local investors’ power plants accounted for 14%.

Foreign investors’ power plants accounted for 8.4%;

Since 2004, the government of Viet Nam has established a vision for a competitive power market aspart of a long-term development strategy for the electricity sector. The implementation of the competitivemarket is deemed a means to create a new dynamic in Viet Nam’s power sector. It aims to reinforce theeffectiveness of production and business activities within the electricity sector, facilitate a decrease inelectricity selling prices and enhance the transparency and efficiency of power generation and distribution
activities to ensure the robust development of the electricity sector over time.
The Electricity Law of December 2004 (effective 1 July 2005 and amended on 20 November 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 PMVN’s Decision 26/2006/QD-TTg dated 26 January 2006
(hereafter Road Map) and revised by PMVN’s Decision 63/2013/QD-TTg dated 8 November 2013.
According to the Road Map, Viet Nam’s competitive power market has three phases of 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 areenacted to complement the Road Map. These cover licensing and technical concerns, market rules, tariffs
and contract regulation.
On 1 July 2011, Viet Nam’s competitive generation power market (VCGM) launched its pilot
operation and commenced full operation on 1 July 2012. By the end of 2014 Q3, there were 55 power plants
with a total capacity of 12.8 GW directly participating in selling electricity in the spot market. Those 55
power plants constitute 40% of total capacity of the power system. There were about 52 power plants witha total capacity of over 18 GW or 60% of the total capacity of the power system yet to participate.
The first actual pilot year of the competitive wholesale power market started January 2016, according
to MOIT’s conceptual and detailed design of the Viet Nam Wholesale Electricity Market (VWEM) issued
during 2014–15 (MOIT, 2014a and 2015b). This year the market will process the simulation of wholesaletransactions in paper only (or by notes), yet still with real payments. ERAV assessed the total number of
power plants and installed capacity that are directly involved in the VCGM in 2016; this could increase to
79 power plants and 21 GW, of which 63 power plants with an installed capacity of 14.9 GW have theirfirm plans in place (ERAV’s Decision No 79/QD-DTDL dated on 20 November 2015). This estimation
excluded power plants that were eligible not to participate in VWEM including:multi-purpose strategic hydropower plants;



small-hydro plants with capacity 30 MW or lower with inappropriate infrastructure;other renewable power plants of all-sizes;



BOT power plants having PPA or HOA concluded before January 2016;



IPPs built in industrial zones and not to supply their total production to the national power
network; and

gas-fired power plants using PM3-CAA gas source.

This category accounts for about 31–42 power plants, equivalent to an installed capacity of 16.3–20
GW in 2016.
The MOIT’s Circular 30/2014/TT-BCT, dated 2 October 2014, requires certain payment settlement
principles of power generating companies involved in the competitive market. Contract coverage not higher
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than 95% applies in the first year of the electricity market, which gradually decreases in the following years
to no lower than 60%. For example:
From 1 July 2012 to 31 Dec 2012, contract coverage applied to both hydro power plants andthermal power plants was 95%;

From 1 January 2013 to 31 March 2013, contract coverage applied to both hydro power plants andthermal power plants was 90%; andFrom 1 April 2013 to current day, the contract coverage applied with a reservoir more than twodays is 80% and for hydropower plants with a reservoir less than two days as well as thermal power
plants is 90%.

As part of the electricity sector reform, EVN has been creating corporate subsidiaries from its member
enterprises since the early 2000s. Thus far, the following generation and distribution companies have been
restructured:

In 2008, four power transmission companies were merged into one company, the National Power
Transmission Corporation, which is a separate entity under the management of EVN (or an
independent cost-accounting subsidiary of EVN);In 2010, five power corporations were established after merging 11 power companies who are
eligible customers in VWEM; and

In 2012, EVN established three generation companies (GENCOs) including GENCO 1, 2 and 3.

In addition, the Electricity Power Trading Company (EPTC), which is the ‘single buyer’ in VCGM
and the buyer of power plants not yet participating directly in VWEM, the National Load Dispatch Centre(NLDC), which manages the spot market’s transactions, and the Information and Communications
Technology Center (EVNICT, responsible for electric measurement and market monitoring) still operate asbranches of EVN. Strategic power plants, including large hydropower plants, namely Hoa Binh, Tri An,
Yaly and Son La and nuclear power plants (in the future) also remain under the management of EVN andoperate as EVN’s dependent-accounting units.
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 baseline of the average retail electricity tariff inViet Nam is calculated annually by the MOIT and is based on:the audited costs;

the generation, transmission and distribution sectors investors’ reasonable profits; andthe costs of regulating, managing and supporting services in the electricity system.

The baseline is the threshold for the electricity retail tariff adjustments. Adjustments occur followingchanges in fundamental costs such as fuel costs, exchange rates and generated capacity. Any changes that
occur within the tariff scope are approved by the Prime Minister.
For the period between 2013–15, following the PMVN’s Decision No 2165/QD-TTg dated 11
November 2013, the average retail tariffs were allowed to fluctuate in the range from VND 1 437 per
kilowatt-hours (kWh) (USD 6.8 cents) to VND 1 835/kWh (USD 8.7 cents). According to the PMVN
Decision No. 69/2013/QD-TTg dated 19 November 2013 (effective 1 January 2014), EVN is allowed toincrease retail tariffs only when:

the fundamental costs change from 7% to under 10%;

the Electricity Price Stabilisation Fund has been used; and

the MOIT, through consultation with the Ministry of Finance (MOF), provides an endorsement.

Any tariff increase outside of the approved tariff scope and in cases of cost fluctuation of 10% or more
require a decision by the Prime Minister. The government’s policy aims for tariff adjustments that aretransparent and publically announced. The minimum timeframe between two consecutive electricity tariffadjustments is six months. The government can deploy the Electricity Price Stabilisation Fund and other254

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measures stipulated in legislations when it is necessary to stabilise the electricity tariff in order to minimise
negative impacts on the stability of the macro-economy and the welfare of the population.
CRUDE OIL MARKET

Players in the upstream oil sector in Viet Nam include PVN, various international oil companies and otherforeign enterprises. According to the Petroleum Law 1993 and amendments in 2000 and 2008, thegovernment reserves the right to be a priority buyer of oil production from contractors and in such a case,foreign contractors have the right to sell their profit oil at international prices.
There is only one refinery in Dung Quat, Quang Ngai province, with a capacity of 6.5 Mt per year.
Operated by the Binh Son Refinery Company (BSR) starting in 2009, it is a 100%-owned PVN subsidiary.
BSR has bought crude oil mainly via the Petrovietnam Oil Corporation (PVOil), a subsidiary of PVN.
PETROLEUM ENGINE FUEL MARKET

Petroleum engine fuels (PEF) include gasoline, diesel, jet A1, fuel oil, kerosene, biofuels and other engine
fuels, excluding LPG and CNG (GOV, 2014).
The government, represented by the MOIT, the Ministry of Planning and Investment (MPI) and theMinistry of Finance (MOF), controls the PEF market. The MOIT regulates all enterprises participating in
the market, especially refineries, importer-wholesale enterprises and the development of petroleum trading
infrastructures (import terminal, strategic stockpiles, commercial stockpiles and oil products pipelines) inorder to ensure the supply of PEF for the economy. Annually, the MOIT selects qualified enterprises toimplement PEF imports, allocates the import quota 16 to these enterprises based on the MPI’s forecast of
total PEF demand for the economy and approves their importing and production plans. The MOIT
manages the development of refineries and oil-trading infrastructure according to the master plans approvedby the Prime Minister. The MOF manages all fiscal and economic issues including tax rates, retail prices andthe Petroleum Price Stabilisation Fund.
As of June 2013, there were 17 wholesale enterprises in the domestic PEF market, of which Petrolimex
was the leading SOE with a market share of 48%, PVOil had 17% (PVOil also distributes BSR’s output
products) and the remaining 35% was from 15 other companies. Fourteen of the 17 wholesale enterprises
were authorised by the MOIT to import products in 2013. The list of importers can change every year
depending on each enterprise’s business performance and whether or not it achieved the import quota of
the previous year. In general, three SOEs, namely, Petrolimex, PVOil and Saigon Petro, hold the largest
quotas, and together they make up nearly 80% of the total annual imports. Key enterprises, including
refineries and importer-wholesale enterprises, are responsible for ensuring the petroleum engine fuel supply
for the whole economy, both in terms of quantity and range of products. Foreign investors are yet toparticipate in the PEF trading in the domestic Viet Nam market.
In terms of the retail market, Viet Nam has more than 12 000 petrol stations as of 2013. SOEs financed
30% of these stations and private investors financed 70%. The government is planning to increase thenumber of fuelling stations to 18 000 by 2020.
In September 2014, the government issued a new decree on the PEF business, which came into effecton 1 November 2014 (GOV, 2014). It detailed the business operating conditions required for importerwholesale enterprises and other enterprises that participate in the PEF trade and distribution in Viet Nam’s
domestic market and their rights and duties. A notable requirement established for importer-wholesale
enterprises and refineries was that they must ensure that they had a 30-day minimum stockpile equivalentavailable according to their level of supply and product structure. Their average daily sales in the domestic
market during the previous year determines the stockpile level. This includes stockpiles for both theeconomy’s energy security and commercial needs.
Since 2009, the government has regulated retail PEF prices based on the approval of a baseline selling
price for importer-wholesale enterprises. The base price is composed of a number of price elements
including: CIF (cost, insurance, freight) price of importers; government taxes and levies (import tax, excise
tax, VAT, environment tax); business expenses norm; deductions for the Petroleum Price Stabilisation Fund;and profit norm.

16 The PEF import quota is the minimum annual amount of petroleum products that an authorised enterprise canimport.

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The MOF regulates the calculation of each price element in the base price. Importing and wholesale
enterprises can define their wholesale prices and adjust their retail prices based on the fluctuations of theiractual costs compared to their approved base price. In raising prices, importer-wholesale enterprises areallowed to make adjustments equivalent to changes in their costs up to 7%, after having informed (in cases
less than 3%) or received guidelines from the MOIT and MOF (in cases 3% to 7%). The Prime Minister
decides on the adjustments when the increase is more than 7%. The interval between two consecutive priceadjustments is set at a minimum of 15 days in the case of increasing prices and a maximum of 15 days in thecase of decreasing prices.
NATURAL GAS MARKETThe government reserves the right to be the first priority buyer of all natural gas 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, gas prices are not subject togovernment 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 gas prices and levels
are set considering the competitive position of gas against alternative fuels. This ensures a reasonable profit
margin for investors in related upstream and midstream 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 and operating gas infrastructure projects toensure a safe and reliable natural gas supply and support gas exploration and production in Viet Nam.
COAL MARKET

Vinacomin’s production and sales account for 95% of the total coal market in Viet Nam. Recently, theNorth-East Coal Corporation separated from Vinacomin to become an independent company and operate
under the oversight of the Ministry of Defence. In addition, PVN established PV Power Coal, which is incharge of 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 is about 16 Mt in 2020 and 20 Mt in 2030. As a percentage of the total coal demandfor power generation, PVN’s share will represent about 24% as of 2019–20 and drop to 10% by 2030.
Since July 2009, Vinacomin has set the price for local customers, except power generators, at themarket price. Recently, the government has been preparing a strategy to deregulate the price of coal used
for power generation. As a first step, in 2012, the government allowed the coal price for power production
to rise according to the latest electricity price adjustment. Any adjustments would be no less than the coalproduction cost in order to ensure funding for the renovation, expansion and improvement of the capacityof the existing mines and building of new mines to meet coal demand and contribute to improvements inenergy efficiency.
ENERGY EFFICIENCYIn April 2006, the Prime Minister approved the Viet Nam National Energy Efficiency Program (VNEEP)
for 2006–15 (PMVN, 2006c). The program’s overall objectives cover:community stimulation, motivation and advocacy;science and technology; andmandatory management measures for carrying out coordinated activities related to the economicaland efficient use of energy in society as a whole.

The aim of the program was to save 3% to 5% of the total energy consumption over the 2006–10
period and 5% to 8% in the 2011–15 period (PMVN, 2012c).
The program includes six components:

strengthen state management of energy efficiency and conservation by developing a management
system for energy saving;

strengthen education, disseminate information and enhance public awareness to promote energy
efficiency and conservation (EE&C) as well as environmental protection;

develop and popularise highly energy-efficient equipment by phasing out low-efficiency equipment;

promote EE&C in industry;256

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

promote EE&C in building; and

promote EE&C in transportation.

VIET NAM

The MOIT is the focal coordinator of EE&C and is authorised to administer the implementation of
the VNEEP. As part of this, the government established the Energy Efficiency and Conservation Officewithin the MOIT on 7 April 2006 (MOIT, 2006). The main work of the office is to develop organisations
and systems for improving EE&C at the government level, from the central government to local
government. According to the MOIT’s report at the 7th National Conference on Energy Savings held inTien Giang Province on 17 October 2014, a network of 14 energy conservation centres and more than 40
industrial promotion centres, counselling centres and technology transfer centres have been establishedacross the economy.
The MOIT established a National Steering Committee chaired by the MOIT to monitor the VNEEP.
The committee includes representatives from the Union of Vietnam Associations of Science andTechnology and the ministries of construction; transport; education and training; culture and information(renamed the Ministry of Culture, Sports and Tourism in August 2007); science and technology; planningand investment; justice; and finance.
In order to realise targets in energy efficiency programs, the government encourages major energyusing establishments to improve their energy planning, management and auditing. Major energy-using
establishments are those with the consumption of energy as follows:Industrial, agricultural production and transportation enterprises with a total yearly energy
consumption of at least 1 000 toe; and

Buildings used as headquarters, offices, accommodations, institutions of education, healthcare,recreation, fitness and sports, hotels, supermarkets, restaurants and stores with a total yearly energy
consumption of at least 500 toe.

The MOIT, in coordination with other ministries, related sectors and localities, organises and manages
the operation of these establishments. In addition, it coordinates with related ministries, the Departments
and People's Committees of Central Provinces and Cities, to set up a list of these energy-intensive consumers
and annually update and submit that list to the Prime Minister for approval. According to the list issued by
the Prime Minister in 2013, there were 1 720 major energy-using enterprises in the economy. Cities andprovinces with large numbers of such establishments are Ho Chi Minh City (241); Binh Duong (178); Hanoi(176); Dong Nai (106); QuangNinh (98); Ba Ria-Vung Tau (89) and An Giang (6). The four provinces
without any major energy-using establishments are BacKan, NinhThuan, DakNong and Bac Lieu.
Phase one of the 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 No 50/2010/QH12 dated 17
July 2010 on Energy Savings and Efficiency (effective 1 January 2011) and its regulations and guidelines bysector. By the end of 2014, the regulation and guidelines of concrete measures for enhancing energy savingsand efficiency covered transport (2011), agricultural (2013) and industrial sectors (2014). In 2013, theNational Technical Regulation on Energy Efficiency Buildings was revised in line with updated international
trends of minimum standards for energy-efficient building exteriors and interior equipment. These standards
applied as of November 2013 to all new or renovated offices, hotels, hospitals, schools, department storesand residences of 2 500 square metres (m2) or more (MOC, 2013). In addition, Minimum Energy
Performance Standards (MEPSs) were instituted from 1 January 2014 for basic household electric appliances(including tube and compact fluorescent lights, electrical and electronic ballasts for fluorescent lights, airconditioners, refrigerators, washing machines, rice cookers, fans and televisions), and as of 1 January 2015
for printers, photocopiers, computer monitors, storage water heaters, commercial refrigerators and freezers(PMVN, 2011e). The government has also issued clear regulations on vehicle life based on vehicle type, fuelquality standards and MEPSs for motorcycles and cars. Drafting guidelines on applications of economicaland efficient use of energy for public means of transportation (buses) in big cities is ongoing.
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 Program on Energy Efficiency–period 2011–15, held in 2015 Q4 by
the MOIT in cooperation with Vietnam Association of Science and Technology in Energy Saving andEfficiency (VNEEP, 2015b). MOIT reported the level of energy savings at 5.96% of Viet Nam’s total energy
consumption during 2011–15. MOIT’s report also showed progresses in application of MEPS and othermeasures for energy efficiency improvement. There were 29 sets of MEPS and testing methods applied for257

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energy labelled products issued in accordance with the energy labelling roadmap; 77 factories applied theplans for energy efficiency improvement to their operations, of which 15 businesses were qualified to obtainthe certificate of the Energy Management System ISO 50001. The energy audit was implemented for 1 140
businesses in 2015; the average energy-savings was 14.6%. Awareness in society about energy savings has
increased; more and more households and enterprises have proactively used energy-efficient equipment andapplied saving measures. Viet Nam’s annual electricity savings was between 1.4–2.5% of total power sales
or 1.3–2.8 TWh per year during 2011–14 (EVN, 2015).
RENEWABLE ENERGYIn November 2015, the government issued for the first time the national strategy of renewable energy forthe period through 2030, with a vision to 2050 (PMVN, 2015b). Renewable energy development in Viet
Nam continues to integrate with the implementation of broader objectives of general socio-economic
development, industrial and sectoral deployment. In particular, it contributes to modernisation and newrural development, fuel diversification and implementation of Viet Nam’s pledge to mitigate GHG
emissions increase.
The ambitious targets set include: commercial renewable energy to reach 37 Mtoe (31% of TPES) by2020 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; biofuels to increase to about 5% of total transport fuel demandin 2020 (about 800 ktoe) and 13% (3.7 Mtoe) in 2030. The government expects that accelerated renewableenergy growth will contribute to a mitigation of GHG emissions in energy activities of around 5% by 2020
and 25% by 2030, compared to the BAU (business as usual) plan, as well as a reduction of fossil fuel imports
for energy purposes of about 40 million tons of coal (compared to the case established in the PDP7 in 2011)
and 3.7 million tons of oil products by 2030. In March 2016, the Prime Minister approved the revised PDP7
to update and detail these new targets and policy measures for renewable power developments in Viet Nam
to 2030.
Renewable energy (RE) remains a field with government investment incentives. Support mechanisms
and policies for renewable energy development include:

Prioritising investment and use of renewable energy in the development of the energy industry witha focus on building Viet Nam’s renewable energy market;

Supporting all organisations and individuals with a variety of ownership structures to participate in
the development and use of renewable energy;Appling various fiscal incentives within import tax, corporate income tax and land taxes and fees,
as well as credit incentives as specified in legislation, applicable to special preferential projects andpreferential investment projects;

Approved electricity prices (avoided-cost tariffs, Feed-in Tariff) for on-grid renewable energy
consistent with the different locations and features of potential renewable energy projects toprovide appropriate returns to investors;Standardized Power Purchase and Sale Contracts (20 years) for each renewable power type and 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;
RPS obligation

2020

2030

2050

Electricity generation companies greaterthan 1,000 MW (excluding BOT projects)

RE not lower
than 3%

RE not lower
than 10%

RE not lessthan 20%

Electricity distribution companies

RE not lower
than 5%

RE not lower
than 10%

RE not lessthan 20%

Notes: RE = renewable power sources excluding large hydropower plants (>30 MW)

Project specific arrangements for off-grid electricity systems;

Net-metering for electricity consumers with simplified connection arrangements;Environmental fees for organisations utilising fossil fuels for energy production.
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The specific regulation system for renewable energy is as follows:
SMALL HYDRO POWER

The MOIT’s Circular No. 32/2014/TT-BCT dated 9 October 2014 on regulation on avoided-cost tariff andpower purchase agreement for small hydropower plants (MOIT, 2014b) replaces the previous MOIT’s
Decision No. 18/2008/QD-BCT dated 18 July 2008 on ‘Regulation on avoided-cost tariff schedule andstandard power purchase agreement’.
The MOIT approves and issues annually avoided-cost tariffs for small hydropower. Tariff levels are detailed
by regions and vary by season and daily dispatch periods.
WIND POWER

Enacted regulations include the PMVN’s Decision No. 37/2011/QD-TTg dated 29 June 2011 on‘Mechanism for supporting wind power development’ (PMVN, 2011d), the MOF’s circular No.
96/2012/TT-BTC dated 8 June 2012 on ‘Financial mechanisms for grid-connecting wind power projects’,and the MOIT’s circular No. 32/2012/TT-BCT dated 12 November 2012 on ‘Regulation on
implementation of wind power project development, power purchase and sale contract form for wind power
projects’.
Current level of the Feed-in Tariff (FiT) for wind power is equal to 7.8 US cents/kWh. The government
subsidises the power price for EVN by 0.01 USD/kWh through the Viet Nam Environment Protection
Fund. The FiT level for wind power is under review by the MOIT for revision.
BIOMASS POWER

Enacted regulations include the Prime Minister’s Decision No. 24/2014/QD-TTg, dated 24 March 2014 on‘Support mechanism for development of biomass power projects in Viet Nam’, the MOIT’s Circular No.
44/2015/TT-BCT dated 9 December 2015 on ‘Regulation on project development, avoided-cost tariff, andpower purchase and sale contract form for biomass power projects’.
FiT for a biomass cogeneration (or CHP—combined heat and power) project is set equal to 0.058
USD/kWh. Avoided-cost tariffs apply for other biomass power projects; MOIT annually approves andissues these tariffs. Calculations are based on the generation cost of thermal coal power plants that use
imported coal. The MOIT’s Decision No. 942 dated 11 March 2016 promulgates the avoided-cost tariffs(excluding VAT) in 2016 for biomass power projects at 7.3–7.5 US cents/kWh.
SOLID-WASTE POWER

The Prime Minister’s Decision No. 31/2014/QD-TTg, dated 5 May 2014, on ‘Support mechanism fordevelopment of solid waste power projects in Viet Nam’ indicates FiT levels applied for landfill gas and
MSW direct combustion power projects equal to 7.28 and 10.05 US cents/kWh respectively.
SOLAR POWER

MOIT is drafting specific regulations for solar power projects in Viet Nam. It plans to submit these to thePrime Minister for approval by June 2016. MOIT has proposed FiT levels ranging at 11.2–14 US cents/kWh
as a support mechanism for solar PV farm and solar PV rooftop projects (MOIT, 2016a).
BIOFUELS

Biofuels are encouraged in Viet Nam as an alternative to partially replace conventional fossil fuels,
contributing to assuring energy security and environmental protection. In 2007, the government of Viet
Nam announced a biofuel development scheme for the period up to 2015, with a vision to 2025, stipulatinga target for building and developing biofuel production and its use nationwide (PMVN, 2007b). By 2015,
the output of ethanol and vegetable oil is expected to reach 250 000 tons (enough for blending 5 million
tons of E5 and B5), satisfying 1% of the whole economy’s gasoline and oil demand. Moving to 2025, Viet
Nam aims to build an advanced biofuel industry, applying biofuel production technology in Vietnam thatwill eventually reach the world's most advanced level. The ethanol and vegetable oil output is targeted toincrease to 1.8 million tons, satisfying some 5% of the whole economy’s gasoline and oil demand.
The MOIT, in coordination with relevant ministries, branches, organisations and individuals, assumes
the prime responsibility for organising the efficient and timely implementation of the biofuels scheme. It
annually reports to the Prime Minister. Enterprises that want to invest in biofuels producing projects are
required to submit their plans for development to the MOIT. Biofuels traded and used in Viet Nam are
required to follow the technical regulation and standards for biofuels.
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In November 2012, the government announced the applicable ratio for mixing biofuels withconventional fuels for road-motorised vehicles using gasoline and diesel in Viet Nam and the road map forthe implementation (PMVN, 2012d). Since 15 January 2013, Viet Nam has produced, traded and distributed
biofuels for motorised road vehicles. The fuels include E5, E10, B5 and B10. As of 1 December 2014, thedistribution and use of E5 for all motorised road vehicles has become mandatory in seven cities andprovinces including Ha Noi, Ho Chi Minh City, Hai Phong, Da Nang, Can Tho, Quang Ngai and Ba RiaVung Tau. It will be mandatory for the whole economy as of 1 December 2015. E10 will be mandatory in
the abovementioned seven cities and provinces as of 1 December 2016 and will then expand to the whole
economy on 1 December 2017. From 2015, the government will focus more on the application of economic
measures and increasing incentives for players on the supply side in order to rapidly boost and sustainably
develop Viet Nam’s biofuel markets (PMVN, 2015a)
From 2007–15, the government classified investment in biofuel production as an area eligible for
special investment incentives. As a result, biofuel production enterprises became entitled to an income tax
exemption or reduction for biofuel products according to legislation on Enterprise Income Tax. They
became entitled to the highest land rent and land use incentives over the next 20 years. Raw materials,
components, machinery and equipment for scientific research and technological development for biofuel
production are exempt from import tax. Raw materials, components, machinery and equipment used forbiofuel production are eligible for the lowest import tax rate.
Since the 2007 deployment of the government’s Decision No. 177/QD-TTg dated 20 November 2007
(PMVN, 2007b), investments in biofuel research and production have increased. Biofuel research focuseson biofuel technologies and applications in electricity generation and transportation use. About 58 R&D
and pilot projects were implemented during 2007–15. The government has invested in domestic research
capacity to advance the biofuel sector in accordance with the framework of Program 177 as well as in othereconomy-wide and provincial funding programs available for the scientific and technological developmentin Vietnam. The total state budget spent to support Program 117 was about 11.78 million USD (MOIT,
2016b). Since 2009, investments in bioethanol production projects have increased among domestic
enterprises including Petrovietnam. In 2014, there were five bioethanol plants (E99.5 and above) built in
Quang Nam, Dong Nai, Quang Ngai (Dung Quat), Binh Phuoc and Phu Tho, with a total installed capacityof about 500 million litres per year, enough for mixing 10 billion litres of E5 (MOIT, 2016a).
NUCLEARIn January 2006, the Prime Minister approved the Strategy for Peaceful Applications of Atomic Energy to2020 with the overall objective to gradually build and develop the atomic technology industry to increasinglyand effectively contribute to socioeconomic development and strengthen the economy’s scientific andtechnological capacity (PMVN, 2006a). The subsequent Prime Minister's Decisions No. 114/2007/QD-TTg(issued in July 23, 2007) and No. 957/QD-TTg (issued in June 24, 2010) detailed the government’s actionplans for the implementation of this strategy. In regard to nuclear power investment, the government
stipulates to select proven/accredited safe and modern nuclear technologies. MOIT is responsible toformulate detail policy and road map for acquiring, mastering and developing nuclear power technologies.
The Viet Nam Power Development Master Plan for the period 2010–20, with a perspective to 2030
(PDP7) (for both approved versions in 2011 and its revision in 2016 by the Prime Minister) promotes thenuclear power development to ensure Viet Nam’s electricity supply security in future, when domestic
primary resources becomes exhausted. The government of Viet Nam has been actively cooperating withother governments and international organizations to accelerate the nuclear power construction anddevelopment programs. According to the PDP7 issued in 2011, the first introduction of 2 GW of nuclear
power was scheduled in 2020; the capacity would gradually increase to 10.7 GW in 2030, so that nuclear
power source could produce annually about 70.5 TWh, accounting for 10.1% of total power generation.
However, after the March 2011 Fukushima nuclear power plant accident in Japan, safety issues in thedevelopment and operation of nuclear power plants became a top priority in government’s review agenda.
With Decision No. 2241/QD-TTg dated 11 December 2014, the Prime Minister has entrusted relevant
ministries, government agencies and sectors with careful reviews for revisions of nuclear power policy andregulatory framework, implementation programs, including the timeframe and the development capacity
over the long term. Since 2015, the Ministry of Sciences and Technology (MOST) has leaded the review
process for amending The Law on Atomic Energy 2008 (Law No.18/2008/QH12) and completing technicaland environmental regulations on nuclear power infrastructure development to 2020. In March 2016, thePrime Minister approved the MOIT’s revised PDP7 (PMVN, 2016), underlining that nuclear power
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safety and efficiency as the primary objectives. The revised PDP7 has postponed the operation year of thefirst unit in 2028 and reduced total capacity to 4.6 GW in 2030; hence, the power generation from nuclear
will be 32.5 TWh in 2030, accounting for 5.7% of total power production of the national system. The
government entrusted EVN as the investor for the first two nuclear power plants built in Ninh Thuanprovince in central of Viet Nam. As a supporting policy, the government guarantees for loans from abroadto develop nuclear power.
CLIMATE CHANGE

In an early stage 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 impactsof climate change and rising sea levels, according to national and international analyses of climate change
scenarios to 2100.
In Viet Nam, the government exercises unified management over its natural resources andenvironmental protection throughout the economy. The institutional framework for environmental
governance consists of the administrative hierarchy, with economy-wide representation through the
National Assembly and provincial, district and community level representation through the People’s
Councils and Committees. More than 10 line ministries and central agencies deal with natural resources andother ministries deal with general planning responsibilities. The Ministry of Natural Resources andEnvironment (MONRE) plays a central coordinating role in environmental management.
Since the 1990s, the government of Viet Nam has been motivated by the serious impacts of climatechange on the economy’s sustainable development. Viet Nam is one of the economies most affected byclimate change. It signed the UNFCCC on 16 November 1994, signed the Kyoto Protocol to the UNFCCC
in 1997 and ratified it 20 August 2002. Viet Nam has fulfilled all requirements to be an Annex II economy
for developing clean development mechanisms (CDMs) under the protocol.
Government agencies are progressively revising and completing the institutional framework and thesystem of legal documents to prevent and mitigate natural disasters due to climate change. In April 2003,
the government established the CDM National Executive and Consultative Board, comprised of officials
from MONRE and other ministries. In June 2003, the government designated the National Office for
Climate Change and Ozone Protection (part of the International Cooperation Department of MONRE) as
Viet Nam’s CDM national authority.
Every five years the Vietnamese government issues its ‘National Target Program to Respond to
Climate Change’ (NTP-RCC) to assess the climate change impact on sectors and regions over specificperiods and to develop feasible action plans that can effectively respond to climate change in the short andlong term in order to ensure the sustainable development of Viet Nam. In December 2008, the Prime
Minister approved the National Target Program to Respond to Climate Change. It has a budget of about
VND 1 965 billion.
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 it is the foundation for allother ministerial, sectoral and local strategies, plans and programs.
Viet Nam has set a target to reduce 8–10% of its GHG emissions intensity from 2010 levels by 2020;
and after 2020, to reduce GHG emissions intensity 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 targetsof 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. The BAU starts from 2010 (the latest year of the national GHG inventory) and includes the energy,
agriculture, waste and LULUCF (Land Use, Land-Use Change and Forestry) 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

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Many international financial institutions and developed economies in the APEC region, including theWorld Bank and the Asian Development Bank, as well as the governments of Australia, Canada, Japan, theUS and others are helping Viet Nam build specific projects aimed at reducing the impact of climate change.
These include risk management for natural disasters and responses to climate change; land management forsustainable forestry under climate change conditions; the reduction of greenhouse gas emissions throughefforts to combat deforestation and forest degradation; and rural development in the Cuu Long River delta
to cope with climate change.
N OTA B L E E N E RG Y D E V E L O P M E N T S
EVN’S STRONG INVESTMENT IN RURAL AND REMOTE ISLANDS ELECTRICITY
DISTRIBUTION NETWORK EXPANSION

By the end of 2014, EVN had successfully developed a distribution network nationwide, specifically therural and remote islands network; currently, 100% of the rural districts are able to receive electricity supply
from the national grid system, next to their own local source; 99.6% of the communes and 98% of the rural
households are connected to electricity; the electricity coverage for the communes and households in northwestern mountainous provinces is 98% and 85%, respectively, for the central highland 100% and 96%,
respectively; and for the south-western region 100% and 98%, respectively. The national grid continues tocover the island districts by overhead lines or submarine cables including Phu Quoc, Kien Hai (KienGiang
province), Ly Son (Quang Ngai province) and five communes of Van Don Island district (QuangNinh
province). This helps to improve the living standards of the people and local economic development, andprotect national sovereignty.
The reliability indicators of power supply in Viet Nam continued to improve significantly in 2014. In
general, the System Average Interruption Duration Index (SAIDI) was recorded at 3 134 minutes, down
23% compared with 2013; the System Average Interruption Frequency Index (SAIFI) was 18.1 percustomer, down 25%; and the Momentary Average Interruption Frequency Index (MAIFI) was 2.63 percustomer, down by 26%.
Improvements in electricity access, a more reliable power network along with power loss reduction
and an increase in power usage efficiency also contribute actively to enhance the national competitiveness.
(EVN, 2015)
FINANCIAL SUPPORT FOR SMALL/MEDIUM ENTERPRISES (SME) TO INVEST IN
ENERGY EFFICIENCY

Since June 2015, the ‘Green Investment Facility’ (GIF), a 6.5 million USD financial support program under
the Low Carbon Transition in Energy Efficiency Project (LCEE), funded by the Danish government, hasbeen rolled out to guarantee loans and credit rewards for SMEs in Viet Nam to invest in energy efficiency
in three sectors: brick, ceramics and food processing.
Techcombank, BIDV and SCB are three Vietnamese lending banks who cooperate to implement the
GIF program.
SMEs in the three mentioned sectors, which plan to invest in projects for energy efficiency
improvements with a minimum value of VND 400 million/project, can apply to participate in the GIF
program. If involved in the GIF, the SMEs can receive financial assistance equivalent to 50% of their loans
through a guarantee from the ANZ bank, thereby reducing half of the collateral needed when they borrowat designated lending banks. The GIF program also offers a reward mechanism based on actual energy
efficiency improvements of the project. SMEs who achieve actual energy savings will receive a
corresponding reward, ranging from 10–30% of their total investment costs, an additional financial source
for them to use to repay the principal.
By the time of the GIF program launch in June 2015, approximately 90 SMEs had made contact with
the LCEE Project for financial support. Of these, 20 companies had been instructed to complete the dossierand eight companies were under consideration for an approved loan. The GIF program expects to support
100–130 energy savings projects by the end of 2016. All information, together with GIF program progress
as well as activities of the LCEE project, including applicable solutions for saving energy applied by SMEs,
are reported at the website www.lcee.vn.
The GIF program presents the private sector in Viet Nam with a good opportunity for practicalsupport in borrowing capital. In regards to Vietnamese banks participating in the GIF program, benefits
may include closer links with businesses and the opportunity to become acquainted with the economic
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benefits of energy efficiency. Furthermore, through these activities, the banks and businesses will contributeto raising public awareness about energy efficiency, energy saving and environmental protection.
OPERATION AT FULL CAPACITY OF THE 99.2 MW BAC LIEU WIND FARM –ASIA’S FIRST OFFSHORE WIND FARM

On 17 January 2016, the Bac Lieu wind farm, the Asia’s first offshore wind farm started operation at
the full capacity of 99.2 MW, with the potential to supply 320 GWh/year to the national power system(MOIT, 2016a), and recognised to offset 151 331 tons of CO 2 emissions a year. The completion of thisproject construction increased Viet Nam’s total wind power capacity to 135 MW.
The Bac Lieu wind farm has been developed on a 540-hectare site in a submerged coastal area of Vinh
Trach Dong Commune, Bac Lieu City of Bac Lieu province, in southern Viet Nam. It includes 62 windturbines of 1.6 MW each, supplied by General Electric (GE). Each GE 1.6 MW turbine has a rotor diameterof 82.5 m and a swept area of 5 346 m 2, made of special stainless steel, weighing more than 210 tons andsitting on an 80 m to 100 m high tubular steel tower. The turbines are expected to operate at a rated speedof 1 915 rpm. The turbines use a double-fed asynchronous generator with a partial power converter system
and are equipped with an electric-drive pitch control system with battery backup for efficient speed
regulation.
Construction commenced in September 2010, and the first phase (ten wind turbines with a total
capacity of 16 MW) was grid-connected in May 2013. Twenty-two new 110 kV-63 MVA transformer stations
and approximately 30 km of 110 kV transmission lines were built to ensure power transmission to thenational grid. Digital and bi-directional type electricity metre systems have been installed at the connection
point to measure the export and import of electricity from the wind farm. The contracts for the construction,transportation and installation of wind turbines for the project were awarded to several domestic companies
including Huy Hoang Transportation & Logistics Corporation (HTL) and Industry Construction
Corporation (Descon) (Power-technology.com, 2014).
Cong Ly Construction-Trade-Tourism has invested more than VND 5.2 trillion (approximately 244.4
million USD) in the project. The wind farm is expected to have an operational life of 22 years.
The Bac Lieu wind farm is also the first project to be developed under the US-Viet Nam private sector
agreement, which is part of the US-Asia Pacific comprehensive energy partnership aimed at addressing
energy access and energy poverty issues in the Asia-Pacific region. The Export-Import Bank of the UnitedStates (US Ex-Im Bank) and the Vietnam Development Bank (VDB) are jointly funding the wind farm.
VDB is responsible for the investment credit and foreign loan, while the US Ex-Im Bank is providing a 1.5
billion USD credit line to finance the project.
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VIET NAM–– (2014a) Ministerial Decision on the approval of the conceptual design of the Vietnam Wholesale Electricity Market ofViet Nam. Decision No. 6463/2014/QD-BCT, dated on 22 July 2014–– (2014b) Circular on Regulation on avoided cost based on electricity tariff and power purchase agreement for smallhydropower plants. Circular No. 32/2014/TT-BCT, dated 9 October 2014.
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Energy Utilization by 2030 in the APEC region. November 2015, Daegu, Korea.
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VIET NAM–– (2015b). Approving the development strategy of renewable energy of Vietnam by 2030 with a vision to 2050.
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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
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 Energy—nangluongvietnam.vn
Vietnam Economic Times—www.vneconomy.com.vn
Vietnam News Agency—http://vietnamnews.vn/

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