A PE C E N E RG YOV E RVI E W
2014

APEC E N E RG Y O VE R VI E W 2014

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
 2015 APEC Secretariat
APEC#214-RE-01.17

APEC E N E RG Y O VE R VI E W 2014

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

Shigeru KIMURA
Chair

Asia Pacific Energy Research Centre

Expert Group on Energy Data and Analysis

April 2015

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

ACKNOWLEDGEMENTS
The APEC Energy Overview 2014 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
Naomi Wynn
MAIN CONTRIBUTORS
Data Collection and Compilation: Energy Data and Modelling Center (EDMC), Institute of Energy
Economics, Japan.
Economy Chapters: Naomi Wynn (Australia, Papua New Guinea), Elvira Torres Gelindon and Muhamad
Izham Abd. Shukor (Brunei Darussalam), Parminder Raeewal and Maren Stachnik (Canada), Luis Camacho
Beas (Chile, Peru), Linmin Xia (China, Hong Kong, China), Chrisnawan Anditya (Indonesia), Takashi
Otsuki (Japan), Dmitry Sokolov (Korea, Russia), Michael Sinocruz and Muhamad Izham Abd. Shukor(Malaysia), Juan Roberto Lozano Maya (Mexico), Martin Brown Santirso (New Zealand, Papua New
Guinea), Michael Sinocruz (Philippines), Lin Yeong Chuan (Chinese Taipei), Hooman Peimani (Singapore),
Atit Tippichai (Thailand), Elvira Torres Gelindon and Alexey Kabalinskiy (USA) and Tran Thi Lien Phuong(Viet Nam)EDITORSIRIS International, LLC and Naomi Wynn
ADMINISTRATIVE SUPPORT
Masatsugu Kamakura, Yoshihiro Hatano, Kayo Sayama and Tomoyo Kawamuraiv

APEC E N E RG Y O VE R VI E W 2014

C ON T E N T S

CONTENTS
Foreword ........................................................................................................................................................................ iii
Acknowledgements ....................................................................................................................................................... iv
Content ............................................................................................................................................................................ v
Abbreviations and symbols ......................................................................................................................................... vi
Acronyms ...................................................................................................................................................................... vii
Australia ........................................................................................................................................................................... 1
Brunei Darussalam ....................................................................................................................................................... 14
Canada............................................................................................................................................................................ 22
Chile................................................................................................................................................................................ 37
China .............................................................................................................................................................................. 45
Hong Kong, China ...................................................................................................................................................... 59
Indonesia ....................................................................................................................................................................... 68
Japan ............................................................................................................................................................................... 83
Republic of Korea ........................................................................................................................................................ 93
Malaysia........................................................................................................................................................................ 102
Mexico.......................................................................................................................................................................... 116
New Zealand ............................................................................................................................................................... 128
Papua New Guinea .................................................................................................................................................... 138
Peru............................................................................................................................................................................... 144
The Philippines ........................................................................................................................................................... 154
The Russian Federation ............................................................................................................................................ 168
Singapore ..................................................................................................................................................................... 183
Chinese Taipei ............................................................................................................................................................ 199
Thailand ....................................................................................................................................................................... 210
United States ............................................................................................................................................................... 220
Viet Nam ..................................................................................................................................................................... 235v

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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)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

EDMC

Energy Data and Modelling Center, 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

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 Countriesvii

APEC E N E RG Y O VE R VI E W 2014

PES

primary energy supply

PPP

purchasing power parity

PSA

production sharing agreement

PSC

production sharing contract

PVphotovoltaicRE

renewable energy

TFEC

total final energy consumption

TPES

total primary energy supply

UNDP

United Nations Development Programme

UNFCCC

United Nations Framework Convention on Climate Change

US

United States

VAT

value added tax

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 comprises of six states and two territories. The population of just under than 23 million
lives mostly in major cities or regional centres along the eastern and south-eastern seaboards. Australia has
maintained robust economic growth for the last 23 years, averaging 3.4% over the period 1960–2014 (ABS,2014). In 2012, Australia’s GDP reached USD 911.8 billion (USD 2010 PPP), a 3.6% increase from 2011
(EDMC, 2014). It is the only developed economy in APEC to have recorded no annual recessions during
the last 23 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 is a significant contributor to the economy (ABS, 2014).
In 2012-13, Australia’s energy production increased by 9.4% compared to 19 318 petajoules or 461
404 ktoe (BREE, 2014a). Australia produces energy for both domestic consumption and export. Net energy
exports grew by 15.0% and accounted for 68.0% of domestic energy production in 2012-13 (BREE, 2014a).
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% in the ten years to 2012–13 (BREE，2014a).
In 2012–13, coal accounted for 59.2% of Australia’s primary energy production, in energy content
terms, followed by uranium (21.9%) and gas (12.6%) (BREE, 2014a). Crude oil and LPG represented afurther 4.6% of total energy production in energy content terms, and renewables 1.7% (BREE, 2014a).
Relative to 2012–13, Australian export earnings from energy and mineral commodities increased by 12.0%
in 2013-14 to AUD 195 billion (OCE, 2014).
Australia is the world’s eighth-largest energy producer, accounting for around 2.4% of world energy
production the second largest exporter of coal and a major exporter of uranium and liquefied natural gas(LNG) (BREE，2014b). 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, 2012
Key dataa

Energy reservesb

Area (million sq. km)

7.7

Oil (billion barrels)

3.8

Population (million)

22.7

Gas (billion cubic metres)

3738.4GDP (USD (2010) billion at PPP)

911.8

Coal (million tonnes*)

105 246

GDP (USD (2010) per capita at PPP)

40 124

Uranium (kilotonnes U)

3 471.5

Sources: a. (EDMC，2014). b. (GA，2014); *recoverable economically demonstrated resources of blackand brown coalE N E RG Y S U P P LY A N D D E M A N D

PRIMARY ENERGY SUPPLY
In 2012–13 Australia’s total primary energy supply was 19 318 petajoules or 461 404 ktoe (BREE, 2014a).
Around 59.2% of supply came from coal, 4.6% from crude oil and LPG, 12.6% from gas, 21.9% fromuranium and the remaining 1.7% from renewables (BREE, 2014a).

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Australia accounts for around 9.0% of the world’s black coal production and is the fourth largest producer
behind the United States, Russia and China respectively (BREE, 2014b). Australian coking and steaming
coals are high in energy content and are relatively low in sulphur, ash and other contaminants. Coal isAustralia’s second largest commodity export, earning AUD 40.0 billion in 2013-14 followed by LNG (AUD
16.3 billion) and crude oil (AUD 11.1 billion) (BREE, 2014b). It is also an important component of domesticenergy supply, accounting for approximately 64.0% of total electricity generation in 2012-13 (OCE, 2014).
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 Carnarvon Basin offshore Western Australia, the Gippsland Basin offshore Victoria and theonshore Cooper–Eromanga Basin that straddles the South Australian and Queensland boundary (GA,2014). While gas production remained relatively stable in 2013-14 (62.8 billion cubic metres), the start-up of
Pluto LNG in April 2012 had resulted in around 5 billion cubic metres of additional gas production in 2012–
13 (BREE, 2014b).
Production of coal-seam gas (CSG), which is produced only in New South Wales and Queensland, has
expanded rapidly from a share of 3.0% of total gas production in 2004-05 to 12.0% in 2012–13 (BREE,
2014b). CSG production is likely to continue to grow, and a number of projects are under development.
Australia is a net importer of crude oil and condensate, but a net exporter of liquefied petroleum gas(LPG) (BREE, 2014b). Australia’s crude oil and condensate production declined by 12.0% in 2012-13 largely
due to scheduled production outages (BREE, 2014b). Australia’s oil production is likely to decline (BREE,
2014b).
In 2012-13, 249 075 gigawatt-hours (GWh) of electricity was generated, mostly from coal (64.0%)(BREE, 2014b). Given its abundance, coal is likely to remain the most commonly used fuel in electricity
generation. However, a large number of wind energy projects, are planned or underway, and are expectedto account for an increasing proportion of total electricity generation over the medium to long term.

FINAL ENERGY CONSUMPTION
Australia’s total net energy consumption in 2012–13 fell to 5 884 PJ (or 140 537 ktoe) from 5 915 PJ in
2011-12 (BREE, 2014a). In 2012–13 the electricity generation sector was the largest energy consuming
sector at 27.6% of Australia’s total net energy consumption. The transport sector was the next largest at
26.3%, and then the manufacturing sector at 21.7% (BREE, 2014a). This is followed by the mining (8.3%),
residential (7.7%), commercial (5.2%), other (1.1%) and construction (0.4%) sectors (BREE, 2014a). By
energy source, petroleum products accounted for 37.7% of consumption in 2012–13, coal 33.1%, gas 23.6%
and renewables 5.6% (BREE, 2014a). Gas has increased due to greater uptake by the electricity generation
sector and growth in industrial use (BREE, 2014a). The share of renewable energy consumption increased
in 2012-13 by 12.0% with growth in solar, wind, hydro and biomass, and decline in biogas and biofuel use(BREE 2014a).
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

296 246

Industry sector

23 263Total

Net imports and other–179 201

Transport sector

30 119Thermal214 114

Total PES

122 858

Other sectors

24 170Hydro

14 026

Coal

48 193

Total FEC

77 551

Nuclear–Oil

41 380

Coal

2 985

Geothermal–Gas

27 028Oil

40 047

Others

8 199

Other

6 258

Gas

13 007

Electricity and other

21 511

236 339

Source: (EDMC, 2014).
For full details of the energy balance table, see www.ieej.or.jp/egeda/database/database-top.html.

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ENERGY INTENSITY ANALYSIS
Australia is contributing to the APEC’s aspirational goal of a 45.0% energy intensity reduction by 2015 from2005 levels. Over the last 30 years Australia’s energy intensity has generally improved in Australia as depicted
in Figure 1 (BREE, 2014a). In 2012-13, energy intensity declined by nearly 3.0%. According to BREE
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 theefficiency effect, which relies on changes in energy intensity. The APEC Energy Statistics’ analysis found an
improvement in final energy demand of 1.8% from 2011 levels.
Australia’s energy intensity improvements are likely due to improvements in energy efficiency fromadvances in technology and industry structures shifting towards less energy-intensive sectors such ascommercial and services.
Table 3: Energy Intensity Analysis, 2012
Energy Intensity (tonnes of oil
equivalent per million USD)

Energy2011

Change (%)

20122011 vs 2012

Primary Energy

139.7

140.7

0.7

Final Energy Demand

88.0

86.4

-1.8

Industry

25.8

25.4

-1.7

Transportation

34.0

34.2

0.5

Others

28.2

26.9

-4.5

Source: (EDMC, 2014).

Figure 1: Australian Energy Intensity.

Source: (BREE, 2014a).
P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORK
Australia’s system of government has three tiers: the Federal Government; the six State Governments andtwo territory governments; and the local governments. Either the federal government or the state/territory
governments rather than private individuals own Australian energy resources. None of the tiers of3

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government are engaged in commercial exploration or development. The Australian Federal Government
has title and power over energy resources located outside the first three nautical miles of the territorial sea(‘offshore’).
The State Governments and the Northern Territory have jurisdiction over resources on their lands orinside the first three nautical miles of the territorial sea (‘onshore’). Each state government oversees she
approvals process for unconventional gas exploration for their jurisdiction, with the Australian Government,
under the Federal Department of the Environment, considering aspects of ‘national environmental
significance’ under the Environment Protection and Biodiversity Conservation Act 1999. In this process,each state/territory assesses applications from proponents looking to explore in their area, and then declines
or grants access. Similarly, the state/territory carries out the assessment of safety requirements andenvironmental regulations for the coal industry in their respective jurisdictions.
The Federal Australian Department of Industry and Science oversees resources and energy matters at
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 to respond torising business and household costs, including a new Energy White Paper. The Energy White Paper will
outline a coherent, integrated and efficient regulatory and policy framework, stimulating sustainable growth,building community confidence in environmental safeguards and growing investment in the energy sector.
See also the ‘Notable energy developments’ section. It is due for publication in 2015.
In December 2013, the COAG Energy Council replaced the Council of Australian Governments’(COAG) Standing Council on Energy and Resources (SCER). The role of the Council is to provide a forum
for collaboration between jurisdictions on ‘matters of national significance’ requiring joint action by the
Commonwealth, State and Territory Governments, including developing and implementing an integrated
and coherent energy and mineral resources policy. The Energy Council is responsible for the remits of theformer SCER, Ministerial Council on Energy (MCE) and former Ministerial Council on Mineral andPetroleum Resources (Industry, 2014a). The Australian Minister for Industry and Science chairs it.
The Council’s work covers the following broad themes:Overarching responsibility and policy leadership for Australian gas and electricity markets;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
In 2009, the Australian Government released the first National Energy Security Assessment (NESA), whichassessed the challenges that could affect Australia’s current and future energy security. The NESA defines
energy security as the adequate, reliable and affordable provision of energy needed to support thefunctioning of the economy and social development. ‘Adequate’ is defined as the provision of enough energy
to support economic and social activity; ‘reliable’ as the provision of energy with minimal supply disruptions;and ‘affordable’ as the provision of energy at a price that does not affect the competitiveness of the economy
and encourages investment in the sector.
Using the same definition of energy security, the second NESA in 2011 found that energy security did notdepend on Australian energy independence, or the ability to be self-sufficient. Australia’s overall energy
security should remain adequate and reliable. Increasingly both the level of new investment going forward
and the price of energy, which are both materially influenced by global trends, shaped it. Work hascommenced on the third NESA, with release planned for 2015. The updated NESA webpage link is:www.industry.gov.au/Energy/EnergySecurity/nesa/Pages/default.aspx.
UPSTREAM ENERGY DEVELOPMENT
The following basic principles guide Australian Government’s approach to developing the economy’s energy
resources:

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

The efficient commercial development of its energy resources should be promoted to provide thehighest-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 ongoing domestic energy
security;

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

The Australian Government does not undertake or finance energy resource exploration ordevelopment. In the offshore petroleum sector, the Australian government relies on an annual acreage
release of vacant offshore acreage to create opportunities for investment. The release, distributed worldwide,
is a comprehensive package that includes geological details of the acreage, bidding requirements andinvestment considerations for each release area on offer. The onshore petroleum sector is managed by therelevant State/Territory jurisdictions.

ENERGY MARKETSMARKET REFORMS
Energy market reform is a priority issue for COAG (Industry, 2014b). To date reforms have included
creating the National Electricity Market, and 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, 2014).
ELECTRICITY AND GAS MARKETSThe National Electricity Market (NEM) was established in 1998 to allow the inter-jurisdictional flow ofelectricity between the Australian Capital Territory, New South Wales, Queensland, South Australia andVictoria (Tasmania joined the NEM in 2005). The NEM is not connected to Western Australia and the
because of their distance from the rest of the market. The NEM comprises both a wholesale sector and acompetitive retail sector. All electricity dispatched must be traded through the central pool, where output
from generators is aggregated and scheduled to meet demand.
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 seeing an expected tripling of domestic gas production
over this period in response to strong international and steady domestic demand growth. On 3 January 2014,
in response to concerns about the dynamics of the eastern Australian gas market as it makes this transition,
the Australian Government released the Eastern Australian Domestic Gas Market Study. The objective of
this study was to inform policy makers of the demand supply situation in the eastern Australian gas market
and barriers to domestic gas supply over the period 2012–23, as well as canvassing opportunities to improve
market efficiency. The Australian Government’s response to the eastern Australian gas market and supply
issues will be included as part of the Australian Government’s Energy White Paper (Industry, 2014c).
A key component of the ongoing energy market reforms was the 1 July 2009 establishment of theAustralian Energy Market Operator (AEMO). The AEMO is 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, 2014).
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

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transmission network; economy-wide transmission planning; and establishing a short-term trading market
for gas from 2010 (AEMO, 2014).
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 more
information to market participants and potential investors. In addition, it publishes the Statement ofOpportunities 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,
2014).
The AEMO oversees Australia’s energy market governance in cooperation with the Australian Energy
Market Commission (AEMC), as the rule-making body, and the Australian Energy Regulator (AER), as theregulating body. The COAG Energy Council, comprising energy and resources ministers from all Australian
governments, is responsible for energy policy and the legislative frameworks under which AEMO, AEMC
and AER operate.
A review of the governance arrangements of these three energy institutions is scheduled to begin inearly 2015. This review will consider the performance of current governance arrangements for energy
markets and provide advice to the COAG Energy Council on potential areas of improvement to theinstitutions and their oversight by the COAG Energy Council. More information including the Terms ofReference for the Review is available at www.scer.govspace.gov.au/workstreams/energy-marketreform/review-of-governance-arrangements.

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 earning an income in Australia are subject tocorporate income tax, which is imposed at a rate of 30.0%. Project ring fencing does not apply, and profits
and losses of one project can be used to offset those of another project, subject to common ownershipcriteria.
Certain expenditures 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. 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). Furthermore, where other layers of resource taxes areapplicable (such as State and Territory royalties and Federal crude oil excise), these expenditures are
creditable against the liabilities of PRRT projects. This ensures that petroleum projects are not subject todouble taxation (ATO, 2014a).
PRRT applies at a rate of 40.0% 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. As 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 a number of conditions. PRRT payments are deductible for income tax purposes, and a PRRT liability is
calculated as per Figure 2 below (ATO, 2014a).
Figure 2: Calculating a PRRT Liability

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ROYALTIESRoyalties are generally levied by the States and are an alternate mechanism to charge for resource extraction.
Royalty rates vary across states and commodities, and are either specific, ad valorem, profit based or a hybrid(flat ad valorem with a profit component). For petroleum, the state and Northern Territory governments
collect royalties for onshore production. The rate is generally between 10.0% and 12.5% of the net wellhead
value of production depending on whether it is from a primary or secondary production licence, or a
combination.
For offshore production (excluding petroleum), 60.0% of the royalties are directed to the state or
territory government and the remaining 40.0% 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
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 is exempt from crude oil excise.
EXPLORATION DEVELOPMENT INCENTIVE (EDI)
Effective from 1 July 2014, the Australian Government introduced the EDI to encourage investment insmall exploration companies undertaking ‘greenfields’ mineral exploration in Australia. The scheme isavailable to junior minerals explorers incurring eligible ‘greenfields’ exploration expenditure in Australia.
Where 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 componentsof the package are:

A 45.0% refundable tax offset for companies with a turnover of less than AUD 20 million per year;A 40.0% 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 90.0% to TimorLeste and 10.0% 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, and so from 1 October 2014 MRRT
liable entities will not accrue further liabilities. (ATO, 2014b).
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A U S T RA LI AINVESTMENT
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’s 2014 National Transmission Development Plan (NTNDP) forecasts between AUD 9.1 and 17.7
billion for electricity transmission investment assets will be required over the next 20 years (AEMO, 2014).

ENERGY EFFICIENCY
Australia has a number of programs and regulatory measures that promote energy efficiency. The National
Strategy for Energy Efficiency (NSEE), released in July 2009, is an overarching programme of work for
promoting energy efficiency in Australia. The NSEE is a coordinated approach to accelerating energy
efficiency efforts that help households and businesses reduce their energy costs and prepare for theemissions reduction measures and targets.
The NSEE incorporates and builds on measures already agreed on by COAG and the SCER throughthe National Framework for Energy Efficiency (NFEE). All NFEE projects and activities form part of the
NSEE, which is now the responsibility of the COAG Energy Council. The NSEE is a 10-year strategy
containing measures across all sectors—commercial and residential buildings, appliances and equipment,
industry and business, government, transport, skills, industry innovation, advice and education. The NSEE
addresses barriers that prevent the optimal uptake of energy efficient opportunities, such as information
failures.

RENEWABLE ENERGY
Australia has abundant and diverse clean energy resources with significant potential for future development
as shown in Figure 3 (take from 4 of the AER). Solar PV use increased by 49.2% in 2012-13 along with a
3.9% increase in solar hot water from 2011-12 (BREE, 2014a). Wind-powered electricity generation
increased by 19.9% in 2012-13 relative to 2011–12 levels (BREE, 2014a). Hydro also increased significantly
at 29.7% in 2012-13 relative to 2012-11 levels, due to ‘increased water inflows in south eastern Australia as
well as improved relative costs of hydro under the carbon price’ (BREE, 2014a).

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Figure 3: Map of 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 allow theGovernment to replace the Mandatory Renewable Energy Target (MRET) with the expanded Renewable
Energy Target (RET) from 1 January 2010 (Environment 2014a).
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 20.0%(or around 60 000 GWh) of electricity supply to be provided from renewable sources by 2020. This includes
a target of 45 000 GWh of new renewable electricity generation, on top of the 15 000 GWh of existing
renewable. The LRET would deliver the majority of the 2020 target (41 000 GWh). The uncapped SRES
provides a subsidy to small-scale technologies, such as residential solar panels and solar hot water systems.
The Australian Government undertook a review of the RET. The Expert Panel has completed its
review and provided a report to the Government, which is available at: www.retreview.dpmc.gov.au/. The
Australian Government is seeking to reform the RET to allow sustainable in renewable energy use andcreate a more stable environment for long-term investment.

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The Australian Renewable Energy Agency (ARENA) is an independent agency established by theAustralian Government on 1 July 2012. It has AUD 2.5 billion out to 2022 to fund renewable energy projects(solar, bioenergy, marine geothermal and enabling technologies) and support research and development,commercialisation and early deployment activities, along with activities that capture and share knowledge.
The two objectives of ARENA are to improve the competitiveness of renewable energy technologies andto increase the supply of renewable energy in Australia. The Australian Centre for Renewable Energy andthe Australian Solar Institute has been incorporated into ARENA. By June 2014 ARENA had committed$1.2 billion in support of more than 200 projects, studies fellowships and scholarships, which have a total
value of $3.5 billion.
ARENA’s independent decision-making board, also referred to as the ‘Board’, consists of up to sevenmembers appointed by the Minister for Industry and Science and has a CEO appointed by the Minister for
Industry and Science, on the recommendation of the Board. 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, but all of these schemes have now been amended or closed.
In December 2014 Australia reached 4GW of installed solar, representing a four-fold increase frominstalled capacity in 2011. The majority of this capacity is small-scale rooftop systems. Over two million
households have installed solar PV or solar hot water systems in Australia with penetration levels over 20.0%
in some areas.
Over the long term, renewables consumption will increase by approximately 0.9% to 2049-50 andrenewables in electricity generation will grow by 1.5% to 2049-50 (BREE, 2014d). Renewables generation
will grow to 20.0% of the percentage share of electricity generation by 2049-50, with 10.0% from windenergy (BREE, 2014d).
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 including the Australian Research Council, which has established arange of competitive grants schemes. 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 5.0% 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, 2014b).
The ERF has a capped funding allocation of $2.55 billion. The fund has three main components:
crediting emissions reductions, purchasing emissions reductions, and safeguarding emissions reductions(CER, 2014). The emissions reduction fund enables the Government to ‘purchase lowest cost abatement(in the form of Australian carbon credit units) from a wide range of sources’ (CER, 2014). The Clean Energy
Regulator (CER) will administer the fund.
The carbon tax was repealed by Parliament with effect from 1 July 2014 (Environment, 2014c).

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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 5 December 2013 the Australian Government released the terms of reference for the Energy White
Paper and the Issues Paper was released on 17 December 2013. The Issues Paper provided an overview ofthe energy issues facing Australia. They included: energy supply security, regulatory reform and the role ofgovernment, growth and investment, trade and international relations, workforce productivity, driving
energy productivity, and alternative and emerging energy sources and technology.
A Green Paper was released on 23 September 2014 which presented a clear set of policy goals acrossfour priority areas: pursuing a focus on deregulation; promoting competition; creating more certainty andcompetition in gas markets; and improving economic, environmental and security outcomes. The Energy
White Paper will be released in 2015. The Energy White Paper will set out an integrated and coherent
Australian Government position on energy policy and will consider the supply and use of Australia’s energy
resources to deliver security of supply, increases in new energy sources to ease demand/ and supply
constraints, regulatory reform to put downward pressure on prices, and improved energy productivity.
Downward pressure on prices will help relieve cost-of-living pressures and improve businesscompetitiveness. For more information see: www.ewp.industry.gov.au.

G20-INTERNATIONAL ENERGY FORUM GAS MARKETSDIALOGUE
In November 2014 Australia and Mexico co-chaired the G20-International Energy Forum (IEF) Gas
Markets Dialogue. It was the first G20IEF and it aimed to bring together gas industry experts from business,government, and international and regional organisations to enhance collaboration and to identify practicalways to improve how gas markets function. The dialogue centred around three themes: increasing market
transparency; encouraging investment in gas infrastructure; and exchanging information about Australia’s
the region’s 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.
The G20 Energy Efficiency Action Plan was endorsed by G20 Leaders at the November G20 summit andprovides a significant step for improving energy efficiency globally through international cooperation.
The G20 Energy Efficiency Action Plan documents six work streams where G20 members and guests
will work together to improve energy efficiency. Each G20 member and guest has nominated which work
streams they will participate in from the Action Plan. These work streams will be progressed through theInternational Partnership for Energy Efficiency Cooperation (IPEEC) and other international organisations
such as the IEA, throughout 2015. The G20 has also tasked IPEEC to report on the progress 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 MANAGEMENTS
REVIEW
In 2014 the Australian Government Department of Industry commenced a high-level strategic review ofthe offshore petroleum frameworks governing oil and gas resource management in Commonwealth waters.
The Offshore Petroleum Resource Management aims to refine the regulatory and administrative frameworks
that support timely and efficient commercial investment, exploration and development. A consultation
paper was released in November 2014, an interim report is planned for late March 2015, and a final report
is scheduled for release mid-2015.

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The
Terms
of
Referenceforthe
Reviewisavailablefordownload
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. BREE’s Electricity Generation Major Projects provides a list of major electricity generation facilities
under development, including renewable and non-renewable sources. It is available for download at:www.bree.gov.au/publications/major-electricity-generation-projects.
REFERENCES

ABS (Australian Bureau of Statistics) (2014). Cat 5206.0 - Australian National Accounts: National Income,Expenditure and Product, 3 September 2014. www.abs.gov.au/ausstats/abs@.nsf/mf/5206.0/.
AEMO (Australian Energy Market Operator) (2014). Australia Energy Market Operator: Homepage.
www.aemo.com.au/.
ATC (Australian Trade Commission) (June 2014), Digital Benchmark Report, www.austrade.gov.au/digitalbenchmark/growth.html#anchor2/.
ATO (Australian Tax Office) (2014b). Mineral Resource Rent Tax (MRRT).
www.ato.gov.au/Business/Minerals-resource-rent-tax/.
–––– (2014a). Petroleum Resource Rent Tax (PRRT). www.ato.gov.au/Business/Minerals-resource-rent-tax/.
BREE (Bureau of Resources and Energy Economics) (2014d). Australian Energy Projections 2049-50.
www.bree.gov.au/publications/australian-energy-projections-2049%E2%80%9350/.
–––– (2014a). Australian Energy Statistics. www.bree.gov.au/publications/australian-energy-statistics/.
–––– (2014b). Energy in Australia. www.bree.gov.au/publications/energy-australia/.
–––– (September 2014c). Resources and Energy Quarterly. www.bree.gov.au/publications/resources-andenergy-quarterly/．
OCE (Office of the Chief Economist) Resources and Energy Statistics 2014, Department of Industry and
Science, Canberra, 3/12/2014.
CER (Clean Energy Regulator) (2014). Emissions Reduction Fund.
www.cleanenergyregulator.gov.au/Emissions-Reduction-Fund/Pages/default.aspx/.
COAG (Coalition of Australian Governments) (2014). COAG Energy Council. www.scer.gov.au/.
EDMC (The Energy Data Modelling Centre, The Institute of Energy Economics, Japan) (2014). APEC
Energy Statistics 2012 and the APEC Energy Database, www.ieej.or.jp/egeda/database/databasetop.html/.
Environment (Australian Government Department for the Environment) (2014b). Emissions Reduction
Fund. www.environment.gov.au/climate-change/emissions-reduction-fund/.
–––– (2014a). The Renewable Energy Target (RET) Scheme. www.environment.gov.au/climatechange/renewable-energy-target-scheme/．
–––– (2014c). Repealing the Carbon Tax. www.environment.gov.au/climate-change/repealing-carbon-tax/.
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 and Science) (2014a) COAG Energy Council.
www.industry.gov.au/resource/Pages/AustralianEnergyCouncil.aspx/.
–––– (2014b). Energy Markets. www.industry.gov.au/Energy/EnergyMarkets/Pages/default.aspx.
–––– (2014d) Energy Savings Initiative. www.industry.gov.au/Energy/Energyinformation/Pages/Reports.aspx/.
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APEC E N E RG Y O VE R VI E W 2014

A U S T RA LI A–––– (2014c). Gas Market Development.
http://www.industry.gov.au/Energy/EnergyMarkets/GasMarketDevelopment/Pages/default.aspx.
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
Office of the Chief Economist — http://www.industry.gov.au/industry/Office-of-the-ChiefEconomist/Pages/default.aspx
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 R U N E I D A RU S S A L 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 strategically located on the north-west
coast of the island of Borneo. It covers a total land area of around 5 765 square kilometres and has a 161
kilometre coastline along the South China Sea. It is bordered on the north by the South China Sea and on
all other sides by the Malaysian state of Sarawak, which divides the economy into two parts. Brunei
Darussalam has four districts: the eastern part is the Temburong District, and the western part consists of
the Brunei-Muara, Tutong and Belait districts; and its capital, Bandar Seri Begawan, is located in the BruneiMuara District. Brunei Darussalam is a small economy with great potential. In 2013, it had a population ofaround 406 200. It is characterised by a mixture of foreign and domestic entrepreneurship, government
regulation, welfare programs and traditional village economies.
Brunei Darussalam’s GDP in 2013 was USD 29.0 billion (at 2010 USD PPP). Notwithstanding thechange in PPP base year from 2005 to 2011, the economy is still enjoying a very high GDP per capita at
USD 70 284 in 2013 as compared to other Southeast Asian economies (EDMC, 2014). The oil and gas
sector continue to be the economy’s main source of revenue and constitutes more than 60.0% of Brunei
Darussalam’s GDP. To further sustain and strengthen the oil and gas industry, the government is actively
strengthening oil and gas upstream and downstream activities as well as energy services (EDPMO, 2015).
Table 1: Key data and economic profile, 2013
Key data

Energy reserves

Area (sq. km)a

5 765

Oil (billion barrels)c

1.1

Population (thousand)a406.0

Gas (billion cubic metres)c

3 000

GDP (USD (2010) billion at PPP)b

29.0

Coal (million tonnes)c–

GDP (USD (2010) per capita at PPP)b

70 284

Uranium (kilotonnes U)–

Sources: a. (DEPD, 2013); b. (EDMC, 2014); c. (BP, 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 of Brunei Darussalam in 2012 was 3 406 kilotonnes of oil equivalent (ktoe).
Natural gas represented about 78.0% of the total primary energy supply and oil 22.0%. Oil and gas
production reached 20 016 ktoe in 2012. As a major oil and gas exporter, Brunei Darussalam exported 82.0%
of its oil and gas production in 2012 (EDMC, 2014).
Crude oil production and condensate in 2013 was 135 thousand barrels per day, the majority of which
was exported (93.0%). The export destinations for Brunei Darussalam’s oil and condensate in 2013 wereAustralia (15.3%); Indonesia (11.1%); India (16.2%); Republic of Korea (17.7%); and Vietnam (11.4%). Gas
production was around 33.9 million cubic metres a day, most of which was exported as liquefied natural gas(LNG) to the major markets of Japan and South Korea (EDPMO, 2015).
Brunei Darussalam’s total installed electricity generation capacity from both public utilities andindustries reached 916.7 megawatts (MW) in 2012 (DEPD, 2013, p.45). In the same year, total electricity
generated was 3 931 GWh, with almost all of the electricity generated being supplied by natural gas (EDMC,
2014).

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Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

20 016

Industrial sector

203

Total

Net imports and other-16 488

Transport sector

451

Thermal

3 929

Total PES

3 406

Other sectors

314

Hydro

–

Coal

–

Total FEC

968

Nuclear

–

Oil

750

Coal

–

Geothermal –

Gas

2 656

Oil

666

OthersOthers

–

Gas

26

3 931

2

Electricity and other 276
Source: (EDMC, 2014).

FINAL ENERGY CONSUMPTION
Brunei Darussalam’s total final energy consumption in 2012 reached 968 ktoe. The transport sector topped
the economy’s energy demand at 451 ktoe or 46.6% of the total amount. The other sectors (residential,commercial and non-energy) consumed 32.4% of the total energy used and the industrial sector 21.0%. In
terms of energy source, oil accounted for 68.8% of final consumption, followed by electricity and other(28.5%) and gas (2.7%). Natural gas accounted for 99% of the fuel type used to generate electricity, 0.96%
was generated by diesel fuel and 0.04% from solar system (EDMC, 2014).

ENERGY INTENSITY ANALYSIS
Brunei Darussalam is contributing to the APEC overall aspirational goal of a 45.0% intensity reduction by2035 (2005 as base year). In 2012, primary intensity was 117.6 tonnes of oil equivalent per million USD or
an improvement of less than 1.0% over the last year’s primary intensity. Meanwhile, the economy’s final
energy intensity reached 33.4 toe/million USD, with the transportation sector accounting for the biggest at
15.7 toe/million USD in view of the economy’s increasing energy requirement in the said sector (Table 3).
Table 3: Energy Intensity Analysis, 2012

EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

117.7

117.6

-0.1

Final Energy Demand

31.9

33.4

4.7

Industry

6.2

7.0

12.1

Transportation

15.0

15.6

3.7

Others

10.6

10.8

1.9

Source: (EDMC, 2014).
P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORKEnergy continues to be the core pillar of Brunei Darussalam’s economy and the oil and gas industry is main
driver for its economic growth (EDPMO, 2013). In 1981, the Oil Conservation Policy was introduced after
oil production peaked at 261 000 barrels per day in 1979. The policy aimed to extend the life of theeconomy’s oil reserves. As a result, oil production gradually declined to around 150 barrels per day in 1989.

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In November 1990, the government reviewed the policy and removed the production ceiling, resulting in
production of 219 barrels per day by 2006. By 2011, crude oil and condensate production averaged 165
barrels per day. In 2000, the Brunei Natural Gas Policy (Production and Utilisation) was introduced. The
policy aimed to maintain gas production at 2000 levels in order to adequately satisfy export obligations, toopen new areas for exploration and development, and to encourage increased exploration by new andexisting operators. Under the policy, priority is always given to domestic gas use, especially for electric power
generation.
In January 2002, the Brunei National Petroleum Company Private Limited (PetroleumBRUNEI) was
empowered to manage Brunei Darussalam’s commercial interests in the oil and gas sector.
PetroleumBRUNEI has been granted all mineral rights in nine petroleum exploration blocks, nominee
shareholder status in the Brunei Methanol Company Private Limited, and one of its subsidiaries, PB
Logistics, is a shareholder in Brunei Methanol Tanker (BMT).
On 24 May 2005, His Majesty the Sultan and Yang Di-Pertuan of Brunei Darussalam created theposition of the Minister of Energy at the Prime Minister’s Office and with it, the Energy Division at thePrime Minister’s Office. The Energy Division was responsible for formulating the economy’s energy policy
as well as presiding over matters related to energy. The Petroleum Unit, which oversaw the development ofBrunei Darussalam’s natural gas and oil sector, and the Department of Electrical Services, which is tasked
with managing and developing its electricity sector, also 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 theEnergy Department, Prime Minister’s Office.
Brunei Darussalam has implemented a series of five year economic development plans known as the
National Development Plan. Currently, the tenth National Development Plan (RKN 2012-2017) is in force.
This is the second five-year plan under the long-term development plan, Vision Brunei 2035, which statesthat the economy’s major goals for the next three decades are economic diversification and strengtheningof the oil and gas sector. The latter is to be achieved by expanding the economy’s oil and gas reserves
through on-going exploration in both existing and new areas.
In March 2014, the Energy Department, Prime Minister’s Office launched Brunei Darussalam’s first
Energy White Paper that sets out a framework for strategic actions that ensures a more sustainable energy
sector for Brunei Darussalam.
ENERGY SECURITY
Recognising the need to enhance energy security and sustainability, improve energy efficiency and accelerate
deployment of renewable energy and clean energy supply for Brunei Darussalam, the economy works tostrengthen partnership 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 relating to energy security, diversification of supply,
energy efficiency and conservation among the regions. The economy is working actively with the association
towards the achievement of the targets set under the ASEAN Plan of Action on Energy Cooperation 2010–
15 (the Action Plan), which include 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 its National plan or
known as the Wawasan Brunei 2035. Energy will continue to serve as the major catalyst in the economy’s
investment, education and infrastructure development (EDPMO, 2013). Brunei Darussalam’s 2014 Energy
White Paper indicated three strategic goals in addressing the growth of the energy sector (Ibid), namely: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) weredeveloped under these. These KPIs will help address the needs across the energy sector to achieve the targets
set under each strategic goal.

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UPSTREAM ENERGY DEVELOPMENT
Brunei Darussalam’s existing and potential oil and gas reserves lie within the economy’s northern landmass
and extend offshore to the outer limits of its exclusive economic zone. Most of the existing oil and gas
production is located in scattered sites around 70 kilometres offshore. While its 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.
As also indicated in the Energy White Paper, the upstream development is one of the strategic goalsin Brunei Darussalam Vision 2035 where the economy put forth great efforts in view of its increasing
challenges. The economy’s energy resources traced its roots back from its first oil discovery in early 19th
century, which spurred development in other sectors of the economy. Now, with its currents oil and gas
combine production of around 372 000 barrels of oil equivalent per day (Ibid), the economy will continue
to boost its upstream production by maximising the potential of its mature fields and venturing into further
exploration and development activities. Specifically, Brunei Darussalam will undertake several initiatives tostimulate production, such as the following:

Rejuvenate existing fields;

Maximise economic recovery from newly discovered fields;



Review potential solutions for the development of small and unconnected fields; and

Upstream international ventures.

DOWNSTREAM ENERGY DEVELOPMENT
The biggest contributor to the existing downstream industry in Brunei Darussalam comes from methanol
produced from the economy’s abundant natural gas resources as feedstock. According to Brunei Darussalam
Vision 2035, the industry is targeting to contribute about BND 300 million to the economy annually, which
would mean increasing the economic output from the downstream processing to satisfy the growing demand
especially for the supply of emerging markets. 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) for petrochemicals and other downstream oil and gas activities.
The government will provide appropriate support and incentives in order to attract more investors toventure into developing and diversifying additional downstream opportunities such as gas-based
petrochemicals, 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 to ensure the achieving of the target. Enabling such activity under this initiative could function
as a possible extension of the petrochemical chain to include ethylene and propylene building 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 to support the strategic objectives set out for the energy sector. The Energy
Department of the Prime Minister’s Office (EDPMO) has initially identified four key regulatory policies andframeworks, which include among others, instituting a regulatory body to monitor the local content
requirement in the bidding process for contracts from operators. The Local Business Development (LBD)
Framework was enforced to ensure that there is a fair and level playing field in the market.
The Government regulates the energy market in Brunei Darussalam. The Government will continue
to provide a subsidy for petroleum products, such as gasoline, diesel and LPG, in order to fix and stabilise
the pump prices at the retail stations regardless the level of oil prices in the international market. This is toensure welfare and benefits of the member economy government.
ELECTRICITY MARKETThe Department of Electrical Services, established in 1921, fulfils the regulatory functions for the power
sector. Its mission 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 generation
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is almost entirely natural gas fired. The only exceptions are the diesel power station at Belingus and the 1.2
MW Tenaga Suria Brunei (TSB) photovoltaic demonstration plant. The transmission system consists ofthree grids operated by the two electrical utilities.

ENERGY EFFICIENCYBrunei Darussalam is actively promoting energy efficiency and conservation in various sectors in theeconomy. Relevant government agencies collaborate in evaluating legislative, financial and fiscal policy
measures that promote energy efficiency and low-energy intensive industries. These industries likewise playa role in the energy conservation efforts of the government, which include, among others, the identificationof technical levers that reduce energy usage over time. Meanwhile, individual consumption behaviour
likewise shifts towards energy efficiency that includes making choices on high-energy efficient appliances.
The EDPMO is now in the process of enacting a regulatory framework on Energy Efficiency andConservation (EEC) through the economy’s National EEC Committee. This committee serves as the bodythat coordinates EEC efforts with various stakeholders at a high-level and oversees the implementation the
EEC Plan of Actions on four major sectors namely residential, commercial, industry and transportation(EDPMO, 2013). The Brunei National Energy Research Institute (BNERI) established in 2012 that serves
as the economy’s research arm and think tank for energy, likewise continues to conduct study on energy
efficiency and conservation.

RENEWABLE ENERGY
One of the KPI’s under the second key strategic goals of the economy, renewable energy development inBrunei Darussalam has four major priority initiatives, namely:Introduce renewable energy policy and regulatory frameworks;



Scale-up market deployment of solar PV and promote waste-to-energy technologies;



Raise awareness and promote human capacity development; andSupport 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 1344 Mwh ofelectricity annually, saving 340 kilolitres of crude oil and avoiding 940 tonnes of CO2 emissions annually.
The actual electricity recorded in 2010 was 808 Mwh, i.e. saving an equivalent 205 kilolitres of crude oil andavoiding 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 between 10 to 15 MW.

NUCLEAR
Brunei Darussalam does not have a nuclear energy industry.

CLIMATE CHANGE
Brunei Darussalam recognises the importance of its economic growth on energy security and environmental
sustainability. Environmental policy directions are embedded in the Vision Brunei 2035. These include:

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

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

Brunei Darussalam acceded to the United Nations Framework Convention on Climate Change(UNFCCC, 2012) in 2007 and subsequently to its Kyoto Protocol in 2009. It also associated itself with the
Copenhagen Accord in 2009. At the 18th session of the Conference of the Parties (COP18) to the UNFCC,
it pledged to continue integrating environmental dimensions into its national development projects. Someof the proposed steps include (UNFCCC, 2012):


Introducing Environmental Impact Assessment (EIA) in the planning and implementation of projects;



Optimising land use by introducing vertical development in national housing schemes;Conserving carbon sink resources by maintaining 50.0% of total land area under forest cover andapportioning a percentage of built-up areas as green areas;Promoting environmentally sound technology and products;

Enhancing awareness of environmentally friendly lifestyles and resource efficiency;Promoting green building initiatives; andIncreasing the utilisation of renewable energy to reach 10.0% of the energy mix by 2030.
N OTA B L E E N E RG Y D E V E L O P M E N T S

ENERGY INFRASTRUCTURE PROJECTSThe government of Brunei Darussalam seeks to maximise the potential of the economy’s oil and gas
resources and to take advantage of its strategic location for trading. One of the key initiatives under the
Vision Brunei 2035 is to designate industry ‘cluster-specific’ sites with supporting infrastructure and facilities.
The first site, established in 2007, was the Sungai Liang Industrial Park (SPARK), designed specifically fordownstream petrochemical processing activities. The first petrochemical plant constructed at the site, amethanol production plant, was successfully commissioned in April 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(BEDB, 2012). The anchoring project will be a USD 2.5 billion oil refinery and aromatics cracker project tobe developed by the Zheijiang Hengyi Group Co. Ltd. The project is expected to begin operations in 2018,with a production capacity of approximately 175 000 barrels per day. The first phase will consist of the
production of petroleum products such as gasoline, diesel and jet A-fuel, as well as paraxylene and benzene,
which is used mainly in textile production (BEDB, 2012). The feedstock for this plant will be crude oil andcondensate.
In the power sector, a Memorandum of Understanding was signed between the Brunei Government,
Brunei LNG and Brunei Shell Petroleum Company 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 of greater than 60.0% through theapplication of combined heat and power integration or cogeneration (EWG, 2012).

BRUNEI NATIONAL ENERGY RESEARCH INSTITUTE(BNERI)
Brunei Darussalam’s newly established energy research centre, the Brunei National Energy ResearchInstitute (BNERI), is now fully operational. This centre aims to be an international centre of excellence in

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energy and will focus on developing innovative solutions for using fossil fuels, for energy efficiency andconservation, and for renewable energy.

THE US-ASIA PACIFIC COMPREHENSIVE ENERGYPARTNERSHIP (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 U.S.-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 EAS Energy Cooperation. The main aim of this RAPG Work Stream
is to spur new renewable energy collaboration and cooperation in the EAS region. The RAPG projects will
coexist and complement current renewable energy activities within ASEAN and Dialogue Partners so as toelevate the role of renewable energy in the region. The project areas cover solar photovoltaic, wind andhydro.
REFERENCESBEDB (Brunei Economic Development Board) (2012), ‘Over US$2.5b investment in oil refinery andaromatics cracker project in Brunei’, press release.
www.bedb.com.bn/news_articles_details.php?id=123.
BP (British Petroleum) (2014). BP Statistical Review of World Energy June 2014.
http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-worldenergy.html.
Brunei Times (2011). Spark Gets New Locator: $3.37 billion Petrochem Complex. 30 August 2011.
www.bt.com.bn/news-national/2011/08/30/spark-gets-new-locator-3-37-billion-petrochemcomplex.
Brunei Times (2012). Brunei Sees Decrease in Methanol Export, 12 March 2012.
http://www.bt.com.bn/legco/2012/03/12/brunei-sees-decrease-methanol-export/.
DEPD (Brunei Department of Economic Planning and Development) (2008). Wawasan Brunei 2035.
January 2008.
––––(2013). Brunei Darussalam Statistical Yearbook 2011. www.depd.gov.bn/home.html.
EDMC (The Energy Data Modelling Centre , The Institute of Energy Economics, Japan) (2014) APEC
Energy Statistics 2012 and the APEC Energy Database www.ieej.or.jp/egeda/database/databasetop.html/.
EDPMO (Energy Department Prime Minister’s Office) (2014). Energy White Paper.
http://energy.gov.bn/Shared%20Documents/Publications/Energy%20White%20Paper%202014(1).pdf––––(2015). Official Internal Data.
EWG (APEC – Energy Working Group) (2012). Key Notable Energy Developments since EWG43 Brunei
Darussalam.
www.ewg.apec.org/documents/Key%20Notable%20Energy%20Developments%20since%20EWG4
3.pdf.
FGE (Facts Global Energy) (2010). Overview of Brunei’s Gas Balance: Implications for LNG Exports, Issue #49,
June 2010. www.fgenergy.com/?page=download&id=1989/.
KOV (Kulcyzk Oil Ventures) (2013). Press Release: Brunei-KOV Acquires Rig for 2013 Drilling Campaign.
http://www.reuters.com/article/2013/01/03/idUSnCCN1gXnqa+1c8+MKW20130103/
UNFCCC (United Nations Framework for Climate Change and Convention) (2012). Brunei Darussalam
Country Statement.

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http://unfccc.int/resource/docs/cop18_cmp8_hl_statements/Brunei%20Darussalam%20Country%20Statement%20COP18CMP8%20Doha%202012.pdf
USEFUL LINKS

Brunei Economic Development Board—www.bedb.com.bn
Brunei LNG Sdn Bhd— http://www.bruneilng.com/home.asp
Brunei Shell Petroleum Company Sdn Bhd—www.bsp.com.bn
Energy Department, Prime Minister’s Office—www.energy.gov.bn
Prime Minister’s Office, 2013—www.energy.gov.bn/Pages/default.aspx

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

Canada is the second largest economy in land area, behind Russia, in the APEC region and the world. Itsborder with the United States of America (USA) is the longest international border in the world. The
population, of more than 34 million, lives predominantly in the southern cities close in proximity to theUSA. Out of the 13 provinces and territories, approximately three-quarters of the population resides in theprovinces of Ontario (38.6%), Quebec (23.3%) and British Columbia (13.1%) (Statistics Canada, 2014).
Canada is an economically robust nation with a gross domestic product (GDP) of USD 1 417.45, which is
the 8th largest in the APEC region and grew by 1.71% from 2011. However, GDP per capita experienced aslightly lower growth of 0.5%, amounting to USD 40 785 in 2012.
Canada is endowed with rich and diversified natural resources, making it the fifth largest energy
producer in the world behind China, the USA, Russia and Saudi Arabia and the fourth largest in the APEC
region. The development of Canada’s rich resources positively impacts the economy, directly contributing
to 9.5% of total Canadian GDP in 2012 (NEB, 2014a). Canada’s total primary energy supply was an
estimated 251.1 Mtoe in 2012, relative to 207.8 Mtoe of final energy consumption (EDMC, 2014), making
the nation a net exporter and well positioned to supply growing world energy demand.
The economy is well known for its rich supply of indigenous energy resources, with abundant reservesof oil, natural gas, coal, and uranium. Fossil energy reserves consist of the third largest proven oil reserves
behind Venezuela and Saudi Arabia, and a smaller yet critical share of the world’s proven gas reserves.
Canada draws on its vast oil and gas reserves estimated at 172.5 billion barrels and 2 024.7 billion cubic
meters, respectively. Of the 172.5 billion barrels of oil reserves, 97.0% can be recovered fromunconventional oil sands, situated predominantly in the province of Alberta and partly in Saskatchewan.
Canada has a large coal endowment with 8 700 million tonnes of proven resources of coal-in-place actively
mined in western provinces and Atlantic Canada. Of that amount, 6 600 million tonnes are deemed
recoverable using existing technology under current and expected local economic conditions (NRCan,
2014a). Just as competitive, Canada’s uranium reserves are the fourth largest in the world, at 494 kilotonnesof uranium metal located in the Athabasca Basin of northern Saskatchewan. The Athabasca Basin isconsidered the world’s largest deposit of high-grade uranium with grades up to 20.0% uranium, 100 times
greater than the world average (NRCan, 2014b).
Table 1: Key Data and Economic Profile, 2012
Key dataa,bEnergy reservesc

Area (million sq. km)

10.0Population (million)

34.8

Oil (billion barrels)
Conventional (billion barrels)
Oil sands (billion barrels)

172.5
5.3
167.2

GDP (USD (2010) billion at PPP)

1 417.5

Gas (billion cubic metres)

2 024.7

GDP (USD (2010) per capita at PPP)

40 785

Coal (million tonnes)

8 700

Uranium (kilotonnes U)

494

Source: a. (CAPP, 2014a); b. (EDMC, 2014); c. (NRCan, 2014a) and (NRCan, 2014b).
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 419.7 Mtoe in 2012 dominated by fossil fuel production
accounting for approximately 83.0%. Fossil fuel production can be separated into: oil (185.6 Mtoe; 44.0%),
natural gas (129.9 Mtoe; 30.9%), and coal (33.5 Mtoe; 7.9%). The remainder of production consists of:hydropower (32.7 Mtoe; 7.8%), nuclear (24.7 Mtoe; 5.9%), and new and renewable sources (13.2 Mtoe;
3.1%) (EDMC，2014). On a regional basis, Alberta accounts for 64.6% of Canada’s primary energy
production, followed distantly by British Columbia (14.4%), Saskatchewan (8.4%), Quebec (4.1%), andOntario (2.7%) (NRCan, 2013a).
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Canada is a net exporter of most energy commodities, and stands out as the largest foreign supplier ofenergy to the USA. Just as the USA relies on Canada for much of its energy needs, Canada too is dependent
on the USA as its largest export market. Canada exported a large proportion of its production. Primaryenergy supply in 2012 totalled 251.5 Mtoe, equivalent to 59.9% of its production. While primary energy
supply declined by 0.7% from 2011, net exports rose considerably by 7.7%. Canada has experienced steadyexport growth between 2000 and 2012 at 2.3% yearly, despite the economic downturn experienced between
2008 and 2010. This continued growth reflects Canada’s ability to take advantage of its natural resource
endowment to meet domestic consumption while growing its role as an energy exporting economy.
Factors affecting the pace of both conventional and unconventional energy production include: skilled
labour shortages, water availability, environmental regulations, rising costs for labour, refining/upgrading,pipeline constraints, and natural gas shortages. The labour issue will be further intensified by the challengeof building new community infrastructure in remote areas in which oil and gas is produced such as Fort
McMurray and surrounding areas in Northern Alberta (NRCan, 2014c).
Table 2: Energy Supply and Consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)
Total

Indigenous production

419 660

Industry sector

58 980634 400

Net imports and other-168 710

Transport sector

60 800

Thermal

147 300

Total PES251 120

Other sectors

88 050Hydro

380 600

Coal

18 360Total FEC

207 830

Nuclear

94 900Oil

82 460

Coal

3 060

Other

11 600Gas

83 480Oil

94 560Other

66 630Gas

56 230Electricity and other53 980Source: (EDMC, 2014).

CRUDE OIL
Canada is currently the fifth largest oil producer in the world and production has been on the rise for the
past two decades. In 2012, Canada’s production of crude oil was 185.6 Mtoe, an increase of approximately
7.7% from 2011 (EDMC, 2014). Oil sands operations have been responsible for most of the growthexperienced in production in recent years, which have grown 192.0% since the year 2000 (CAPP, 2014b).
The recent growth in production has been driven by bitumen and upgraded synthetic crude oil produced
from the oil sands, with oil sands output surpassing conventional production for the first time in 2010
(NRCan, 2014c).
Canada’s crude oil production is geographically dispersed, but comes from three principle sources: theresources in the broader Western Sedimentary Basin, offshore Atlantic Canada, and the oil sands. The crude
oil production is within the following Western Canadian Sedimentary Basin provinces: Alberta (50.6%),
Saskatchewan (42.3%), Manitoba (4.4%), and British Columbia (1.7%) (CAPP, 2014c). The largest
production outside of the Western Canadian Sedimentary Basin occurs Atlantic offshore in the Jeanne d’Arc
Basin and Hibernia field representing 15.0% of production (CAPP, 2014c). Oil Sands, located in Athabasca
oil fields in Alberta, are a solid, extra-heavy type of crude oil composed of a mixture of natural bitumen,sand, water and clay. Production from oil sands in Canada has grown consistently since first production in
1967. It reached 1 802 000 barrels per day in 2012 when Canada’s conventional oil production was only 1
458 000 billion barrels per day, accounting for about 55.0% of Canada’s total oil production of 3 259 000
billion barrels per day in that year (CANSIM, 2014b).
For geographic and economic reasons, oil is exported from the west and Atlantic offshore, andimported in eastern and central regions. On balance however, Canada remains a large and growing oil
exporter experiencing 8.1% increase in exports between 2011 and 2012 (CANSIM, 2014). The Canadian oil
industry is heavily impacted by the USA, as Canada is the largest exporter of crude oil to the USA. The bulkof Canadian crude oil exports (128.2 Mtoe; 97.0%) are sent to the USA, accounting for one-third of the
USA imports (EDMC, 2014).

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GAS
Canada holds a relatively small share of the world’s proven natural reserves, yet it is the fifth largest producerof natural gas. In 2012, natural gas production reached 129.9 Mtoe, a decline of 1.9% from 2011, a trendthat has been ongoing since 2006 when gas production peaked (BP，2014). This continued decline is
attributable to numerous factors including: conventional reserve depletion, increasing capital and labourcosts, the residual impact of the economic downturn, and most dramatically by the USA’s rapid expansionof its shale gas resources. As a result of the American shale gas boom, net natural gas exports from Canada
have been declining. This trend continued in 2012 as Canada exported 73.5 Mtoe of gas to the USA, its only
gas market, compared to 76.8 Mtoe in 2011 (EMDC, 2014).
While conventional natural gas experiences reserve depletion, technological advances and rapid
investment in the Western Canadian Sedimentary Basin have renewed growth potential from shale gas, tightgas, and coal bed methane. Shale gas is emerging as the new low-cost source of natural gas in North America
resulting in greater investments and research to develop plays. In Canada, potential and producing shale gas
resources are found in British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, New
Brunswick, and Nova Scotia. Most of the current drilling and production activities are occurring in northeast
British Columbia in the Montney and Horn River shale basins (NRCan, 2012a).
COAL
Annual coal production has remained relatively steady since 1990. In 2012, Canada produced 33.5 Mtoe ofcoal (EDMC, 2014). Of total production, thermal coal attributed to 53.3% of production in comparison to46.7% attributed to metallurgical coal. There were 21 coal mines operating in Canada at the end of 2012
（NRCan, 2012b）. British Columbia and Alberta hosted 18 of these mines and were the two highest
producing provinces, together accounting for more than 85.0% of Canada’s coal production (NRCan,
2012b).
Coal exports are vital to the Canadian coal industry as 52.0% of production, approximately 20.8 Mtoeof coal, was exported in 2012 （EDMC，2014）. While Canada is a mid-size coal producer, it is asignificant exporter of metallurgical coal, which accounts for about 90.0% of Canada’s coal exports (EDMC,
2014). Canada exports coal to a variety of countries, however Asia is Canada’s primary export market,
accounting for 81.0% its exports （NRCan, 2012b）. Canada also exports coal to a number of European
countries, the USA, Mexico and Latin American countries.
URANIUM
Canada is among the three leading producers of uranium along with Kazakhstan and Australia, collectively
accounting for roughly 64.0% of total global output in 2012 (WNA, 2014a). With nearly 15.5% of global
uranium production, Canada’s output totalled nearly 24.7 Mtoe or 10 612 tonnes of U3O8 in 2012 (EDMC,
2014) (WNA, 2014a). Total production increased by 1.3% from 2011 (EDMC, 2014) (WNA, 2014a).
Canada’s uranium production is mostly located in Northern Saskatchewan with the MacArthur River mine
producing approximately 84.0% of Canada’s annual uranium production (WNA, 2014b).
NEW AND RENEWABLE
Canada has substantial renewable energy resources including moving water, wind, biomass, solar, geothermal,
and ocean energy. In 2012, non-fossil energy production consisting of renewable energy (not including
nuclear) accounted for 45.3 Mtoe, which is equal to about 18.3% of the economy’s total primary energy, an
increase of 1.7% from 2011 (IEA, 2014). Of the total renewable energy production share, the majority shareis hydro energy at 70.9% (32.7 Mtoe) (IEA, 2014). Non-hydro renewable energy sources are growing quickly
in Canada, but their share in Canada’s total primary energy supply remains small at 5.3% (NRCan, 2014d).

FINAL ENERGY CONSUMPTION
Compared to other industrialised countries, Canada is relatively energy intensive and largely fuelled bypetroleum, natural gas and hydroelectricity. On average, the Canadian population has high-energy demands,
both to meet their high living standards but also due to the prevalence of cold temperatures, the long
distances between major cities, and the energy-intensive industries driving the economy. A combination ofthese factors led to Canada’s total final energy consumption in 2012 to be 207.8 Mtoe, making Canada theworld’s seventh largest energy consumer and the fifth largest in the APEC region (EDMC, 2014).
Given Canada’s low population density, a final per capita energy consumption level in 2012 was nearly 6.0
tonnes of oil equivalent, the highest among the APEC economies. Canada’s per capita energy consumption

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was far ahead of other large developed APEC economies, namely the USA (4.6 toe), Australia (3.5 toe),
Russia (3.1 toe), the Republic of Korea (3.3 tonnes of oil equivalent) and Japan (2.4 toe) (EDMC, 2014).
Canadian energy consumption is driven by the transport sector (60.8 Mtoe; 29.3%) followed by theindustry sector (58.9 Mtoe; 28.3%) (EDMC, 2014). This follows a similar trend since 2009, when thetransport sector overtook industry consumption. Both sectors’ consumption have remained relatively stablesince 2010 in absolute terms. Excluding the share of the non-energy sector of final energy consumption(26.1 Mtoe; 12.6%), the remaining consumption can be accounted for by the following sectors: residential(31.7 Mtoe; 15.2%), commerce and public services (25.6 Mtoe; 12.3%) and agriculture (4.7 Mtoe; 2.3%)(EDMC, 2014).
Given Canada’s endowment of natural resources, naturally direct fossil fuels accounts for the largest
share of Canada’s total final energy consumption: petroleum products (94.6 Mtoe; 45.5%), gas (56.3 Mtoe;
27.1%) and coal (3.1 Mtoe; 1.5%) (EDMC, 2014). While oil and gas consumption has been increasing since
2000, coal consumption has declined at a yearly rate of 1.0% (EDMC, 2014). Coal consumption has been
declining due to various reasons, particularly environmental ones, resulting in government policies to limit
the use of coal. Following the direct fossil fuel energy consumption, electricity and renewable energy
consumption is the next largest source of energy consumption at 53.4 Mtoe, 25.7% (EDMC, 2014). This
sector experienced a decline of 2.6% from 2011, which may be partly explained by the reduction of coal inelectricity generation.
POWER GENERATION
Canada generated 616 terawatt-hours (TWh) of electricity in 2012, a decrease of approximately 0.3% fromthe previous year (618 TWh) (CANSIM, 2014). This decline is largely driven by the rapid decline in thermal
power generation at a rate of 6.8% from 2011, a trend on going since 2000 at yearly declines of 2.3% on
average. In 2012, hydropower plants were the largest contributor to Canada electricity at 61.2% of total
electricity generation in Canada, followed by thermal generation (coal, natural gas and petroleum) at 21.0%
and nuclear at 14.5% (NRCan, 2014). Comparatively, the share of renewables, other than hydro, of total
electricity generation is relatively small at 3.3%, but is growing steadily.
The share of renewable electricity production (including hydroelectricity) has been on the rise since2000 in Canada. New regulations limiting the use of coal, low natural gas prices, and the rapidly decreasing
cost of renewable energy is making the electricity sector increasingly ‘greener’ (NEB, 2014b). Canada is the
APEC regions second largest and the world's third largest hydroelectricity producer after China and Brazil,
accounting for 61.2% of Canada’s electricity production in 2012 (CANSIM, 2014a). Canada’s rich water
resources, particularly in eastern Canada, allow it to rely on hydropower. If nuclear power is added torenewable power generation, 79.0% of Canada’s electricity generation did not emit greenhouse gases in 2012(CANSIM, 2014a).
The electricity networks of Canada and the USA are highly integrated, resulting in the USA being a net
importer of electricity. In 2012, Canada exported 4.98 Mtoe of electricity to the USA while importing 0.9
Mtoe, making Canada APEC’s largest and the world’s third largest exporter of electricity after France andGermany (IEA, 2013) (EDMC, 2014). The bulk of electricity trade with the USA takes place between theprovinces of Québec, Ontario, Manitoba, and British Columbia (NEB, 2014b). The excess supply of hydroand nuclear resulted in Canadian net exports to reach a 10-year high. This explains the significant increasein net exports of electricity compared to 2011 when Canada exported 4.4 Mtoe of electricity (EDMC, 2014).
E N E RG Y I N T E N S I T Y A NA LY S I S

Canada’s industrial structure, vast geography, and cold climate make it a highly energy-intensive economy
in the APEC region. In 2012, Canada had the third largest primary supply energy intensity, behind Russia
and China at 177 tonnes of oil equivalent per million USD (EDMC, 2014). Canada’s energy intensity reflects
its role as a significant energy producer and exporter. Among other factors, energy intensity is influenced
also by efficiency improvements achieved from technology, which the Canadian Government is committed
to through the Office of Energy Efficiency (OEE) (NRCan, 2014e).
Canada has successfully reduced its energy intensity over the past few decades. Since 2011, primaryenergy intensity has fallen by 2.5%, whereas final energy demand intensity reduced by 0.9% (EDMC, 2014).
A significant share of the decline is driven by the industrial sector, which experienced a reduction of 11.5%
since 2005. Increasing energy efficiency and reducing energy intensity has been a policy goal for the25

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Government of Canada, mandated by the OEE, as a way to mitigate climate change and conserve energy,
further discussed in the energy efficiency section.
Table 3: Energy Intensity Analysis
Energy Intensity (tonnes of oil
equivalent per Million USD)

Energy2011

Change (%)

20122011 vs 2012

Primary Energy

181.6

177.1

-2.5

Final Energy Demand

148.0

146.6

-0.9

Industry

41.9

41.6

-0.7

Transportation

42.9

42.9

0.0

Others

63.2

62.1

-1.7

Source: (EDMC, 2014).
P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORKCanada has a federal government, ten provincial governments, and three territories, which all have a role inshaping the energy policy in Canada. Canada’s energy policy at all levels is market-based to determine supply,
demand, price, and trade. The fundamental principles that are important pillars to energy policy include: therespect for jurisdictional power granted under the Constitution Act of 1867, and targeted intervention in themarket process to achieve specific policy objectives (e.g., pipeline regulation) through regulation and othermeans (NEB, 2014b) (GOC, 2014a).
Under Sections 91 and 92 of the Constitution, provinces are the owners of ground resources andmineral rights within provincial boundaries, excluding the resources located in aboriginal lands, and frontier
lands (i.e. national parks, and international waters) (NEB, 2014b) (GOC, 2014b). The provincial
governments have the primary responsibility for shaping policies in their jurisdiction, making energy policy
variable from jurisdiction to jurisdiction. Unlike the provinces, the territories do not own the groundresources, but do share partial management responsibility. In addition to frontier lands, the federal
government is responsible for uranium resources/power, interprovincial/international trade and commerce,trans-boundary environmental impacts, interprovincial work (e.g. pipelines), and policies in the national
interest (economic development, health and safety, and energy security) (NEB, 2014b) (GOC, 2014c).
At the federal level, energy policy is layered and a number of government agencies are involved in thedevelopment and implementation of energy policy under the federal jurisdiction. The 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, 2014). 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 Canada, Fisheries and Oceans Canada, Aboriginal
Affairs and Northern Development Canada, and Department of Foreign Affairs, Trade and Development
Canada.
ELECTRICITY MARKETSThe structure of the Canadian electricity markets gives the provinces and territories jurisdiction overgeneration, transmission and distribution of electricity within their boundaries, including restructuringinitiatives and electricity prices. In turn, the federal government is responsible for electricity exports,
international and designated inter-provincial power lines, and nuclear safety, which is especially importantsince the economy-wide market is interconnected at many points with the United States to form a larger
grid (NEB, 2014c).
In most provinces, the electricity industry is highly integrated with the bulk of generation, transmission
and distribution services provided by one or two dominant utilities. While some of these utilities are privately
owned, many are Crown corporations owned by the provincial governments and, although independent
power producers also exist, they are rarely in direct competition with a Crown corporation. Exceptions

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include 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 both their levels and the mechanisms bywhich they are set. Provinces with an abundant supply of hydro-electricity generally have the lowest prices.
In most provinces, the regulator sets the prices according to a formula that determines the cost of generation
plus a reasonable rate of return. While 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) to address concerns about the reliability of the North American grid that had been prompted by the2003 blackout. In July 2006, the Federal Energy Regulatory Commission of the United States (FERC)
certified the North American Electric Reliability Corporation (NERC) as the ERO, authorising the NERC
to enforce reliability standards on the owners, operators and users of the bulk power system in both Canada
and the United States (FERC, 2014). The Canadian and United States governments also established 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 of mutual concern (FERC,
2014).

ENERGY MARKETOIL AND NATURAL GAS
Wellhead oil and natural gas prices in Canada have been fully deregulated since the conclusion of theWestern 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 to greater competition by permitting more exports, allowing users to buy directly from producers
and unbundling production and marketing from transportation services (NEB, 1996). Oil and gas pipeline
networks continue to be regulated as natural monopolies.
The participation of international oil companies, both private and state-owned in Canada’s oil and gas
sector has risen rapidly. These investments may be driven by a number of factors including economic andpolitical motivations, or to gain technological expertise that can be applied to conventional andunconventional resources elsewhere. Federally, the Investment Canada Act stipulates that any large
investment greater than CAD 325 million in Canada must be a net benefit to Canada (Industry Canada,2014).
COAL
Canada has abundant coal resources with the largest known reserves located in the western provinces, which
are also Canada’s principal producers. Coupled with the provincial level law and regulations, 35 federal acts
and regulations relate to the mining industry (CAC, 2012).
Among the many existing regulations, a new regulation will be adopted starting July 2015 that will placea performance standard to new coal-fired electricity. This will further reduce the coal consumption in Canada,
but not necessarily the production of coal. The Regulation, adopted under the Canadian Environmental
Protection Act 1999, is a performance standard that sets an emissions intensity level of Natural Gas
Combined Cycle (NGCC) technology, a high-efficiency type of natural gas generation, fixed at 420 tonnes
per GWh (GOC, 2014d). It also contains a caveat to encourage new technology for GHG reductions, whereunits that incorporate CCS technology can apply to receive a temporary exemption from the performancestandard until December 31, 2024 (GOC, 2014d).

ENERGY EFFICIENCYEnergy efficiency is the joint responsibility of the federal and provincial governments, but their role andresponsibilities vary and target different aspects of efficiency. Each province has ministries responsible foradministering energy and environment 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, 2014e). 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-efficient, cost-effective ones.
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The Energy Efficiency Act 1992 and related efficiency issues is administered at the federal level by the
NRCan through its Office of Energy Efficiency (OEE), with the vision to improve the utilisation of energy
by ‘leading Canadians to energy efficiency at home, at work and on the road’ (NRCan, 2014e). The OEE
delivers the ecoENERGY Efficiency program to improve energy efficiency for a cleaner environment andreduced greenhouse gas emissions (GHG), while saving Canadians money and making the most of Canada’s
natural resources (NRCan, 2014g). Between 2011 and 2016, the ecoENERGY Efficiency is investing 195
million CAD to improve energy efficiency in all end-use sectors, making the housing, building andequipment stock more energy-efficient, energy performance more visible, and industry and vehicle
operations more efficient. The ecoENERGY efficiency program addresses the following components ofefficiency:ecoENERGY Efficiency for Buildings provides information and benchmarking tools to improvebuilding 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 through the ENERGYSTAR® initiative in Canada;

ecoENERGY Efficiency for Industry aids the adoption of an energy management standard andaccelerates energy-saving investments and the exchange of best practices information within Canada's
industrial sector; andecoENERGY Efficiency for Vehicles provides both individual Canadians and Canada's
commercial/institutional fleet sector with decision-making tools for buying and operating their vehicles
to reduce fuel consumption. It also promotes vehicle efficiency by introducing improved vehicle fuelconsumption labels and a light-duty tire information system (NRCan, 2014g).

In addition to the 195 million CAD invested into the efficiency program, the Government is investingin alternative fuels and biofuels in order to diversify its energy sources. From 2011 to 2016 the federal
government has committed 3 million CAD to support alternative fuels used in the transport sector (NRCan,
2014g). Federally, there is CAD 1.5 billion of funding available between 2008 and 2017 to support the
production of renewable alternatives to gasoline and diesel for the development of a competitive domestic
industry (NRCan, 2014g).

RENEWABLE ENERGY
Given its large landmass and diversified geography, Canada has an abundance of renewable resources thatcan be used to produce energy. Canada is world leader in the production and use of renewable energy, with
18.3% of its primary energy supply from renewable energy resources (EDMC, 2014). At a federal level,
Natural Resources Canada’s research centre, CanmetENERGY, is the leader in clean energy research anddevelopment. The federal government supports renewable energy through funding it provides toCanmetEnergy, which develops research, development and demonstration activities that would ultimately
accelerate renewable technology towards commercialisation and self-sustainability (NRCan, 2014f).
Through the research centre, the government funds and drives hydro energy, wind energy, solar energy,
bioenergy, geothermal energy and tidal energy.
Moving water is the most important source of renewable energy in Canada, accounting for 61.2% of
Canada’s electricity generation in 2012(NRCan, 2014d). In 2013, Canada had 533 hydroelectric stations, withmore than 75.7 thousand megawatts of installed capacity (CANSIM, 2014a). Surrounded by oceans, Canada
has access to a significant energy source that can be used to produce energy from ocean waves and tides.
Canada has one of the few tidal power plants in the world, located in Nova Scotia generating 20 megawattsof electricity and has two wave and tidal current technology demonstration projects in British Columbia andNova Scotia. In British Columbia, the wave energy device has capacity of 100 kilowatts. The 4-megawatt
project in Nova Scotia will be the first deployment of commercial-scale tidal turbines in Canada. (NRCan,
2014d). Wind is the second most important renewable energy source in Canada, accounting for 1.8% ofelectricity generation (NRCan, 2014d). Canada has vast areas with large potential for wind resources making
expansion of wind-generated power very economical. Installed wind power capacity has expanded rapidly
in the recent years and is forecasted to grow at a rapid pace given the government initiatives in place
supporting its growth (NRCan, 2014d). In 2013, Canada had almost 4 400 wind turbines in operation in 187
wind farms, with a total installed capacity of 7 801MW (CanWEA, 2015). Solar energy has also experienced
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continuous growth both in thermal and photovoltaic power. Thermal power has grown at an annual averagerate of 9.5% since 2000, reaching a capacity of 819MW. Solar photovoltaic power experienced an
exponential growth during the 2008-2011 period with an annual growth rate of 147.3%, reaching installedcapacity of 1 210MW (IEA, 2014).
With its large landmass filled with active forests and agricultural industries, Canada has access to large
and diversified biomass resource for energy production. In 2013, bioenergy is the second most important
form of renewable energy with biofuels and renewable waste representing 4.9% of Canada’s total primaryenergy (NRCan, 2014d). Canada has 61 bioenergy power plants with a total installed capacity of 1 580MW.
Most of this capacity is built around the use of wood biomass, spent pulping liquor, and landfill gas. Biofuelsis also a growing form of bioenergy in Canada, accounting for 2.0% of world ethanol production and 1.0%
of world biodiesel production (NRCan, 2014d). The federal government alongside the provinces has
introduced regulations on renewable content that will further increase future production and use of biofuels.
The Government of Canada has developed a comprehensive renewable fuels strategy consisting of four
elements:Renewable Fuels Regulation establishing a minimum renewable fuel content of 5.0% renewable content
based on gasoline pool, and 2.0% renewable content in diesel and heating oil;A commitment of CAD 200 million over four years to the ecoAgriculture Biofuel Capital Imitative tosupport farmer participation in the industry;

A commitment of CAD 1.5 billion over 9 years to the ecoENRGY for Biofuels program to support
domestic production; andCommitment of CAD 500 million to the NextGen BioFuels FundTM to support next-generation
technologies from non-conventional feedstock (NRCan, 2014d).

Geothermal power has not experienced similar momentum as solar, wind and biomass. As the highest
temperature geothermal resources are located in British Columbia, Northwest Territories, Yukon, andAlberta; there are a number of heat and power generation projects being considered with the demonstration
projects under way in Western Canada, including the South Meager project in British Columbia, the mostadvanced geothermal power plant in Canada. In 2010, there were over 95 000 ground-source heat pumps,
but no large-scale geothermal stations (NRCan, 2014d). CanmetENERGY has been financially supporting
the demonstration projects in British Columbia, Northwest Territories, Yukon, and Alberta. Thesedemonstration projects are not commercially viable.

NUCLEAR POWER
Nuclear energy is an important component of Canada’s dynamic energy mix. In 2012 nuclear energy
accounted for 14.5% (89.5 TWh) of electricity generation in Canada (EDMC, 2014), with nearly 50.0%
located in the Province of Ontario. Canadian nuclear power generation is concentrated in the provinces of
Ontario (houses 20 reactors) and New Brunswick (houses one reactor) (NRCan, 2014j). In 2012, Gentilly 2,
the Province of Québec’s only nuclear plant, was decommissioned following Hydro-Québec’s (theprovincial energy utility provider) decision not to proceed with refurbishment due to the high cost (Canadian
Nuclear Association, 2014).
Unlike other energy sources, nuclear energy falls within federal jurisdiction. Within its bounds, thefederal government is responsible for all regulation of nuclear materials and activities along with supporting
research and development (R&D). Concerned with nuclear activities impact on health, safety, security andthe environment, the federal government has put in place a comprehensive nuclear legislation framework,
which is comprised of the Nuclear Safety and Control Act 1997, the Nuclear Energy Act 1985, the Nuclear
Fuel Waste Act 2002 and the Nuclear Liability Act 1985 (NRCan, 2014j). While these regulations provide
the framework for how nuclear energy will develop in Canada, it is administered through a layeredorganisational approach. The organisations that play a role in the administration of the legislation include:

Natural Resources Canada (including Energy and Nuclear Energy division): Responsible fordeveloping ‘policies and programs which enhance the economic and environmental well-being of
Canadians. The Department provides advice on energy policy, as well as, institutional, legislative, andfinancial frameworks for the nuclear industry’;Canadian Nuclear Safety Commission: An independent agency of the Government of Canada
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’;29

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C AN AD AAtomic Energy of Canada Limited: This Crown Corporation is the premier nuclear and scienceorganisation mandated to ‘develop peaceful applications of nuclear energy. It has two distinct roles,
namely a public policy role and a commercial role’; and

The Department of Foreign Affairs, Trade and Development Canada, Health Canada,
Transport Canada, and Industry Canada (including National Research Council): These federal
departments are not directly involved in nuclear legislation or policy development, but do administercertain aspects of nuclear energy including: security, health, safety, research and trade (NRCan, 2014j).

While the federal government is the central body regulating nuclear energy, the decision to invest in
nuclear power plants for electricity generation rests with the provinces (in concert with relevant provincial
energy utilities) (NRCan, 2014j). Given the current context and each provincial electricity outlook, no new
nuclear capacity is projected but existing operational plants will undergo refurbishments.
The Canadian Government is committed to address climate change in a meaningful manner while
ensuring the Canadian economy remains competitive (GOC, 2014f). Climate change is a complex issue
making Canada’s approach multifaceted and layered at the provincial, federal and international levels. All
these levels work in collaboration to ensure policies, regulations and initiatives are aligned and work inconcert.
PROVINCIAL
Provinces/territories hold the jurisdictional authority to regulate natural resources, therefore play an integralrole in climate policies as energy production and consumption contribute significantly to Canada’s
greenhouse gases (GHG). Each province has an extensive list of policies, regulations and initiatives tomanage climate change and reduce GHG emissions. The major regulations and programs that focus on
reducing direct GHG’s include:

Alberta: Passed the Specified Gas Emitters Regulation 2007, which requires facilities emitting morethan 100 000 tonnes of greenhouse gas to reduce emissions by 12.0%. Among other options, companies
may choose to pay CAD 15 per tonne for every ton over their target if they do not physically reduce
their emission levels (Province of Alberta, 2014).



British Colombia: A revenue neutral carbon tax applied to the purchase or use of fuels within theprovince at a current rate of CAD 30 per tonnes of CO 2 equivalent (British Columbia Ministry of
Finance, 2014).



Nova Scotia: The Greenhouse Gas Emissions Regulations 2009 places a cap on electricity sector
emissions from all facilities with targets established to 2030 (Nova Scotia, 2013).



Ontario: As of April 2014 the province no longer uses coal to generate electricity and the Government
has proposed regulation to ensure no future coal-burning generation on the electricity grid (Ontario,2014). The Government also introduced the Green Energy and Green Economy Act 2009, which
implemented a feed-in-tariff that promotes and facilitates the connection of renewable generating
facilities (Ontario Power Authority, 2014).

Quebec: Established a GHG emission cap-and-trade system along with placing a small levy on fueland fossil fuels (Quebec, 2012).

FEDERAL
Energy production and consumption contribute significantly to Canada’s greenhouse gas (GHG) and air
pollutant emissions. Canadian government policies are aimed 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 through investments in green infrastructure, energy efficiency, clean energy technologies andthe production of cleaner energy (Environment Canada, 2013a).
The Federal Government is regulating greenhouse gas (GHG) emissions through a sector-by-sector
approach, with regulations already in place in two of the largest emission sectors: electricity andtransportation.


30Electricity Sector: Canadian government announced in 2012 stricter regulations concerning coalbased electricity generation, with new standards applicable for new and old power plants that havereached the end of their economic life. The standards, which will be in force by July 2015, are expectedAPEC E N E RG Y O VE R VI E W 2014

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to result in a cumulative reduction in GHG emissions of about 214 megatonnes in the first 21 years(Environment, 2013a).
Transportation Sector: proposed final regulation in the transportation sector will ensure that 2025
passenger vehicles and light trucks will emit about 50.0% less GHGs than 2008 models and emissions
from 2018 model-year heavy duty vehicles will be reduced by up to 23.0% (Environment, 2013a). The
transportation regulations were developed to align with U.S. Environmental Protection Agency (EPA)
standards in order to collaboratively work towards a common North American standard (Environment,2013a).

Despite the provinces having jurisdiction over natural resources, when it comes to climate change, thefederal government has constitutional authority to regulate emissions under Section 91 of the constitution.
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(Environment, 2013a). The federal government has been in negotiations with industry and all provincial
governments since 2012.
INTERNATIONAL
Climate action taken by the provinces and federal government of Canada is partially driven by thecommitments made at the international arena. Canada is a signatory to the United Nations Framework
Convention on Climate Change (UNFCCC). In 2009, Canada signed onto the Copenhagen Accord andcommitted to reduce GHG emissions to 17.0% below 2005 levels by 2020 (Environment Canada, 2013b).
Canada has continued its engagement in the UNFCCC negotiations to support the establishment of a fairand comprehensive global climate change regime since the end of the Doha round of negotiations under
the UNFCCC in December 2012. This was endorsed again through the Cancun Agreement. Along with the
UNFCCC, Canada commenced the 2009 Clean Energy Dialogue with the USA with the intention ofdeveloping a possible future cap-and-trade system, and development and deployment of clean energy
technologies in a regionally focused effort.

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 2000’s, mounting concerns over the decreasing conventional supplies of domestic natural gas
gave way to uncertain forecasts, ultimately resulting in an investment boom to build LNG import facilities(NRCan, 2014h). One such investment included the Canaport LNG terminal in Saint John, New Brunswick,
which began gas-importing operations in 2009, and has remained Canada’s only operating LNG facility(regasification) since.
However, despite these early concerns, natural gas resource and production in Canada and the USA
surged given the technological advancements made in unconventional natural gas production. Greater
supply from shale gas and tight gas formations outpaced the growth in natural gas demand, which ultimately
paved a path for the USA to become increasingly self-sufficient with respect to natural gas. Given thissignificant shift in the USA, Canadian exports to the USA may experience decline.
Canada is looking to diversify its market by exporting LNG to overseas markets and creating LNG
export terminals to do so. The West coast of Canada has experienced an overwhelming number of proposed
LNG facilities to address growing demands of the Asia Pacific region, but these projects involve long leadtimes to obtain approvals, establish markets and construct facilities (NEB, 2014b). For Canada, along withmany other export countries, the window of opportunity to capitalise on its LNG export potential is quite
narrow given the strong competition around the world that aims to profit from these investments (NEB,
2014b).
Currently, Canada does not have any operational export facilities. However, as of November 2014,seventeen proposed LNG export facilities have entered the regulatory review process. Most of these projects
are located in the province of British Columbia near Kitimat and Prince Rupert, and most will require new
infrastructure to bring both gas and electricity to the facilities (NEB, 2014b). None of these projects haveentered the construction phase. Final investment decisions will be influenced by factors including

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construction costs, pricing arrangements and competition for other existing or potential LNG exporters(NEB, 2014b).
Once in operation, the LNG terminal generally falls under provincial regulations. However, LNG
terminal proposals require numerous federal and provincial environmental assessments and permits. Amongother federal requirements, a permit from the National Energy Board (NEB) is required to export LNG
from Canada. The NEB ensures that the proposed volume of gas exports does not exceed the surplus
needed to meet estimated domestic demand (NRCan, 2014h). As of November 2014, the NEB has issued
nine long-term export licenses to the proposed Canadian facilities. No application has yet been rejected,
thirteen remain under review (of which five are for Steelhead LNG and three for Cedar LNG) and one has
been deemed incomplete (Goldboro LNG).

PIPELINE DEVELOPMENTS
The success of Canada’s landlocked oil economy, based in Alberta, Saskatchewan, and Manitoba, relies on
its ability to reach markets. While the industry is experiencing growth in production from oil sands and newlight oil prospects, its location is less than ideal. The distance is too far from the major refining hub in the
USA Gulf Coast and ocean ports that would provide access to the expanding overseas market. The
Government and industry are working together to find options to access markets, new LNG terminals on
Canada’s west coast, and numerous pipeline proposals are in the regulatory process or have recently received
approval in addition to the frequently discussed TransCanada Keystone XL.

ABORIGINAL ENGAGEMENT
The participation of Aboriginal people is a critical factor in Canada’s ability to capture the benefits of energy
resource development. Aboriginal peoples are especially well positioned as many of the existing or proposedenergy resources and infrastructure projects are located near their communities. In Canada’s resources
development sector, Aboriginal consultation has been a strong component of energy projects and willcontinue to be in the future.
In recent years, the Government of Canada has adopted initiatives to enhance the engagement of
Aboriginal communities and to ensure that resources development are done in partnership with Aboriginal
peoples, in a way that protects the local environment, and is respectful of Aboriginal and treaty rights. As
part of this policy, Aboriginal consultations are integrated into assessment and regulatory processes andconsultation protocols or agreements with Aboriginal groups are established for project reviews. In 2012,
the Government of Canada introduced Responsible Resource Development. In addition to its objective tocreate jobs, growth and long-term prosperity, the plan highlights the aim to establish open consultation with
Aboriginal partners, strong partnerships throughout natural resource development, and to provide
considerable employment and profit opportunities for the Aboriginal communities (GOC, 2014g)
As many of the proposed energy infrastructure projects on the West Coast of Canada pass through ornear Aboriginal communities, the federal government works closely with the Government of British
Columbia (BC), and BC First Nations to establish a tripartite forum that will provide an opportunity to share
information identify common interests and align efforts on issues relating to the development of energy
infrastructure and natural resources. The Government has created the Major Projects Management OfficeWest (MPMO) that serves as a single window for the Government of Canada to coordinate activities onenergy infrastructure development with BC First Nations and industry in BC and Alberta.

ARCTIC AND OFFSHORE ENERGY
Since the 1950s, exploration and study by the oil and gas industry, and the Canadian Geological Survey has
indicated strong potential for petroleum discoveries in the north. However, the cost of developing the fields
and getting to the market were quite large; given the low oil prices of the previous decades, andtransportation bottlenecks made discoveries uneconomical to bring to market (NRCan, 2007). However,there is a renewed interest in vast oil and gas potential provided high oil and gas prices, and the promise of
new pipeline systems. The potential of the offshore continental shelf is considered quite high with 19
significant discover licenses issued for the Arctic islands and 60 licenses in the Mackenzie Delta/Beaufort
Sea region (NEB, 2014b). Discoveries in these regions exceed one billion barrels of oil and ten trillion cubicfeet 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) and the Canada Petroleum Resources
Act (CPRA) and National Energy Board Act whereas Canada’s Atlantic offshore oil and gas industry is

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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 are an estimated 9.8 billion barrelsof recoverable resources (NRCan, 2013b).
In order to enhance responsible resource development, the Canadian Minister of Natural Resources
introduced legislation in early 2014 that would bring changes to Canada’s offshore oil and gas regime. The
Energy Safety and Security Act contains amendments to the Canada Oil and Gas Operations Act 1985 andthe Canada Petroleum Resources Act 1985, along with the federal Accord Acts for offshore Nova Scotia
and Newfoundland and Labrador (NRCan, 2014i). The proposed changes focus on four main areas —prevention, response, accountability and transparency — and they help to further strengthen safety andsecurity to prevent incidents and ensure swift response in the unlikely event of a spill.
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IEA (International Energy Agency) (2014) IEA Statistics: Renewables Information–––– (2013a). Key World EnergyStatistics.
http://www.iea.org/publications/freepublications/publication/name-31287-en.html.
–––– (2013b) National Survey Report of PV Power Applications in Canada. www.ieapvps.org/index.php?id=93&eID=dam_frontend_push&docID=2312
IVEY (IVEY Business School - Western University ) (2014). Strong aboriginal relations is key to future energysector development. www.ivey.uwo.ca/news/news-ivey/2014/10/guy-holburn-strong-aboriginalrelations-is-key-to-future-energy-sector-development/．
KinderMorgan (2014). Trans Mountain Pipeline Expansion Project．
www.kindermorgan.com/business/canada/tmx_expansion.cfm/．
NEB (National Energy Board) (2014e). Application for Cedar 1 LNG Export LTD For a License to Export
Liquefied Natural Gas. https://docs.neb-one.gc.ca/lleng/llisapi.dll/fetch/2000/90466/94153/552726/2485970/2486960/2485956/Application_by_STE
ELHEAD_LNG_(C)_INC._-_A3Y9S1.pdf?nodeid=2486729&vernum=-2/．
–––– (2014b). Canada Energy Dynamics. www.nebone.gc.ca/nrg/ntgrtd/mrkt/dnmc/2013/2013nrgdnmc-eng.pdf．
–––– (2014a). Canadian Energy Overview 2013 - Energy Briefing Note. www.nebone.gc.ca/nrg/ntgrtd/mrkt/vrvw/2013/index-eng.html．
–––– (2014d). LNG Export Licence Applications. www.nebone.gc.ca/pplctnflng/mjrpp/lngxprtlcnc/index-eng.html.
–––– (2014c). NEB Electricity.www.neb-one.gc.ca/bts/ctrg/gnnb/lctrct/index-eng.html．
–––– (2014f). Steelhead LNG (C) Inc. Application for Licence to Export Liquefied Natural Gas．
https://docs.neb-one.gc.ca/lleng/llisapi.dll/fetch/2000/90466/94153/552726/2485970/2486960/2485956/Application_by_STE
ELHEAD_LNG_(C)_INC._-_A3Y9S1.pdf?nodeid=2486729&vernum=-2/．
–––– (2013). Canada's Energy Future 2013: Energy Supply and Demand Projections to 2035． www.nebone.gc.ca/nrg/ntgrtd/ftr/2013/2013nrgftr-eng.pdf．
–––– (1996). Natural Gas Market Assesment: Ten years after Deregulation.
www.arcticgas.gov/sites/default/files/documents/1996-neb-10-years-after-deregulation.pdf.
NRCan (National Resources Canada) (2014a). What is Coal? http://www.nrcan.gc.ca/node/14377–––– (2014d). About Renewable Energy. www.nrcan.gc.ca/energy/renewable-electricity/7295/．
–––– (2014b). About Uranium. www.nrcan.gc.ca/energy/uranium-nuclear/7695/．

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APEC E N E RG Y O VE R VI E W 2014

C AN AD A–––– (2014h). Canadian LNG Projects. www.nrcan.gc.ca/energy/natural-gas/5683/–––– (2014f). CanmetENERGY. www.nrcan.gc.ca/energy/offices-labs/canmet/5715/．
–––– (2014g). ecoENERGY Efficiency and Alternative Transportation Fuels. www.nrcan.gc.ca/energy/officeslabs/office-energy-efficiency/5691/．
–––– (2014i). Energy Safety and Security Act- Offshore.www.nrcan.gc.ca/mediaroom/backgrounder/2014/14660/．
–––– (2014j). Nuclear Energy. www.nrcan.gc.ca/energy/uranium-nuclear/7711.
–––– (2014e). Office Energy Efficiency.www.nrcan.gc.ca/energy/offices-labs/office-energy-efficiency/．
–––– (2014c). Oil Supply and Production.www.nrcan.gc.ca/energy/crude-petroleum/4549/．
–––– (2013). Additional Statistics on Energy, 04 November 2013.
http://www.nrcan.gc.ca/publications/statistics-facts/1239/．
–––– (2013b). Offshore British Columbia. http://www.nrcan.gc.ca/energy/offshore-oil-gas/5835–––– (2012a). Shale gas.www.nrcan.gc.ca/energy/natural-gas/5687/．
–––– (2012b). Commodity Review. Coal – Other Information. www.nrcan.gc.ca/miningmaterials/markets/commodity-reviews/2012/14377．
–––– (2007). Arctic Oil and Gas． www.gac.ca/PopularGeoscience/factsheets/ArcticOilandGas_e.pdf．
Province of Alberta (2014) Alberta Climate Change and Emissions Management Act: Specified Gas Emitters
Regulation. www.qp.alberta.ca/documents/Regs/2007_139.pdf．
Province of Nova Scotia (2013). Nova Scotia Greenhouse Gas Emission Regulations．
www.novascotia.ca/just/regulations/regs/envgreenhouse.htm．
Pronvince of Ontario (2014). Ontario Ontario's Climate Change Update 2014.
https://dr6j45jk9xcmk.cloudfront.net/documents/3618/climate-change-report-2014.pdf.
Province of Quebec ( 2012a). Quebec in Action Green By 2020: 2013-2020 Climate Change Action Plan.
www.mddelcc.gouv.qc.ca/changements/plan_action/pacc2020-en.pdf．
Ontario Power Authority (2014). OPA FIT Program: Introduction. http://fit.powerauthority.on.ca/fitprogram/introduction/．
Supreme Court of Canada (2014). SC. Tsilhqot’in Nation v. British Columbia, 2014 SCC 44. http://scccsc.lexum.com/scc-csc/scc-csc/en/item/14246/index.do．
Statistics Canada (2014). Table 051-0001: Estimates of population, by age group and sex for July 1, Canada, provinces
and territories, 26 September 2014. http://www.statcan.gc.ca/tables-tableaux/sumsom/l01/cst01/demo10a-eng.htm/．
TransCanada (2014a). About the Project.http://keystone-xl.com/about/the-keystone-xl-oil-pipelineproject/．
–––– (2014b).Energy East Pipeline.www.energyeastpipeline.com/．
WNA. (World Nuclear Association) (2014a). World Uranium Mining Production, October 2014．
www.world-nuclear.org/info/Nuclear-Fuel-Cycle/Mining-of-Uranium/World-Uranium-MiningProduction/．
–––– (2014b). Uranium in Canada.www.world-nuclear.org/info/Country-Profiles/Countries-A-F/Canada-Uranium/．
USEFUL LINKS

Atomic Energy of Canada Ltd—www.aecl.ca
Canadá Gazette—www.gazette.gc.ca

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APEC E N E RG Y O VE R VI E W 2014

Canadian Association of Petroleum Producers—www.capp.ca
Canadian Nuclear Association—www.cna.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

36

C AN AD AAPEC E N E RG Y O VE R VI E W 2014

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 kilometres with an average of 175 kilometres wide
and a land area of 756 102 square kilometres. Administratively, Chile is divided into 15 regions headed byregional governors (Intendente) appointed by the President and divided into 54 provinces. In 2012 theeconomy’s population was above 17 million with an 87.0% of the population living in urban areas (INE,2013). Given the size and shape of its territory and its number of inhabitants, Chile’s general population
density is almost 23 inhabitants per square kilometre in 2012 on average, although in such metropolitan
areas as Santiago and Valparaíso it is much higher, having respectively as much as 455 and 110 people persquare kilometre (INE, 2013).
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 GDP per capita
from USD 8 728 in 1990 to USD 19 973 in 2012 (PPP in USD). It is one of the fastest growing economies
in South America. In 2012, Chile’s GDP reached USD 348 billion (USD constant 2010 at PPP), which
represents an increase of 5.8% from 2011 levels, led by retail sales (8.4%) and construction (8.1%). In termsof Chile’s GDP composition, 96.0% is divided between services (61.0%) and industry (35.0%), where mining(15.0%) is considered a service. Almost 98.0% of the total exports were under trade agreements with 60
economies with which include: the European Union, Mercosur (a regional trade group comprised ofArgentina, Brazil, Paraguay, Uruguay and Venezuela), India, China, Japan, Korea, Mexico and the UnitedStates. Copper is a main factor in the Chilean economy accounted alone for nearly 92.0% of the mining
exports and 41.0% of total exports (BCL, 2012). The evolution of foreign direct investment (FDI) is closely
related to the evolution of mining investment, in that sense, FDI increased in 32.0% to USD 30 billion
during 2012 due the higher investment flows in mining (UNCTAD, 2013).
Despite the diverse geography and abundant natural resources, the territory is very limited in fossil fuelresources, making Chile a net energy importer for which one of its mainstay priorities revolves around a
steady energy supply.
Table 1: Key data and economic profile, 2012
Key dataa

Energy reservesb

Area (sq. km)

756 102

Oil (million cubic metres)

1.9

Population (million)

17.5

Gas (million cubic metres)

9.0

GDP (USD (2010) billion at PPP)

348.8

Coal (million tonnes)

19 973

Uranium (kilotonnes U)c

GDP (USD (2010) per capita at PPP)

171.0
3.7

Source: a. (EDMC, 2014); b. (MEN, EIA, 2014); c. (CChEN, 2013).
E N E RG Y S U P P LY A N D D E M A N D

PRIMARY ENERGY SUPPLY
According to EDMC (2014), Chile’s total primary energy supply (TPES) has increased in 10.7% from 2011
to 2012 to reach 37 213 ktoe. Approximately 42.0% of this energy volume was supplied in the form of crude
oil and its by-products, 16.5% as coal, 11.5% as natural gas and the remaining 23.4% as other sources,
particularly biomass and hydropower. Given its limited endowment of hydrocarbons Chile is a net importerof primary energy, especially of fossil fuels. Its net primary energy imports represents 70.0% of the TPES,
having reduced 1.5% from 2011 to reach nearly 26 000 ktoe in 2012. Despite its small contribution to TPES,
Chile’s energy output from non-fossil sources have increased in 43.0% from 2011 to 2012, being explainedby the important increase in biomass used by auto-producers of energy.

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In regards to fossil energy resources, Chile’s proved crude oil reserves amounted to 15 million barrels
by the end of 2012, with most of it located in the southern Magallanes region. In the light of the low domestic
production, nearly all of Chile’s crude oil supply of 15 609 ktoe in 2012 came from imports that also included
by-products such as diesel, gasoline and LPG (EDMC, 2014). As for natural gas, Chile’s demand was 4 286
ktoe, met by three-quarters of imports and the rest by domestic production in 2012 (EDMC, 2014). Chile’s
domestic coal production is mainly located in the region of Magallanes with a total recoverable coal reserves
estimated in 170 million tonnes, but as of 2012, domestic production accounted for less than 4.0% of thetotal supply (EDMC, 2014).
Owing to Chile’s abundance of renewable energy resources, in particular of water resources, theircontribution to TPES is high, totalling 11 198 ktoe and representing near 85.0% of the economy’s total
domestic energy production in 2012 (EDMC, 2014). Chile’s primary supply of non-fossil energy in 2012
was mainly made up of biomass and hydropower.
In 2013, Chile’s total net installed electricity capacity was 17 741 MW, representing an increase of 476
MW (2.8%) from 2012, with thermal power plants representing 65.0% of the total capacity (self-suppliers
included), and the remainder contributed by mainly hydro power with a 33.0%. It is important to mention
about the drastic change in the participation of Hydro and Thermal sources since 2006 when hydro was
54.0% and thermal 46.0% of the total electricity capacity.
The National Electric System (SEN in Spanish) in Chile is organised around the following systems 1:
Northern Grid (SING): 3 760 MW, 99.0% thermal (51.0% coal and 38.0% natural gas);Central Interconnected System (SIC): 13 826 (MW), 54.0% thermal (33.0% coal and 18.0% natural gas)and 43.0% hydro;

Aysen Grid: 50 MW, 51.0% thermal (100% diesel) and 45.0% hydro;

Magallanes Grid: 99 MW, 100.0% thermal (85.0% natural gas and 15.0% diesel); and

Los Lagos Grid: 6.2 MW, 88.0% thermal (100.0% diesel) and 12.0% hydro.

FINAL ENERGY CONSUMPTION
During 2012, Chile’s total final energy consumption was 24 954 ktoe, representing almost the same valuesof the previous year.
Energy demand was fairly balanced between industry (39.3%), residential, commercial and public—
jointly grouped as ‘other’—(29.6%) and transport (29.8%) sectors.
By energy source, more than half of Chile’s final energy demand was met by petroleum products(50.4%), primarily consumed in the transport and industrial sectors, followed by electricity and other sources(43.0%), natural gas (5.8%) and a marginal share of coal. Oil, gas and coal consumptions decreased 1.2%,
27.0% and 41.0% respectively, while electricity consumption rose 7.4% (EDMC, 2014).
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

13 053 Industry sector

9 069 Total

64 897

Net imports and other24 957 Transport sector

7 461

Thermal44 330Total PES

37 213 Other sectors

8 423

Hydro

20 158Coal

6 094 Total FEC

24 954

Nuclear-Oil

15 609

Coal

192

Others

409

Gas

4 286

Oil

12 589

Hydro

1 734

Gas

1 441

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APEC E N E RG Y O VE R VI E W 2014

Others

9 490

CHILE

Electricity and other10 732

Source: (EDMC, 2014).

ENERGY INTENSITY ANALYSIS
Energy intensity has been declining since 2005 showing a better and efficient use of energy sources.
Chile’s primary energy supply in 2012 was 106.7 tonnes of oil equivalent per million USD, up 5.0% from
101.5 in 2011. The energy intensity for the final energy demand improved, declining by 5.0% to 71.5
toe/million USD in 2012 from 75.7 tonnes of oil equivalent per million USD in 2011. Broken down by
sector the transport and others sectors declined by 3.0%, while the energy intensity of the industry sector
declined by 10.0%.
Table 3: Energy Intensity analysis
Energy Intensity (tonnes of oil
equivalent per million USD)

Energy2011

2012

Change (%)
2011 vs 2012

Primary Energy

101.5

106.7

5.0

Final Energy Demand

75.7

71.5

-5.0

Industry

28.8

26.0

-10.0

Transportation

22.0

21.4

-3.0

Others

24.9

24.2

-3.0

Source: (EDMC, 2014).
E N E RG Y P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORK
Chile has embarked on the development of an economy based on international trade and the rules of thefree market since the 1980s, when the economy started to grow significantly. From that time to 2012, 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 supportive business environment for foreign investments withstreamlined administrative processes and simplified tax payments. Chile is ranked 34 among 183 economies
in the report Doing Business 2014.
Chile is an open market economy, highly integrated to world. Its participation in free trade
agreements increase its options to reach a sustainable development based on further trade opportunities,
looking to reduce its dependency of mineral exports and trade products with a higher value added.
In line with these foundations, 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, the regulatory
framework and strategies to be applied, and the development of public policy instruments. In 2014, theChilean government through its Ministry of Energy (MEN in Spanish) released the national Energy Agenda
to guide the economy’s long-term energy policy.
The goals and purposes of the Energy Agenda can be summarised as follows:

Reduce the electricity marginal cost by 30.0% in the Central Interconnected Grid (SIC);



Reduce the prices of the electricity supply bids by 25.0%;

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APEC E N E RG Y O VE R VI E W 2014

CHILE



Lift existing barriers for Non-Conventional Renewable Energies to increase the participation ofrenewal energies up to 45.0% of the new electric generation capacity by 2025;



Foster the efficient use of energy as an energy resource, establishing a 20.0% savings goal by the year
2025, considering the expected energy consumption growth in the economy as of that 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 in the energy challenges of the member
economy government; andDevelop by 2015 a long-term Energy Policy that will be validated by the Chilean citizens.
FISCAL REGIME AND ENERGY PRICES

Since 2001, Chile’s fiscal policy is guided by the rule of the cyclically adjusted balance, also known as the
Structural Balance Rule. This policy looks to keep medium term equilibrium in the fiscal accounts, adjusting
the government 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.
In Chile, prices for petroleum-based fuels are set by international market conditions and across allstages of the value chain, including retail sales at service stations. However, specific excise taxes (IEC in
Spanish) are charged on transport fuels (gasoline, diesel, liquid petroleum gas (LPG) and compressed naturalgas (CNG)). In February 2011, the government introduced the Consumers’ Protection System for Volatility
in International Oil Prices (SIPCO) to reduce uncertainty about domestic prices for oil products. This system
was replaced on July 2014 by a new mechanism called the Fuel Price's 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 in no more than five Chilean Pesos per liter per week. Finally, the SIPCO
converts the oil international price in local currency to assess the value of the final price protection to theconsumer.
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 systemand consumer risk is minimised.

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 regulator, policy-maker and technical consultant in such efforts to identify the requirements to meet the
projected demand growth. The Ministry of Energy is the main regulator of the electricity industry in Chile,which 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).
The Energy Agenda of May 2014 presents seven fundamental issues to reach a reliable, sustainable
and inclusive energy development at reasonable prices:

A new role for the State;Reduction of energy prices, with higher competition, efficiency and diversification of the energy
market;

Development of own energy resources;

Connectivity for energy development;An efficient sector managing consumption;Boost for investment in energy infrastructure; andCitizen involvement and territorial regulation.

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APEC E N E RG Y O VE R VI E W 2014

CHILE

ENERGY EFFICIENCYEnergy efficiency is among Chile’s priorities as it works toward achieving its key goal of enhancing its energy
security. As per the ENE issued in 2012, the government’s approach in recent years has been focused onincreasing the electricity generation from nonconventional renewable energy sources, with efforts also
encompassing the stabilisation of demand growth through energy efficiency efforts.
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 marks torecognise and reward leading energy-efficiency companies. The current goal is to foster the efficient use ofenergy as an energy resource, establishing a 20.0% savings goal by the year 2025, considering the expectedenergy consumption growth in the economy as of that date.
RENEWABLE ENERGYIn April 2008, Law 20.257 (Law of Non-Conventional Renewable Energy) was enacted, which was added
to previous modifications of the Electricity Law introduced through Law 19.940 (2004) and Law 20.018(2005). It establishes the requirement that electricity companies include a percentage of non-conventional
renewable energy (renewable energy excluding large hydropower plants, NCRE) as a share of the total energy
sold.
Specifically, the law requires that between 2010 and 2014 5.0% of the total annual withdrawals ofelectricity generators that obtain energy from electric systems with an installed capacity greater than 200
MW be guaranteed to come from non-conventional renewable sources. Beginning in 2015, the required
level of non-conventional energy sources rises by 0.5% annually to reach 10.0% of the total energy
production by 2024. Since 2005, the Ministry of Energy has implemented, through the CORFO, amechanism used to finance feasibility studies for NCRE projects for up to 40.0% of the total study with a
UF 1 000 cap. (Approx. USD 40 000.00)
In October 2013, the government of Chile enacted Law 20.698 to promote the expansion of renewableenergy, which doubles the goal previously set by Law 20.257 and specifies that 20.0% of the electricity soldby 2025 must come from non-conventional renewable energies. In addition, it introduces the obligation of
the Ministry of Energy to conduct annual public procurement of energy blocks generated from nonconventional renewable energy, which will serve to fulfil the required NCRE quotas. This occurs only if it
is foreseen that the market will not meet the requirement by itself.
At the end of September 2014, Chile’s energy matrix has an installed capacity of 1 803 MW of NCRE,
with Wind and Biomass representing 41.0% and 26.0%, respectively. In the same way, there are an additional
14 280 MW in new projects with approved Environmental Permission and 5 035 MW under environmental
evaluation.
Chile’s Economic Development Agency (CORFO) is administratively dependent on the Ministry of
Economy and its mission is to promote the economy’s economic development by supporting production
companies. CORFO handles subsidies for studies at the pre-investment stage and long-term credits forfinancing consortiums to develop biofuel projects and solar energy pilot projects.
NUCLEARIn 1964, Chile created its Commission on Nuclear Energy (Comisión Chilena de Energía Nuclear, or CCHEN)
to address problems related to the production, acquisition, transfer, transport and peaceful uses of atomic
energy. Also, the Commission on Nuclear Energy is in charge of the operation and regulation of the tworeactors located in the Santiago metropolitan region, which have been used for investigation and civil
purposes. In 2007, the Nuclear Power Working Group was created to assess the potential advantages andrisks associated with the use of nuclear energy for power generation. Its duties are as follows:Technical and legal advisor to the government on nuclear issues related to energy and radiations;

Research and development in peaceful uses of nuclear energy;Regulate, control and supervision of nuclear facilities; and41

APEC E N E RG Y O VE R VI E W 2014



CHILE

Technology transfer and its applications.

In the National Energy Strategy 2012–2030 the Chilean government announced that it had decided
that it would not make any decisions regarding the use of nuclear energy to generate electricity.

CLIMATE CHANGE
Chile is a signatory to the United Nations Framework Convention on Climate Change (1995) and ratified
the Kyoto Protocol in 2002. In December 2008, Chile published the National Action Plan on Climate
Change 2008–12. This action plan assigns institutional responsibilities for adapting, mitigating andstrengthening Chile’s response to climate change (CONAMA, 2008). According to the results ofvulnerability studies of the Environmental Ministry of Chile, the effects of the climate change cansummarised as follows:

Decrease in precipitation in some regions up to 75.0%, temperature increase up to 1.5% and a decreasein the caudal rate to 77.0% in some regions.



The vast majority of species have reduced their distributions.



Regions, which are predominately small properties with 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 global carbon
dioxide emitted in 2010 (UNStats, 2013) its territory is highly vulnerable to the effects of climate change.
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, and 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 the biodiversity.
N OTA B L E E N E RG Y D E V E L O P M E N T S

The new Energy Agenda increases the role of the government not only as a regulator but also as an active
participant in the energy market through ENAP. The government aims to protect the final consumer ofenergy and create effective competition in the market. In the case of market distortions, the government
will use public policies, regulations, and even direct participation in the market through ENAP.
Under the new Energy Agenda of May 2014, the Chilean government proposes short- and long-termgoals. The short-term policy horizons goals lay out the terms for the standards, policies and regulations with
the intention of securing the technical feasibility and sustainability of the energy matrix by 2025. The
medium- and long-term policy goals cover the strategic and technological aspects defining the energy matrix
to be intensified by 2050.
This new Energy Agenda proposes a participative role of the society that involves public sector,
industry, academy, civil society, regions and citizens to approve the new long-term “Energy Policy”. This
policy will identify the matrix, standards, guidelines and regulations required to guarantee its sustainability
and feasibility through year 2050. Additionally, this Energy Agenda, proposes energy security as a permanent
process to establish an organisational and operative structure for ex-ante preparation to face energy
emergency situations.
REFERENCES

BCL(Banco Central
de Chile) (2013).
Cuentas Nacionales deChile 2008-2013.
http://www.bcentral.cl/publicaciones/estadisticas/actividad-economica-gasto/aeg01j.htm.

CIFES (Centro Nacional Para la Innovacion y Fomento de las Energias Renovables) (2014). Estado deProyectos ERNC en Chile, Octubre 2014. http://cifes.gob.cl/

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APEC E N E RG Y O VE R VI E W 2014

CHILE

CNE (Consejo Nacional de Energía) (2013). Operacion Real por Sistema Electrico Nacional Periodo: 1998 – 2013.
www.cne.cl/estadisticas/energia/electricidad/.
––––(2013). Capacidad Instalada por Sistema Eléctrico. http://www.cne.cl/estadisticas/energia/electricidad/.
CONAMA (Comisión Nacional del Medio Ambiente) (2008). Plan de Acción Nacional de Cambio Climático
2008–2012. www.mma.gob.cl/.
CchEN(Comision Chilena deEnergia Nuclear). Uranium and Thorium Resources in Chile
Prospection and Recovery Experiences. July 2013.

CIFES (Centro Nacional para la Innovación y Fomento de las Energías Sustentables) (2015) Estado
deproyectos
ERNC
en
Chile.
http://www.cifes.gob.cl/reporte/2015/REPORTE_Enero2015%20V2.pdf.
EDMC (The Energy Data Modelling Centre , The Institute of Energy Economics, Japan) (2014) APEC
Energy Statistics 2012 and the APEC Energy Database. www.ieej.or.jp/egeda/database/databasetop.html.
EIA (United States Energy Information Administration) (2014). Chile. www.eia.gov/countries/countrydata.cfm?fips=CI.
INE(Instituto
NacionaldeEstadística)(2013).
Compendio
Estadístico.
http://www.ine.cl/canales/menu/publicaciones/compendio_estadistico/compendio_estadistico201
3.php/.

MINERGIA (Ministerio de Energía) (2014) Agenda de Energía, Un desafío País, progreso para todos.
www.minenergia.cl/documentos/estudios/2014/agenda-de-energia-un-desafio-pais.html/.
––––(2013).
Balance
NacionaldeEnergía
2012.
http://antiguo.minenergia.cl/minwww/export/sites/default/14_portal_informacion/06_Estadisticas/Documentos/BNE2012.xls/.

––––(2012a). Estrategia Nacional de Energía. www.minenergia.cl/estrategia-nacional-de-energia-2012.html.
––––(2012b) Agenda Nacional de Energía 2012-2030. http://www.minenergia.cl/estrategia-nacional-deenergia-2012.html.
United Nations (2013).
Conference on Trade and Developmentwww.unctad.org/en/publicationslibrary/wir2013_en.pdf.

World

Investments

Report.

UnStats (United Nations Statistics Division) (2013). Millenium Development Goals Indicators - Carbon dioxide
emissions (CO2). http://mdgs.un.org/unsd/mdg/SeriesDetail.aspx?srid=749.
World Bank (2014). Doing Business 2014. www.doingbusiness.org/reports/global-reports/doing-business2015/.
U SEF UL LI N K S
Chilean Commission of Energy (CNE)—http://www.cne.cl
Chilean Energy Efficiency Agency (AChEE)—http://www.acee.cl
Chilean Energy Efficiency Agency—www.acee.cl
Economic Load Dispatch Centre Norte Grande Interconnected System—www.cdec-sing.cl
Economic Load Dispatch Centre of Central Interconnected System—www.cdec-sic.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
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APEC E N E RG Y O VE R VI E W 2014

National Energy Commission (CNE)—www.cne.cl
National Institute of Statistics (INE)—www.ine.cl
National Oil Company (ENAP)—www.enap.cl
Nuclear Energy Chilean Commission (CCHEN)—www.cchen.cl
Superintendence of Electricity and Fuel (SEC)—www.sec.cl
Chilean Energy Efficiency Agency—www.acee.cl
Economic Load Dispatch Centre Norte Grande Interconnected System—www.cdec-sing.cl
Economic Load Dispatch Centre of Central Interconnected System—www.cdec-sic.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 Energy Commission (CNE)—www.cne.cl
National Institute of Statistics (INE)—www.ine.cl
National Oil Company (ENAP)—www.enap.cl
Nuclear Energy Chilean Commission (CCHEN)—www.cchen.cl
Superintendence of Electricity and Fuel (SEC)—www.sec.cl

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CHINA
I N T ROD U C T I ON

China is one of the world’s most important emerging economies. It is located in north-east Asia and isbordered by the East China Sea, the Yellow Sea and the South China Sea. Its population of 1.4 billion isroughly one-fifth of the world’s population. It has a land area of about 9.6 million square kilometres, withdiverse landscapes consisting of mountains, plateaus, plains, deserts and river basins. Its total maritime area
is 4.7 million square kilometres, and the length of its coastline reaches 32 thousand kilometres (NBS, 2012).
After reforming and opening up its economy in 1978, China entered a new period of high-speed growth.
Its entry to the World Trade Organisation in 2001 further contributed to its prosperity in the first 10 yearsof the twenty-first century. China’s proportion of total imports and exports in the world increased from
4.0% in 2001 to 10.1% in 2012 (WTO, 2013). In 2010, China overtook Japan to become the world’s secondlargest economy, ranking after the United States. Its gross domestic product (GDP) was 13 236 billion (USD
2010 at PPP), with the primary, secondary and tertiary industries accounting for 10.0%, 43.9% and 46.1%,
respectively (EDMC, 2014; NBS, 2013).
Due to its huge population and booming economy, China plays an increasingly important role in theworld’s energy markets. Some statistics have reported that China was the world’s largest energy consumer
in 2013 and accounted for 22.4% of global primary energy consumption in 2013 (BP 2014). However, its
per capita primary energy supply, at 2.0 tonnes of oil equivalent (toe) in 2012, is far lower than that of many
developed economies and below the world’s average. It has almost one-fourth of the per capita energy
consumption of the United States (EDMC, 2014).
China is rich in energy resources, particularly coal. According to recent estimates, China had recoverable
coal reserves of around 114.5 billion tonnes, proven oil reserves of 18.1 billion barrels and proven natural
gas reserves of 3.3 trillion cubic metres (tcm) at the end of 2013 (BP, 2014). In addition, China has
400 gigawatts (GW) of economic hydropower potential, more than any other economy. Coal and oil
resources have been utilised more extensively than natural gas and hydro for power generation and industrial
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 1978 to 2012, theaverage annual growth rate of primary energy consumption in China was 5.6% and the average annual
growth rate of GDP was 15.9% (NBS, 2013). China essentially achieved its goal of a quadrupling of GDP
supported by only a doubling of energy consumption.
Table 1: Key data and economic profile, 2012
Key dataa

Energy reservesb

Area (million sq. km)

9.6

Population (million)
GDP (USD (2010) billion at PPP)
GDP (USD (2010) per capita at PPP)

Oil (billion barrels)

18 1001 350.7

Gas (billion cubic metres)

3 300

14 249.0

Coal (million tonnes)

114.5

10 549Uranium (kilotonnes U)

18 100Source: a. (EDMC, 2014); b. (BP, 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, driven mainly by rapid economic growth,
especially in energy consumption by heavy industry. In 2012, the total primary energy supply increased 5.2%
compared with 2011, reaching 2 668 Mtoe, including net imports and other. Of this, coal was the dominantsource, accounting for 73.2%, followed by oil (17.8%), gas (5.1%) and other (3.9%) (EDMC, 2014).
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

45

Final energy consumption (ktoe)

Power generation (GWh)APEC E N E RG Y O VE R VI E W 2014

Indigenous production
Net imports and otherTotal PES
Coal

CHINA

2 289 163 Industry sector
467 639 Transport sector
2 668 356 Other sectors
1 954 417 Total FEC

932 042 Total

4 987 553

202 742

Thermal

3 892 814

417 673Hydro

872 107

1 552 458

Nuclear97 394125 238

Oil

474 526

Coal

597 464

GeothermalGas

136 498Oil

437 282

OthersOther

102 915

Gas

92 414

Electricity and other425 297

4 987 553

Source: (EDMC, 2014).

China has provided significant political and financial support for the development of its abundant
indigenous coal reserves to ensure the security of its energy supply. In 2012, China’s total energy production
reached 2 289 Mtoe, of which coal accounted for 81.7%, followed by oil (9.1%), gas (4.4%) and other (4.9%)(EDMC, 2014). Since the 1990s, Chinese authorities have been encouraging fuel switching (for example,
from coal to cleaner fuels), introducing energy-efficiency initiatives to reduce pollution and emissions fromenergy use, and optimising the existing energy structure. However, with lean oil and gas resources, the shareof coal in total domestic energy production is still at a comparatively high level. In 2013, coal production
reached 1 840 Mtoe, 1.2% higher than the previous year. Total coal consumption reached 1 925 Mtoe, 4.0%
higher than the previous year and 50.3% of global coal consumption in 2013 (BP, 2014).
In 2013, China’s domestic crude oil production reach 208.1 million tonnes, rising 0.6% compared to 2012.
At the same time, crude oil imports reached 283 million tonnes. Since 1993, China has been a net oil and oil
product importer, and net oil and oil product imports increased to 311.5 million tonnes in 2012. Total oil
consumption reached 507.4 million tonnes, 3.8% higher than the previous year and 12.1% of global oil
consumption in 2013 (BP, 2014).
China’s proven gas reserves and gas production have expanded rapidly. Gas reserves have grown from1400 billion cubic metres (bcm) in 2001 to 3300 bcm in 2013. Since 2003, gas production in China has
grown 12.8% a year, on average, to reach 117.1 bcm in 2013 (BP 2014). The expansion of natural gas
pipelines has also been rapid (NBS 2013). At the same time, China imported 24.5 bcm of liquid natural gas(LNG) and 27.4 bcm of pipeline gas in 2013. Total gas consumption reached 161.6 bcm, 10.8% higher thanthe previous year and 4.8% of global gas consumption in 2013 (BP, 2014).
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, which were major
consumers of electricity. Subsequently, however, a power supply shortage developed because of rapid
economic expansion after 2001. Between 2001 and 2005, installed generation capacity increased steadily atan annual average rate of 9.8%; since 2005, installed generation capacity has increased steadily at an annual
average rate of 13.6%. In 2010, installed generation capacity reached 962 GW, an increase of 10.1%
compared with 2009 (EDMC, 2013).
The power supply structure diversifying, with wind power and nuclear energy generation increasing
rapidly. In 2012, total power generation in China was 4 987.6 terawatt hours (TWh). Thermal power
accounted for 78.1% (3 892.8 TWh) of total generation, hydropower 17.5% (872.1 TWh), nuclear energy
2.0% (97.39 TWh) and other 2.5% (125.2 TWh) (EDMC, 2014).

FINAL ENERGY CONSUMPTION
Final energy consumption in China reached 1552.5 Mtoe in 2012, 6.9% higher than in the previous year.
The industrial sector was the largest consumer, accounting for 60.0% of total final energy consumption,
followed by the transport sector (13.1%) and other sectors, including residential, commercial and agriculture,
totalling 26.9% (EDMC, 2014).
Power generation increased 12.0% to 4 987.6 TWh in 2012, compared to the previous year (EDMC,
2014). Demand rate growth was, as in previous years, based mainly on increased consumption in thecommercial and public services, residential, transport and industrial sectors. In 2012, the industrial sector
accounted for the majority of electric power consumption (68.6% or 243.33 Mtoe), followed by theresidential, commercial and public services sector (29.1% or 103.26 Mtoe, including non-specified), andtransport (2.2% or 7.9 Mtoe). In terms of growth, electric power consumption in the residential, commercial

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and public services sector in 2012 increased by 10.26% compared with the previous year, the transportation
sector by 7.89%, and the industry sector by 5.3% (EDMC, 2014).
Coal consumption, excluding coal consumption to generate electricity, was 597 Mtoe in 2012 (EDMC2014). The electric power generation sector was the biggest coal consumer, followed by the metallurgicalsector, the building materials sector, the chemical sector and other. Coal consumption in the residential,commercial and agriculture sectors showed little growth.
In 2012, total final oil consumption was 437 Mtoe. The transportation sector was the largest oilconsuming sector, accounting for 40.9% of total final oil consumption, or 178.4 Mtoe. The industrial sector
was the second largest in terms of consumption and accounted for 21.9% of total oil consumption or
95.4 Mtoe (EDMC, 2014).
The market for gas is moving to the north and east of China with the completion of the Shaanxi–Beijing
and West–East gas pipelines. With the larger-scale utilisation of gas, residential and commercial and public
service consumption grew from 5.19 Mtoe in 2000 to 31.7 Mtoe in 2012. However, the industrial sector was
still the largest sector in total final gas consumption, accounting for 40.9% or 37.9 Mtoe (EDMC, 2014).
Based on changes in its electricity mix and energy consumption in end-use, China is optimising its primaryenergy structure, and the proportion of low-carbon energy has increased significantly. In 2012, theproportion of coal used was 66.6% (compared to 76.2% in 1990), the proportion of oil and natural gas usedrose from 18.7% in 1990 to 24.0%, and hydropower, nuclear energy and wind power rose from 5.1% in1990 to 9.4% (NBS, 2013).

ENERGY INTENSITY ANALYSIS
China has reduced energy intensity in the last two decades. The intensity of primary energy and final energy
demand in 2012 have been cut by 50.4% and 61.5% respectively compared to 1990, the biggest among the
APEC economies. However, the energy intensity is still very high and there is quite a lot of room to improve(EDMC, 2014).
In 2011, China eliminated more than 3 GW of small thermal power plants and 24 million tonnes of backward
cement production capacity (MEP, 2012). With all these efforts, the intensity of final energy demanddecreased 1.2% year-to-year in the industry sector. However, due to the booming economy andtransportation needs, car purchases are high, which result in increased energy intensity of transportation
sector.
Table 3: Energy Intensity, 2012

EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

191.6

187.3

-2.3

Final Energy Demand

109.7

109.0

-0.7

Industry

66.2

65.4

-1.2

Transportation

13.8

14.2

3.2

Others

29.8

29.3

-1.5

Sources: EDMC (2014).
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
key to economic restructuring, which is also an important indicator of social progress. Achieving the goalof a low-carbon and orderly energy structure is the basis of China’s energy strategy.
In March 2011, the National People’s Congress approved the Twelfth Five-Year Plan for National
Economic and Social Development (the Twelfth Five-Year Plan). The plan aims to:47

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

prioritise domestic resources; encourage diverse patterns of development; protect the environment;

increase international cooperation for mutual benefit;adjust and optimise the energy structure; andconstruct a modern energy industry with the merits of safety stability, economy and cleanliness.

It also publishes energy targets including increasing non-fossil fuels in total primary energy consumption to
11.4%, and reducing the energy consumption per unit of GDP by 16.0% and carbon dioxide emissions perunit of GDP by 17.0% by 2015, compared to 2010.
ORGANISATIONThe National Energy Committee is a high-level body that coordinates overall energy policies. The committee,
chaired by the Premier, is in charge of drawing up 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 currently is composed of 12 departments, with an authorised staff size 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, including coal, oil, andnatural gas, other forms of power such as nuclear energy, and new and renewable sources of energy. It 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 policy development.
In 2009, China established the National Energy Conservation Centre directly under the NDRC toprovide technical support to the government in implementing energy efficiency and conservation
management initiatives. Its main duties include energy efficiency and conservation policy research; theassessment of fixed asset investment projects; information dissemination; the promotion of technologies,
products and new mechanisms; label management; and international cooperation in the field of energy
conservation.
LAW
The laws relating to energy in China include, the Coal Law, the Electricity Law, the Renewable Energy Law,
the Energy Conservation Law and the Environmental Protection Law. A comprehensive legal basis for theenergy sector, the Energy Law, is currently under consideration. The Standing Committee of the National
People’s Congress endorsed the amended 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 and emphasises the completely secure purchase of power from renewable energy
sources and the establishment of a development fund for renewable energy. The amendment provides thatpower grid companies will receive all of the revenue generated from the surcharge on retail power tariffs,
and it sets a minimum target for renewable electricity that 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 and came into effect on
1 October 2010, requires that oil and pipeline companies take safety measures while constructing pipelines.
This includes ensuring the quality of construction materials, conducting regular patrols of pipelines andpromptly eliminating any hazards.
The State Council approved the Regulation on Electricity on 15 February 2005 and 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
and 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‘More coal, less oil and gas’ characterises China’s energy resources. The most efficient use of available
resources is the guiding principle for the economy. China has also strengthened the security of its oil supply
through building and supporting bilateral cooperation with new trading partners and through theglobalisation of its oil and gas assets. China is trending toward energy diversification to secure its energy
base.
To increase oil supply security Chinese companies are encouraged to develop upstream investment activities
abroad, through cooperation with international and/or local companies. The China–Russia crude oil
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pipeline, completed in September 2010, transports 150 mt of crude oil per year from 2011 to 2030. On
10 September 2010, construction began on domestic engineering of the China–Myanmar oil and gas pipelinein Yunnan province. In 2009, the first phase of China’s SPR projects was completed and in operation. In
2010, a second round of SPR projects began construction, and a third round of SPR locations went throughthe site selection process. In 2014, China’s SPR capacity has reached 12.4 mt (NEA, 2014b). According to
the China Petroleum and Chemical Industry Federation (CPCIF), with the addition of the second and thirdrounds, China’s SPR capacity will reach 350 million barrels by the end of 2015 (CPCIF 2011).
In order to secure the energy supply, the NDRC and the Ministry of Finance established a strategic coalreserve base in major coal production areas and import ports in 2011. The first round of reserves withcapacity of 5 mt. China will continue to look for new locations for a second round of strategic coal reserveswith another 10 mt capacity (CEN, 2011).
ELECTRICITY MARKET
In addition to the abovementioned laws, the following laws apply to the electricity market: the Electricity
Law, the Energy Conservation Law, the Renewable Energy Law, the Regulations on Electric Power Supply
and Consumption, and the Basic Operating Rules for the Electric Power Market.
The State Electricity Regulatory Commission (SERC), formed in 2003, administers the electricity sector,
along with the NDRC and the NEA. The SERC merged into the NEA in March 2013. This is a significant
change for China's power industry as the restructuring has eliminated duplicated functions andresponsibilities between the original NEA and the SERC, and endowed the new NEA with greateradministrative and regulatory power over the energy sector.
In 2014, China’s total installed power generation capacity reached 5550 TWh, a 3.6% increase from theprevious year, giving it the second largest capacity in the world. (CEC, 2015).
In 2011, thermal power plants, particularly coal-fired power plants, were under pressure both from themove towards carbon reduction and from operational deficits. The southern provinces experienced theworst power shortages since 2004. This situation was caused by the contradiction that existed between coalfired power plants and the price for supplying coal, which resulted in a ‘the more power generated, thegreater the deficit’ dilemma for existing coal-fired power plants. In order to solve this problem, the NDRC
announced the decommissioning of coal-fired power plants with a capacity of less than 100 MW by the endof 2011, and proposed a mechanism for creating a linkage between the price of electricity and coal prices.
In 2011, China adjusted the tariff for electricity three times. The last adjustment, at the end of 2011, wasmore comprehensive, and included CNY 0.008/kWh in subsidies. In this regard, while price adjustments
may ease the losses incurred by thermal power enterprises, reliance on temporary administrative adjustments
makes it impossible to solve the problems of China's electric power system (CEN, 2011).
Some coal production enterprises have gradually expanded their business into the thermal powerindustry. This has led coal-fired power plants growth continued growth and rising coal prices to bring greater
revenue for the coal industry. This also creates impacts efforts to reduce carbon emissions. However, theintegration of power generation companies with coal production companies can also help avoid the risk ofcoal price fluctuations and enhance the stability of the electricity supply (CEN, 2011).
On December 2011, China completed the power grid network connecting Qinghai and Tibet—the
Qinghai-Tibet power grid project. It has a total length of 1 038 km and includes DC transmission lines andtwo ±400 kV converter stations. It also supports the construction of the Xining-Mountain-HercynianGolmud 750 kV power transmission project and a 220 kV power grid project in Tibet. It integrates the Tibet
Power Grid into China’s grid and completes China’s comprehensive grid network system (CEN, 2011).
ENERGY MARKET
Actively promoting energy market reform and uniformly allocating resources to accelerate development areamong China’s major concerns. The Government of China announced that the entire range of projects
included in the National Energy Plan would be 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,’ which encourages private capital toparticipate 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 acomprehensive, new renewable energy industry.
China has stressed that reform is a strong driving force in accelerating the transformation and diversificationof energy. China intends to continue pushing firmly ahead to reform the energy field, strengthen top-level
design and overall planning, accelerate the establishment of institutional mechanisms for the development
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of energy technology, improve the environment for energy development, and promote a revolution in energy
production and application to secure the economy’s energy supply in line with demand (Reuters, 2012).
COAL MARKET
Coal is the major primary energy source for China, contributing about 70.0%, and this is likely to remain thecase for the near future. Due to efforts by the State Council and enforcement of policies regarding coalindustry development during the period of the Eleventh Five-Year Plan (2006-2010), the coal industry has
made quite promising progress (CEN, 2011).
In March 2012, the NEA announced its Twelfth Five-Year Plan for Coal Industry Development andset an overall target for annual coal production to reach 3.9 Bt by 2015. The Plan calls for the industry to: Continue to push for the formation of large coal companies that will contribute to more than 60.0%
of production in China.
 Continue to improve the safety of coal production, reducing deaths per million tonnes of production
by more than 28.0% in 2015 compared to 2010.
 Adjust the balance between production and demand, strengthen the railway and shippingtransportation system, reduce the long-distance road transportation of coal, and establish an
emergency coal reserve system, improving emergency response capabilities.
 Strengthen the development of coal bed methane by creating 36 sites with annual production of coal
bed methane in excess of 100 million cubic metres. Encourage the application of coal bed methane in
district power generation and for household use through the construction of a district pipeline network.
On 21 October 2010, the State Council announced the Instructions for Accelerating Coal MineEnterprise Mergers and Restructuring, prepared by the NDRC. Some commentators believe that mutual ties
between a coal enterprise and its relevant upstream and downstream industries will be a trend and that the
integration of coal production and related industries will be an important characteristic of future large coalcompanies (CEN, 2010).
Since 2011 the central government requested that large coal and power enterprises establish coalreserves in the major collection and distribution centres, consumption regions and key transport hubs, so as
to be able to respond to supply disruptions or serious shortage of coal due to natural disasters or otheremergencies. The central government grants a subsidy to the stakeholders for their costs in relation to thereserves and instructs them to use the reserves when it is necessary.
According to the strategic plan for energy development (2014-2020), the consumption of coal will beless than 4.2 billion tonnes by 2020. The government plans to expand 14 large coal bases, with an output
that will occupy 95.0% market share in China (SCC, 2014a).
The February 2011 ‘Thermal Power Plant Air Pollutant Emission Standards’ (second edition), requires
all new thermal power plants from 2012 to meet tougher emissions standards for sulphur dioxide, nitrogenoxides and particulate matter. From 1 July 2014 these standards also applied to existing power plants. (CEN,
2011).
OIL MARKETIn December 2008, China instituted an oil product tax and price reform plan. Based on the Highway Law
and other relevant regulations, the NDRC, the Ministry of Finance, the Ministry of Transport and the State
Administration of Taxation jointly drafted a proposal on a fuel tax reform program. The State Council
approved the programme and it took effect on 1 January 2009. The reform aims to standardise government
fees and charges by gradually abolishing all fees related to road maintenance, waterway conservation, roadtransport management, road passenger and freight surcharges, water management and water transportpassenger and freight surcharges, as well as government approval of road charges on secondary loans. The
reform also raises the gasoline consumption tax from CNY 0.2 a litre to CNY 1 a litre for gasoline and from
CNY 0.1 to CNY 0.8 for diesel, with similarly increased unit taxes on other oil products. For gasoline anddiesel oil, the aim is to implement a fixed-amount consumption tax rather than an ad valorem tax.
The government mandates or guides prices for oil products depending on the product type. When the
average oil price in international markets varies by greater than 4.0% for more than 22 consecutive working
days, the government may adjust domestic oil product prices accordingly. From December 2008 to March
2013, the government adjusted the oil price 25 times, where it rose 15 times and fell 10 times. In March
2013, the NDRC revised the oil pricing mechanism to reflect global price movements. The new plan
shortened the 22-working day price review period to a 10-working day period and removed the 4.0%
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fluctuation limit, which means the government will adjust domestic oil product prices based on international
market fluctuations every 10 working days (CEN, 2013).
On 25 March 2006, the State Council decided to collect a Special Oil Gain Levy from oil companies
that obtain excess income from sales of domestically produced crude oil when the crude oil price exceeds acertain level. The cut-off point is USD 40 per barrel and the levy rate is progressive, with five categories
ranging from 20.0% to 40.0%.
On 9 May 2008 the National Standardisation Technical Committee for the Oil and Natural Gas Industry
standardised China’s oil and natural gas industry and it entered a new stage of development. The committee
is responsible for petroleum geology, oil exploration, oil drilling, logging, oil and gas field development, gas
production, storage and transportation of oil and gas, oil and gas measurement and analysis, oil pipes,
offshore oil engineering, production safety and environmental protection.
On 1 November 2010, the first crude oil pipeline between China and Russia began its trial run. This pipelinetransports 15 mt of crude oil a year from 1 January 2011, for a period of 20 years, up to a maximum of
30 mt a year (CEN, 2010).
In 2010, the first round of economy-wide strategic petroleum reserve projects successfully completed
collections. China aims to have 100 days of net imports by 2020 or approximately 570 million barrels andcurrently has just under 30 days of net imports. (Bloomberg News, 2014). China constructed a number ofcommercial petroleum reserve bases with a capacity of up to 26.5 million cubic metres. In December 2015
China had 20 underground gas storage units with a total storage capacity of 4.2 billion cubic metres (bcm)(CN, 2015).
The ‘Ocean Oil 981’, also known as Haiyan Shiyou 981, Ocean Petroleum 981 and HD-981, began
operation in 2012 in the South China Sea. It is the sixth generation of China’s first independently designed
3 000 metre deep-water semi-submersible drilling platform and is used to perform deep-water drilling for
the China National Offshore Oil Company (CNOOC) (CEN, 2011).
In 2011 China started the refined oil electronic trading platform at the Beijing Petroleum Exchange,along with another trading platform in Xiamen (CEN, 2011). In March 2013, the NDRC announced a new
pricing system to reflect fluctuations in global oil prices. The new system shortened the current 22-day
adjustment period to 10 days and removed the 4.0% limit, making it a more market-based mechanism that
could better reflect production costs and energy shortages.
NATURAL GAS MARKET
China’s energy industry is rapidly expanding its natural gas market. This includes production, transmission
and application of natural gas. On 14 October 2012, China released the new Natural Gas Utilisation Policy(2012 Gas Policy). The 2012 Gas Policy addressed some important issues such as balancing gas supply anddemand, promoting economical and efficient use, intensifying the pricing reform and classifying gas users(NDRC 2012).
China’s five-year plan (2011–2015) for shale gas development, aims for 6.5 bcm/year of shale gas
production by 2015, the equivalent to 2.0–3.0% of projected Chinese gas production in 2015, and60~100 bcm/year of shale gas production by 2020. Geological conditions are complex in China posing
greater technical and investment challenges. In order to secure more natural gas supply through domestic
shale gas, China and the United States signed a working plan of action on shale gas resources during thesecond round of their strategic and economic dialogue in May 2010. They agreed that, based on the US’s
experience in unconventional natural gas development and in accordance with relevant Chinese laws andregulations, both sides will strengthen cooperation in shale gas resource evaluation and exploration and in
the development of technology and related policies.
According to the strategic plan for energy development (2014-2020), the usage of gas is encouraged
and the efficiency is to be improved so that gas could occupy more than 10.0% of the total primary energy
consumption in China by 2020 (SCC, 2014a).
China’s reforms cover energy investment, government regulation, market adjustment and managing
state-owned energy companies. The economy encourages investment diversification in the energy sector,
offers autonomy to businesses and seeks to attract foreign capital and advanced technology to China’s energy
industry.
The Chinese energy tax regime includes resource taxes, royalties, mineral resources compensation,
consumption taxes and other levies. Since 1 October 1984, China collected a resource tax on oil, natural gas
and coal. In 1994, the levying scope expanded to the volume of production as well as the circumstances ofthe various resources. In September 2011, the State Council amended the Provisional Regulations on
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Resource Taxes. From 1 November 2011, the assessment base for resource taxes on crude oil and natural
gas changed from production amount to sales value, with the tax rate ranging from 5%–10%. It singles out
coking coal and rare earth ores from coal and nonferrous metal ore resources, respectively. Correspondingly,
it also raises the tax rates were to CNY 8–20 per tonne and CNY 0.4–60 per tonne, respectively.
The collection of royalties is limited to offshore and onshore oil and gas exploitation and with the option to
pay in kind. Since 1989, production of up to 1 mt of crude oil in offshore exploitation has royalties levied at
a rate of 2.5%–4%. Similarly, production of up to 2 bcm of natural gas has royalties levied at a rate of 1%–
3%. For onshore exploitation, the collection of royalties has depended on the annual production of each oil
field or gas field since 1990. The rate ranges from 1%–12.5% for production of up to 50 000 tonnes ofcrude oil and 100 million cubic metres of natural gas. Since 1 April 1994, China has levied mineral resourcescompensation on mining operators. The rates differ between mineral resources, ranging from 0.5%–4%.
There are 13 kinds of energy-related products, including gasoline and diesel that incur a consumption tax.
On 29 March 2010, the Sichuan–East China gas production and related transmission pipeline came into
operation. This included Puguang gas field exploration and development, acidic gas processing and matching
long-distance pipelines. At present, the Puguang gas field has an annual production capacity of 10.5 bcm ofnatural gas mixture, with plans to purify 4 bcm of natural gas. The pipeline is 2 170 kilometres long and will
carry 12 bcm of natural gas to eastern China and the regions along the line (CEN, 2010).
On 1 June 2010, a Notification on the Increase of the Benchmark Price of Domestic Onshore NaturalGas issued by the NDRC went into effect. This notification aims increase domestic natural gas prices andto publicise related policies about natural gas pricing and supporting measures (CEN, 2010).
On 19 November 2010, the State Council approved the Regulation on the Administration of Urban
Gas it came into effect on 1 March 2011.
On 3 December 2010, four ministries jointly issued a notice announcing further expansion ofinternational cooperation on coal bed methane (CBM) exploration (CEN, 2010). In 2013 pilot wells
produced 3 bcm and China is aiming to produce 16 bcm in 2014. However, meeting this target is unlikely,
given development is still in its early stages (NUS, 2014).
The first stage of the Shanxi Coal Bed Methane Pipeline was completed at the end of 2011 at a lengthof 354 km. The second and third stages will follow with an additional 1 328 km. This is the longest pipeline
for a coal bed methane transportation system in China. It will support the Gasification Shanxi strategy andspeed up the development of coal bed methane in China. Construction of a so-called ‘five horizontal andthree vertical’ pipeline network across Shanxi Province is also planned, with a total length of 3 300 km tosupport 12 bcm of annual gas production by the end of 2015 (CEN, 2011).
ENERGY EFFICIENCY
China's energy consumption per unit of GDP is much higher than the global average. Energy-intensive
industries are backward in technology. The share of energy consumption by the secondary industries is toohigh a percentage of the member economy's total. Four major energy-intensive industries—steel, nonferrous metals, chemicals, and building materials—account for 40.0% of the total energy consumption. Low
energy efficiency results in high-energy consumption for every unit of GDP.
In 2011, the State Council released the Comprehensive Work Plan on Energy Conservation andEmission Reduction during the Twelfth Five-Year Plan Period. This plan proposed the major objectives
and key actions in the fields of energy conservation and emission reduction during this period. China aims
to establish a ‘reverse coercion mechanism’ through the dynamic integration of its efforts in lowering theintensity of energy consumption, reducing the total emissions of major pollutants, and rationally controlling
total energy consumption. The reverse coercion mechanism helps promote the strategic restructuring of theeconomy, push forward the optimisation of the industrial structure, and strengthen all aspects of energy
utilisation management in industry, construction, transportation and public organisations, as well as in thefields of urban and rural construction and consumption (SCC 2012a).
To promote energy conservation activities in the industry sector, the central government has issued
catalogues of advanced and applicable technologies in the fields of energy conservation and emission
reduction for key industries such as iron and steel, petrochemicals, non-ferrous metals and building materials.
It has established and improved a mandatory standards system of quotas for energy consumption per unit
product in key industries and strengthened the energy-saving evaluation and supervision system. It has
undertaken key energy-saving projects, including combined heat and power (CHP), recycling of industrial
by-product gas, construction of enterprise energy-control centres, and fostering of energy-saving industries,
to increase its enterprises' energy utilisation efficiency. The government also encourages energy service
companies (ESCOs) through financial and tax incentives. ESCOs provide a total energy efficiency solution
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(finance, technology, operation, maintenance, etc.) for industrial energy users. From 2005 to 2010, thenumber of ESCOs increased from 80 to over 800, the number of employees in this sector increased from
16 000 to 180 000, and revenues from the energy service industry grew from CNY 4.7 billion to
CNY 84 billion (USD 740 million to 13.2 billion) (APERC, 2012).
In the transport sector, the government is committed to improving public transport, developing
intercity rail transportation, and encouraging green commuting. China has implemented some of the world’s
most advanced fuel economy standards for automobiles and popularised energy-saving andenvironmentally-friendly vehicles. It is speeding up the elimination of old automobiles, locomotives andships. Some efforts include optimising the transportation structure and develop green logistics. According
to the Development Plan for Energy Saving and New Energy Automobile Industry (2012–2020), China will
focus on electrically powered cars (EVs and FCVs) to increase energy efficiency and reduce carbon
emissions. It will also push the economy’s automobile industry to upgrade its technology and encourage
local car manufacturers to speed their efforts in the development of electrically powered vehicles. Production
and sales of electrically powered vehicles are expected to total 500 000 units by 2015 and to reach more than
5 million units with a 2 million unit production capacity by 2020. Subsidies and tax exemptions are available
for electrically powered vehicles (SCC, 2012b). The construction of supporting facilities, such as electricity
charging facilities is also included. More than 2000 charging stations with 400 000 quick chargers for EVs
will be provided by 2015. The economy is harmonising charging methods to promote electrical-driven
vehicles. Electrically powered car (EVs and FCVs) and hybrid vehicle use is gradually increasing on thedomestic market (IEEJ, 2012). Another effort by China is to carry out a vehicle fuel consumption testing
and management scheme from March 2011 to enhance and strengthen vehicle energy efficiency
management. In this scheme, China published a list of vehicle models that satisfy the fuel consumption
standards (CAA, 2011).
The government sets standards for green buildings and implements rating and identification of green
buildings. It actively promotes energy-saving renovation of existing buildings, sets quotas for energy
consumption by public buildings and publicises their energy efficiency rates. It has set up a management
system for the life cycles of buildings and exercises strict control over the demolition of buildings. China
has also made and implemented an energy-saving plan for public institutions and strengthened theestablishment of a supervisory system for energy conservation in public buildings. It carries forward heatmetering and energy efficiency renovations on existing residential heating systems in the northern regionsof China, builds energy-saving greenhouses, improves the old heat-supply network, and practices meteredheat-supply charging and energy consumption quota management (SCC 2012a).
China also promotes energy conservation among all citizens. The government will intensify efforts inenergy saving education and publicity. It has launched a project to promote energy-efficient products suchas high-efficiency lighting products and air conditioners, energy-efficient motors by providing government
subsidies. The central treasury has appropriated subsidies to support the use of 360 million high-efficiency
lighting products, 30 million high-efficiency air conditioners and one million energy-efficient motor vehicles,
which have realised an annual energy-saving capacity of 20 billion kWh. The government has established apreferential procurement system for energy-efficient products, released a government procurement list ofenergy-efficient products and ordered the mandatory procurement of nine kinds of energy-efficient
products, including air conditioners, computers and lighting products. By the end of 2010, the market shareof high-efficiency lighting products had reached 67.0%, and that of high-efficiency air conditioners, 70.0%.
China advocates demand side management, pushing enterprises to use efficient products and optimise
energy usage. The target is to save more than 40 TWh of electricity and reduce 9 GW in peak demand during
2014-2015 year (SCC, 2014b).
RENEWABLE ENERGY
China announced the Medium- and Long-term Development Plan for Renewable Energy in September
2007. It aims to achieve a 15.0% share for non-fossil fuels (including nuclear energy) in its primary energy
consumption mix by 2020. According to the strategic plan for energy development (2014-2020), the capacityof hydro power, wind power and solar power are expected to be around 350GW, 200GW and 100 GW by
2020 respectively, while the usage of geothermal power would save about 40 mt coal equivalents (SCC,
2014a).
In the Twelfth Five-Year Plan for Energy Development, China confirms its ambitious targets forrenewable energy. By the end of 2015, installed wind power generation capacity will reach 100 GW, and thecapacity of installed solar power plants will be more than 21 GW.
After the enactment of the Renewable Energy Law in 2005, China has doubled its installed capacity
every year for renewable energy. In 2010, the thermal power supply accounted for 79.2 of total power
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generation capacity, hydro for 17.2% and (grid connected) wind power for 1.1%. The Renewable Energy
Law, revised in April of 2010, now requires the grid companies to guarantee a minimum amount of
renewable electricity to solve the issue of balance between power generation and grid connection.
The generation price for biomass power, solar power and other sources of renewable energy power is amandated price. On 18 July 2010, the NDRC published a Notification about the Ideal Pricing for Power
Generation Using Agriculture and Forestry Biomass, which came into effect on 1 July 2010. The notification
requires the implementation of a benchmark electricity price policy for power generation projects using
agricultural and forestry biomass. The benchmark electricity price for biomass power is uniform at
CNY 0.75 per kWh (including tax). On 24 July 2011, the NDRC published another Notification about the
Ideal Pricing for Solar Photovoltaic Power Generation, which came into effect on 1 August 2011. The
notification set the benchmark electricity price for solar photovoltaic power at CNY 1.00 or CNY 1.15 perkWh (including tax), depending on the location and commissioning time.
WIND
China’s approach in increasing wind power has come to be known as ‘Three Gorges on the Land,’ areference to a massive scale of development comparable to that of the Three Gorges Dam. In 2009, China
added 13 GW to total capacity, of which 5.5 GW was in Inner Mongolia, and was on par with Germany
with the world’s second largest installed wind power capacity. The Chinese capacity surpassed the UnitedStates in 2010, when the member economy became the world’s largest wind power capacity holder (IEA,
2012). In 2014 China installed 61 offshore wind power units with a total capacity of 229.3 MW. In 2014 theChinese Wind Energy Association released its ‘2014 China Wind Power Installation Capacity Statistics’.
According to China Electricity Council, China has 95.81 GW of wind capacity connected to the grid in
December 2014, 657.9 MW of that was offshore wind power (Howe, 2015).
In August 2011, the NEA published a large wind power grid design specification, which put forward
clear requirements for wind power unit performance. It will improve grid safety when the grid takes on wind
power.
On 31 August 2011, the Shanghai Donghai Bridge offshore wind power plants passed their 240 hours’
inspection. It was China’s first offshore wind turbine project and has a total capacity of 100 MW (CEN,
2011).
Asia's first flexible DC power transmission demonstration project—the Shanghai Nanhui Wind Farm
Flexible DC Transmission Project—was put into operation on 25 July 2011. The project links the Shanghai
Nanhui wind farm and the Sulo converter station, with a DC transport capacity of 20 MW at the ± 30 kVlevel and a transport distance of 8.6 km. It is a completely independent intellectual property of China (CEN,
2011).
SOLAR
In 2014, photovoltaic (PV) cell production in China reached 26.52 million kW, accounting for more than
50.0% of the global market share, of which five local enterprises ranked among the world’s top 10 PV cellmanufacturers. The price per PV module fell from CNY 40 per W in 2005 to about CNY 6–7 per W in2010. The power generation cost has also fallen from CNY 4 per kWh before 2009 to about CNY 1 per
kWh in 2010. This marked significant progress in technology development and production capability in
China (NEA, 2012).
In December 2014, national grid solar power generation capacity was 26.5 million kW, which is a 67.0%
increase (CEC, 2015).
China is also developing a feed-in tariff policy for PV systems to encourage the construction of solar
farms in the western region to connect with the local grid system. The Golden Sun Demonstration Projectprovided financial subsidies for the construction of photovoltaic power generation systems on the demandside. Photovoltaic power generation systems is widely used in areas without any other electricity supply, as
well as in solar traffic signals, solar street lights, and in the fields of communications, weather, railways, andpetroleum. By the end of 2010, the total installed PV capacity reached 860 000 kW, including large-scale
grid-connected photovoltaic power plants generating 450 000 kW and Building Integrated Photovoltaic
Systems (BIPVs) generating 260 000 kW (NEA, 2012).
China has established targets for solar power development: 21 GW of solar power capacity (10 GW forsolar farms, 1 GW for solar thermal power and 10 GW for distributed solar power) in 2015, and 50 GW (20GW for solar farms, 3 GW for solar thermal power and 27 GW for distributed solar power) by 2020 (NEA,
2012).

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HYDRO
On 27 March 2011 the first privately owned million-kilowatt hydropower station, the Jin'anqiao
Hydropower Station with a 2.4 GW capacity, began operations and connected to the grid (CEN, 2011).
In 2014 hydropower installed capacity reached 300 million kW, which is an increase of 7.9% from theprevious year. Generating capacity reach 1.07 trillion kWh a 19.7% increase from 2013, due to the Pianku
2013 flood (CEC, 2015).
NUCLEAR
The Medium- and Long-Term Nuclear Energy Development Plan (2005–20), issued in 2007, called for total
nuclear energy installed capacity to reach 40 million kW by 2020, and for annual power generation by nuclear
energy to reach 260–280 billion kWh. An additional 18 million kW of installed capacity will be underconstruction at the end of 2020.
China has 24 nuclear power generating units in operation by 2014 and has another 25 units still underconstruction (WNA, 2015). It has 19.1 GWe of installed nuclear energy capacity, which China plans to
expand to 58 GWe by 2020.
Following Japan’s Fukushima Daiichi Crisis in early 2011, China reviewed their nuclear plant safety
requirements. On 25 October 2012, the Chinese Cabinet approved new safety rules, which prioritises safety
and quality in the Chinese regulations (WNA, 2015). The Chinese government has said that it will approvea small number of plants along the coast in accordance with new stricter safety rules. However, none ininland areas during the period of the Twelfth Five-Year Plan (2011-2015) (SCC, 2013).
According to the Energy Development Strategy Action Plan 2014-2020, all new nuclear plants are tomeet the strictest safety standard in the world in coastal areas. (SCC, 2014a).
On 21 July 2011, China’s first fast neutron reactor—China’s experimental fast reactor (CEFR)—had its firstcritical success operation, a significant breakthrough for the economy’s fourth advanced nuclear energy
power generation system technology. China has become one of the few economies with fast reactor
technology (CEN, 2011).
CLIMATE CHANGE
The 2008 Chinese Government White Paper on China’s Policies and Actions for Addressing Climate
Change described the economy’s climate change policies and actions the economy. The government releases
follow-up annual progress reports at the end of every year. Nearly all provinces have province-level
programmes to address climate change. China also addresses climate change in its mid-term and long-termplanning for economic and social development. In 2006, China set the goal of reducing per unit GDP energy
consumption in 2010 by 20.0% from that of 2005. In 2007, China became the first developing member
economy to formulate and implement an economy-wide program to address climate change. In 2009, China
set a goal to reduce per unit GDP GHGs in 2020 by 40.0%–45.0%, compared to 2005 levels (IOSC, 2011).
It also aims to increase non-fossil fuel to 15.0% of the primary energy by 2020 and 20.0% by 2030 (NEA,
2015).
From 2000 to 2010, China's energy use grew 130.0% - a 50.0% increase from the previous decade.
China is the world's largest energy consumer and the greatest source of greenhouse gas emissions. China's
share of global energy-related CO2 emissions has increased in just five years from 19.5% in 2005 to 24.7%
in 2010 (WB, 2014).
In 2010, China launched an economy-wide ‘low-carbon province and low-carbon city’ experimental
project. The first round of selected localities included five provinces, namely, Guangdong, Hubei, Liaoning,
Shaanxi and Yunnan, and eight cities, namely, Tianjin, Chongqing, Hangzhou, Xiamen, Shenzhen, Guiyang,
Nanchang and Baoding.
In 2011, the Chinese Government released the Comprehensive Work Plan for Energy Conservationand Emission Reduction during the Twelfth Five-Year Plan period (2011–15) and established overallarrangements for energy conservation, emissions reduction and greenhouse gas emissions control duringthat period
Since 2013 seven major cities (Beijing, Chongquing, Guangdong province, Hubei province, Shanghai,
Shenshen and Tianjin) are testing a pilot cap-and-trade program. On 31 August 2014, China announced thatan economy-wide cap-and-trade program will operate from 2016 (CBR, 2014)
As the APEC region and the world’s second largest economy and largest emitter, China’s roleinternational climate change negotiations is critical. The economy is a non-annex I party to the United
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Nations Framework Convention on Climate Change (UNFCCC) and the Kyoto Protocol. It adheres to the
double-track negotiation mechanism of and the principle of ‘common but differentiated responsibilities’ inpromoting the progress of international climate change negotiations (EE, 2012).
NOTA BLE EN E RG Y D EV EL O PM E NT S
In late 2014 the United States and China made a Joint Announcement on Climate Change, which establishes
an economy-wide target of peaking CO2 emissions in 2030, however the announcement did not provide atarget level (SCC, 2014c). Under the announcement, China intends to increase the share of non-fossil fuelsin primary energy consumption to around 20.0% by 2030. President Xi Jinping and President Barack Obama
will work together, and with other countries, to adopt a protocol, another legal instrument or an agreed
outcome with legal force under the Convention applicable to all Parties at the United Nations Climate
Conference in Paris in 2015 (SCC, 2014c).
In June 2014, the 6th Work Conference of Central Government Finance and Economics Leading group was
held, focusing on the security of energy. President Xi Jinping attended and emphasised the revolution ofenergy production and consumption, including:

promoting the revolution of energy consumption and restraining unreasonable energy consumption;
promoting the revolution of energy supply and setting up multiple supplying system;
promoting the revolution of energy technology and pushing the industrial upgrading; promoting therevolution of energy management system and smoothing the way of energy development; andenhancing the international energy co-operation and realising energy security under the conditions of
open-up policy.

On 28 November 2014, an ultra-large auxiliary platform for workers for offshore oil drilling, named
the POSH XANADU, was completed in China and is ready to be handed over to overseas customers. 750
people can live and work on the floatel, the largest of its kind in the world (SCC, 2014d).
On 21 May 2014, China Natural Petroleum Corporation and Gazprom signed an agreement to purchaseand transport natural gas from Russia to P.R.C. through the East pipeline. According to the contract, thepipeline will run from 2018, and the final capacity is 28 bcm per year, the value of the contract would be
about 400 billion US dollars (NEA, 2014a).
On 20 November 2014, the Sichuan-Tibet grid-connection project came into operation. This project
would enhance the reliability of Tibet grid and the total cost is more than 1 billion US dollars (CEN, 2014a).
On 23 November 2014, the first unit came into run in Zangmu hydro power plant, the first large-scale hydropower plant in Tibet with 510 MW in capacity totally (CEN, 2014b).
On 27 November 2014, more than 14 GW of renewable energy connected to the grid in Gansu
province, which the largest in China in terms of capacity. Currently, the capacities of wind and solar power
are around 9.5 GW and 4.6 GW respectively, and is likely to reach 17 GW and 7.5 GW at the end of 2015
(CEN, 2014c).
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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 7.1 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 2012, the per capita GDP of Hong Kong, China was 49 303(USD 2010 at PPP), among the highestof the APEC economies. GDP increased 1.6% in real terms in 2012to 352.8 billion (USD 2010 at PPP). The
services sector remained the dominant driving force of overall economic growth, accounting for 90.0% of
GDP in 2012 (EDMC, 2014). Hong Kong, China is driven by its financial services, as well as its higher
value-added and knowledge-based services. To stay competitive and attain sustainable growth, Hong Kong,
China not only needs to restructure and reposition itself in the light of the 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 the advantages of ‘one country, two systems’. As
part of the liberalisation of trade in goods under CEPA, all products originating in Hong Kong, China enjoy
tariff-free access to mainland China by local manufacturers.
With the support of mainland China under CEPA and the Framework Agreement on
Hong Kong/Guangdong Co-operation, 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 the goal of basically achieving liberalisingtrade in services between the mainland and Hong Kong by the end of the National Twelfth Five-Year Plan
period, starting with pilot programs in Guangdong. Hong Kong, China will enhance government-togovernment co-operation and economic partnership with provinces and municipalities in the Mainland on
all fronts, and maintain ties with its trading partners and related international organisations around the world
to expand its markets (Policy Address 2013, 2014).
Table 1: Key data and economic profile, 2012
Key dataa

Energy reservesb

Area (sq. km)

1 104

Population (million)

7.1

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

GDP (USD (2010) billion at PPP)

352.9

Coal (million tonnes)–

GDP (USD (2010) per capita at PPP)

49 303

Uranium (kilotonnes U)–

Source: (EDMC, 2014).
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 13.8 Mtoe in
2012, about the same amount as in 2011. Coal maintained the highest share of the total primary energy
supply (53.3%), followed by oil (22.6%), gas (18.3%) and other sources (5.8%) (EDMC, 2014).
In 2013, the total installed electricity generating capacity in Hong Kong, China was 12 624 MW (EDMC,
2014). 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 Power supplies electricity fromits 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 and Castle Peak power
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stations. CLP Power has arrangements with the China National Offshore Oil Corporation and thePetroChina International Company for gas supplies from the Mainland. HKE’s electricity is supplied by theLamma Power Station, which has a total installed capacity of 3 737 MW. Natural gas used at HKE’s power
station is mainly imported through a submarine pipeline from the Dapeng liquefied natural gas (LNG)
terminal in Guangdong, mainland China. HKE has also operated wind turbines 800 kW since 2006, and aphotovoltaic (PV) system (1 MW) since 2010 (PAH, 2013a, 2013b).
While natural gas and liquefied petroleum gas (LPG) are the main types of gaseous fuels used in Hong
Kong, China, there is another product available. 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, 2014).

FINAL ENERGY CONSUMPTION
In 2012, the total final energy consumption in Hong Kong, Chinawas 6 837 ktoe, an increase of 1.6% fromthe previous year. The other sectors (residential and commercial) accounted for the largest share of energy
used at 63.1%, followed by the transport sector (31.8%) and the industry sector (5.1%). By energy source,
electricity and others made up 54.7% of end-use consumption, followed by petroleum products (35.4%)(EDMC, 2014).
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, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

352 Totala

Indigenous production

67 Industry sector

Net imports and other28 056 Transport sector

2 175

Thermal

Total PES

13 823 Other sectors

4 311

Hydro

–

Coal

7 288 Total FEC

6 837

Nuclear

–

Oil

3 234

Coal

Geothermal

–

Gas

2 374

Oil

2 418

Others

–

Other

928

Gas

677

Electricity and other–38 75038 7503 742

a. Total does not include electricity generated by hydro and nuclear energy facilities located in mainland.
Sources: (EDMC, 2014).

ENERGY INTENSITY ANALYSIS
Hong Kong, China’s energy intensity is lowest in terms of primary energy or final energy demand among
APEC economies. The primary energy intensity in 2012 is only 39.2 tonnes of oil equivalent per million
USD (toe/million USD), compared with the median value of 122.0 toe/million USD in APEC economies,
while the final energy demand is only 19.4, compared with the median value of 72.2 tonnes of oil equivalent
per million USD (EDMC, 2014).
Hong Kong, China endeavours to develop sustainably and fully supports the APEC’s Honolulu
Declaration in 2011, seeking to reduce 45.0% of energy intensity by 2035. To step up energy efficiency andconservation, various policies are implemented, such as Mandatory Energy Efficiency Labelling Scheme,
Building Energy Efficiency Ordinance, Building Energy Efficiency Funding Schemes and District Cooling
System (EMSD, 2013).

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Table 3: Energy Intensity Analysis, 2012

EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

40.0

39.2

-2.0

Final Energy Demand

19.4

19.4

0.0

Industry

1.0

1.0

-1.6

Transportation

6.2

6.2

-0.8

Others

12.2

12.2

0.6

Source: (EDMC, 2014).
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 pursued four key energy policy objectives: to ensure the energy
needs of the community are met safely, efficiently and at reasonable prices, while minimising theenvironmental impact of electricity generation. The Government also promotes the efficient use andconservation of energy. In combating climate change, reducing greenhouse gas emissions and developing a
low-carbon economy, Hong Kong, China’s emissions reduction strategy emphases the wider use of cleaner
and low-carbon energies and fuels in power generation.
In keeping with the free market economic policy of Hong Kong, China, the Government intervenes
only when necessary to safeguard the interests of consumers, ensure public safety and protect 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, the present ones signed in 2008, to encourage energy efficiency, quality services and renewableenergy 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. Both fuel mix options could help us achieve ourpledged environmental targets for 2020 in respect of reduction in carbon intensity and air pollutant
emissions. That is, to reduce carbon intensity by 50.0-60.0% by 2020 when compared to 2005; and to reduceSO2 emissions by 35.0%-75.0%, NOx by 20.0%-30.0% and respirable suspended particulates (RSP) by
15.0%-40.0% by 2020 when compared to 2010. Hong Kong, China will also endeavour to enhance energy
efficiency, promote green buildings, advocate electricity savings, facilitate low-carbon transport, reducing
wastes and develop facilities to turn waste into energy (ENB, 2014).
A major target for the economy’s energy policy is to reduce its energy intensity by 25.0% by 2030, basedon the 2005 level. The key measures are:


Reduce carbon emissions through the use of clean fuel and improved energy efficiency;Promote the energy efficiency of buildings and products;



Promote renewable energy, including waste-to-energy;Seek input from the community to improve energy efficiency; andEnhance the management of electricity demand.
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
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co-operation between the Mainland and Hong Kong over the long term, which will include efforts toprovide 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, bringing gas from Central Asia; andA liquefied natural gas (LNG) terminal to be located in Shenzhen, mainland China.

The MOU also contemplates the ongoing supply of nuclear-generated electricity to Hong Kong, China.
An extension of the Guangdong Daya Bay Nuclear Power Station joint venture and supply contracts wasapproved by the Hong Kong, China Government in September 2009. These contracts will enable thecontinued supply of non-carbon-emitting electricity to Hong Kong, China for a further term of 20 years
from 2014 (CLP 2012a, 2012b).
ENERGY EFFICIENCY
Buildings consume about 90.0% of the electricity used in Hong Kong, China. The economy is putting its
efforts into conserving building energy as its first priority. Efforts will go into improving public awarenessof 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, as they seek improvements in their energy consumption systems (EMSD,
2012d).
BUILDINGS
To strengthen its efforts to improve the effects of building energy conservation, the Government hasenhanced the regulatory system for building energy efficiency. The Buildings Energy Efficiency Ordinance
was fully implemented on 21 September 2012. The three key requirements of the Ordinance are as follows(EMSD, 2012a):The developers or building owners of newly constructed prescribed buildings should ensure that thefour 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).



Responsible persons of prescribed buildings (i.e. owners, tenants or occupants, etc.) should ensure thatthe four key types of building services installations comply with the design standards of the BEC whencarrying out ‘major retrofitting works’.



The owners of commercial buildings, including the commercial portions of composite buildings, should
carry out an energy audit for the four key types of central building services installations in accordancewith the Energy Audit Code (EAC) every 10 years. The first energy audit should be carried out withinfour years of the commencement of the Ordinance in accordance with the timetable set out in Schedule
5 to that Ordinance.

It is estimated that implementation of the Ordinance will result in a savings of approximately 2.8 billion
kWh of electricity and 1.96 million tonnes of carbon dioxide emissions in its first decade. These figures only
take into account the savings achieved from new buildings. It is expected that more savings can be achieved
from existing buildings when carrying out ‘major retrofitting works’ and energy audits (EMSD 2012b). The
BEC and EAC are being reviewed and will be completed in 2015. It is anticipated that it would contribute
more savings in future by tightening of minimum standards.
The Government continues to demonstrate in government buildings state-of-the-art energy efficientdesigns and building energy conservation technologies. These are based on an environmental performanceframework that covers energy efficiency, greenhouse gas reduction, renewable energy application, waste
reduction, water management and indoor air quality. In its effort, all newly built government buildings over
10 000 square metres should aim to obtain not lower than the second highest grade under the Hong Kong
Building Environmental Assessment Method (BEAM).

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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 aims to achieve a 5.0% savings on the total electricity used in government buildings from 2009–10 to2013–14 after discounting activity changes, using electricity consumption in 2007–08 as the baseline.
Also in April 2009, the Government introduced the Buildings Energy Efficiency Funding Schemes,
with a total of HKD 450 million to subsidise environmental performance reviews and upgrades forcommunal areas of residential, commercial and industrial buildings. The Schemes also cover energy/carbon
audits and works to upgrade the energy efficiency performance of building services installations. The subsidy
can cover up to 50.0% of the expenditure. These funding schemes were closed in April 2012 (EMSD 2012a).
Water-cooled air conditioning systems
Water-cooled air-conditioning systems using fresh water-cooling towers are generally more energy efficientthan air-cooled systems. A voluntary Fresh Water Cooling Towers Scheme was launched in 2000 to promotea wider use of fresh water in evaporative cooling towers for air conditioning systems in non-domestic
buildings for energy efficiency. At the end of December 2014, 573 installations were completed under the
Scheme. It is estimated that these installations could save up to about 372 million kWh of electricity, whichis equivalent to the reduction of around 261 000 tonnes of carbon dioxide emissions per annum (EMSD,
2012h).
The Government implements a District Cooling System (DCS) at the Kai Tak Development to supply
chilled water to buildings in the new development for centralised air conditioning. The DCS is the firstproject of its kind implemented by the Government. The core facilities including the plant rooms of the
project were completed and the Kai Tak Cruise Terminal Building and a shopping centre under the Hong
Kong Housing Authority were provided with chilled water in February 2013 (EMSD, 2012i).
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 serve to allow the energy-consuming groups to understand their energy
consumption levels and performance with respect to corresponding peers. They help foster the concept ofefficient energy consumption and promote general awareness (EMSD, 2012c).
ENERGY EFFICIENCY LABELLING
Hong Kong, China has a voluntary Energy Efficiency Labelling Scheme that covers 22 types of household
and office appliances, among which there are 13 types of electrical appliances (refrigerators, washingmachines, non-integrated type compact fluorescent lamps, dehumidifiers, electric clothes dryers, room
coolers, electric storage water heaters, televisions, electric rice-cookers, electronic ballasts, LED lamps,
induction cookers and microwave ovens), seven types of office equipment (photocopiers, fax machines,
multifunction devices, printers, LCD monitors, computers and hot/cold bottled water dispensers) and two
types of gas appliances including domestic instantaneous gas water heaters and gas cookers. The Scheme
was extended to cover petrol passenger cars (EMSD, 2012g).
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, compact fluorescent lamps, washingmachines and dehumidifiers. Under the MEELS, energy labels are required to be shown on the products
for supply in Hong Kong, China to inform consumers of their energy efficiency performance (EMSD,
2012f).
TRANSPORTLand transport accounts for about 17.0% of the total greenhouse gas emissions in the economy, and is thesecond most significant contributor. In order to reduce carbon emissions from the transportation system,
Hong Kong, China, is conducting the following efforts:
EXTEND THE PUBLIC TRANSPORT SYSTEM
An extensive and energy-efficient public transport system in Hong Kong, China is instrumental in helping
to maintain its low level of greenhouse gas emissions. Some 90.0% 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 emphasis on railways.
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PROMOTE CLEANER VEHICLESTo encourage the use of cleaner vehicles, the Government launched tax incentive schemes for environmentfriendly petrol private cars from April 2007. Vehicles meeting the energy efficiency and exhaust emissions
criteria can have the First Registration Tax (FRT) reduced. The current FRT reduction rate is 45.0%, subject
to a cap of HKD 75 000 per car. In addition, the Government actively promotes wider use of electricvehicles. The FRT of electric vehicles is waived till end of March 2017.
PROMOTE ELECTRIC VEHICLESThe Government liaised with the electric vehicle manufacturers and dealers to encourage them to introduce
electric vehicles into Hong Kong and as a result leads in electric vehicle use. The Government has beenworking with the private sector in expanding the electric vehicle charging infrastructure in Hong Kong.
There are now more than 1 100 EV charging points for public use including over 150 medium charging
points and 31 quick charging points. Funding was provided for franchised bus companies to purchase 36
single-deck electric buses and also six double-deck hybrid buses for trial.
PILOT GREEN TRANSPORT FUND
To encourage the transport sector to test green and innovative transport means and technology, in 2011 theGovernment set up a HKD 300 million Pilot Green Transport Fund for which the transport sector canapply (Policy Address, 2010).
PROMOTE THE USE OF BIODIESEL AS 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 and introduced in 2010 a regulatory control for motor vehicle biodiesel to help
safeguard its quality and build up drivers’ confidence in the fuel.
RENEWABLE ENERGY
Despite geographical and natural constraints in developing wind energy, both power companies (CLP Powerand HKE) in the economy have started to explore the feasibility of offshore wind farm projects.
CLP Power is continuing the feasibility study for an offshore wind farm. An offshore meteorological windmast was installed to collect site environmental data. CLP Power completed the renewable energy powersystem of about 200kW on Town Island in late 2012. The system now consists of 672 solar panels and two
wind turbines supplying renewable energy to the Island.
The renewable energy assets of HKE also performed well, with Lamma Winds generating more than 7 000
MWh of electricity since being commissioned in 2006, offsetting more than 6 000 tons of carbon dioxide
emissions. Another 1 MW thin-film photovoltaic (TFPV) solar power system was installed at Lamma Power
Station, generating 1 100 MWh annually (PAH 2013c, 2013d, HKEI 2014).
To increase its renewable energy portfolio, HKE plans to install up to 33 offshore wind turbines at a capital
cost of about HKD 3 billion with a total generation capacity of around 100 MW, producing 175 GWh ofelectricity and offsetting 150 000 tons of carbon dioxide 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 (PAH 2012).
In 2007, a landfill gas processing plant at the North East New Territories landfill started operation, witha peak supply of synthetic natural gas (SNG) from landfill gas at 8 000 m³ per hour. As a result, theconsumption of naphtha at the town gas production plant in Tai Po can be reduced by about 10 000 tonnes,
reducing carbon dioxide emission up to about 31 600 tonnes in 2014 (Towngas 2014).
The Government has taken the lead in using renewable energy by installing a 350 kW PV system on
the roof of the Electrical and Mechanical Services Department headquarters. An 850 kW PV system has
been planned by the Drainage Services Department for installation at Siu Ho Wan Sewage Treatment Works,
scheduled for completion in mid-2016. The Government also installed large-scale solar water heating devices
on government buildings, including swimming pools, to save power in water heating.
In its effort to convert waste to energy and to reduce greenhouse gas emissions, the Government isplanning to construct an integrated waste management facility, two organic waste treatment facilities and asludge treatment facility, expecting them to meet about 1.0% of the total electricity demand by 2020.

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NUCLEAR
Currently, CLP Power has contracted to purchase around 70.0% 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 (CLP, 2012a). This meets some 22.0%of the electricity demand in Hong Kong, China. In September 2009, the Government approved theextension of CLP Power’s contract for the supply of nuclear-generated electricity from Guangdong Daya
Bay Nuclear Power Station for another 20 years from 7 May 2014. The extension of the contract ensures acontinued supply of cleaner electricity to Hong Kong, China, which will help alleviate air pollution andgreenhouse gas emissions locally (CLP, 2012b). To make sure 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 70.0% of its output to approximately 80.0% for late 2014 to 2018 (CLP, 2013).
CLIMATE CHANGE
Hong Kong, China is committed to working closely with the international community to combat climatechange, and the Government is pursuing measures set out in the Hong Kong’s Climate Change Strategy andAction Agenda to reduce the territory’s carbon intensity between 50.0%-60.0% by 2020, with reference to2005 level.
The major contributors of greenhouse gases in Hong Kong, China are power generation and the landtransport sector, accounting for about two-thirds and one-fifth of the territory’s greenhouse gas emissions,
respectively. Also, energy consumption in buildings contributes about 90.0% of total electricity
consumption. Therefore, the Government is focussing on decarbonising the future fuel mix for power
generation, enhancing building energy efficiency and greening the road transport to reduce carbon emissions.
The greenhouse gas emissions reduction measures set out in the Hong Kong’s Climate Change Strategy
and Action Agenda can be classified as follows:
Maximising energy efficiency: In particular, measures to improve energy efficiency in buildings, including
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 by 2020
major electrical equipment in all new commercial buildings will be up to 50.0% more energy efficientcompared with buildings in 2005.

Expanding the use of district cooling or water-cooled air conditioning, so that by 2020 up to 20.0% of
all commercial buildings will have up to 50.0% better refrigeration performance compared withbuildings using regular air conditioners.

Reducing energy demand in new buildings by various means, such as tightening overall thermal transfer
value standards and promoting the wider adoption of green roofing, so that by 2020 all new commercial
buildings will reduce their energy demand by up to 50.0% compared with new buildings in 2005.



Improving energy efficiency in commercial buildings through good housekeeping, information
technology products and intelligent building environmental management systems, so that by 2020 up
to 25.0% of existing commercial buildings will be 15.0% more energy efficient compared with 2005.

Expanding the scope and tightening the energy efficiency of electrical appliance standards for domesticuse, so that by 2020 all appliances sold in the market will be 25.0% more energy efficient comparedwith those sold in 2005.

Greening road transport: Includes 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.



Making wider use of motor vehicles running on alternative fuels, so that 30.0% of private cars, and15.0% of buses and commercial vehicles are hybrid and electric vehicles (EVs) or other vehicles withsimilar performance by 2020.
 Implementing importers’ average fleet-efficiency standards, so that new vehicles will be 20.0% moreenergy efficient than the 2005 market average.

Promoting the use of clean fuels for motor vehicles: Measures to promote clean fuels such as biofuels.
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Turning waste into energy: Measures to explore the potential of renewable energy. Specific measures include:

Developing and fully operating one integrated waste management facility, two organic waste treatment
facilities, and one sludge treatment facility.



Fully utilising recovered landfill gas and gas generated from wastewater treatment.

Revamping the fuel mix for electricity generation: To increase the use of non-fossil, clean and low-carbon
fuels for future electricity generation, having balanced the various objectives of Hong Kong, China’s energy
policyNOTA BLE EN E RG Y D EV EL O PM E NT S
In order to create a more ecologically-friendly environment, the Government has initiated a number ofmajor actions to save energy, reduce carbon emissions and improve waste recovery. Some major actions andachievements are summarised as follows (EPD, 2012a, EMSD 2014):


The CLP Power and its Mainland counterparts have completed construction of the Second West-EastNatural Gas Pipeline (Hong Kong Branch Line) to supply cleaner energy to Hong Kong.



A mandatory energy efficiency labelling scheme for certain products and building energy efficiency
codes for both new and existing buildings were introduced.



An Environmental Impact Assessment report on the development of a 100 MW offshore wind farmin Hong Kong, China was approved in May 2010.

The Buildings Energy Efficiency Ordinance was implemented in September 2012, mandatingcompliance with codes of practice promulgated by the Electrical and Mechanical Services Department
concerning the energy efficiency of four types of buildings services.



High-efficiency equipment (air-conditioning, electrical systems, lifts and escalators, and lighting
installations) has been newly installed and energy audits are being conducted.

The number of electric vehicles in Hong Kong has started to expand with the Government's active
promotion. As at end of December 2014, there are 1 551 electric vehicles in use. .

At the end of December 2014, around 6 400 product models were listed under the Mandatory Energy
Efficiency Labelling Scheme.
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EDMC (Energy Data and Modelling Center) (2013). APEC energy database. Institute of Energy
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H ON G K ON G , C H I N A––––(2012e). Hong Kong Renewable Energy Net. http://re.emsd.gov.hk/eindex.html/
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––––(2014).Social and Environmental Report 2012/2013.
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PAH (Power Assets Holdings Ltd.) (2012). 2012 Sustainability Report––––(2013a). 2013 Interim Results. http://powerassets.com/NR/rdonlyres/0C03D033-F0CA-46AA-A7B4EB0708A0E0B7/0/E_2013_Interim_Results_Highlights.pdf/.
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Policy Address by Chief Executive 2010–11. www.policyaddress.gov.hk/10-11/eng/pdf/policy.pdf.
Policy Address by Chief Executive 2011–12. www.policyaddress.gov.hk/11-12/eng/pdf/Policy11-12.pdf.
Policy Address by Chief Executive 2013. www.policyaddress.gov.hk/2013/eng/pdf/PA2013.pdf/.
Policy Address by Chief Executive 2014. www.policyaddress.gov.hk/2014/eng/index.html/.
TID (Trade and Industry Department, Government of the Hong Kong Special Administrative Region of
the People’s Republic of China) (2011). Mainland and Hong Kong Closer Economic Partnership Arrangement(CEPA). www.tid.gov.hk/english/cepa/legaltext/files/sa7_main_e.pdf/.
Towngas (2014. Hong Kong and China Gas Company Limited (Towngas) Gas Production.
www.hkcg.com/eng/corp/abttg/newenergybus/eco.aspx/.
U SEF UL LI N K S
Census and Statistics Department—www.censtatd.gov.hk
Electrical and Mechanical Services Department—www.emsd.gov.hk
Environnent Bureau—www.enb.gov.hk
Environnemental Protection Department—www.epd.gov.hk
Transport Department—www.td.gov.hk

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INDONESIAI N T ROD U C T I ON

Indonesia is a large archipelago located southeast 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, which includes Indonesia’s exclusive
economic zone. Indonesia’s total land area (24.5% of its territory) is about 1.9 million square kilometres.
The population was 246.9 million in 2012.
Indonesia had a gross domestic product (GDP) of around USD 2,144 billion and a per capita GDP of
USD 8 684 in 2012 (USD 2010 at PPP). Excluding the oil and gas sector, manufacturing industries
accounted for the largest component of GDP in 2012 (25.6%), followed by trade, hotels and restaurants(18.0%); agricultural, livestock, forestry and fisheries (12.5%); transportation and communications (10.1%);
finance, real estate and business services (9.7%); services (9.3%); mining and quarrying (7.4%); construction(6.6%); and electricity, gas and water supply (0.8%). In 2012, Indonesia attained economic growth of 6.2%,
a decrease of 0.3% from 2011 (BPS, 2013).
Domestic oil, gas and coal reserves have played an important role in Indonesia’s economy as a sourceof energy, industrial raw material and foreign exchange. In 2012, oil and gas exports contributed 19.5% andcoal exports contributed 13.8% of Indonesia’s total exports of about USD 190 billion (BP, 2013). Overall,tax and non-tax revenue from oil, gas and minerals including coal accounted for 30.5% of the Indonesian
Government’s budget in 2012 (ESDM, 2013a).
Indonesia’s proven fossil energy reserves at the end of 2012 consisted of 3.7 billion barrels of oil, 2.9
trillion cubic metres of natural gas and 28.0 billion tonnes (Bt) of coal.
Table 1: Key data and economic profile, 2012
Key dataa

Energy reservesb

Area (million sq. km)

1.9Population (million)

246.9

GDP (USD (2010) billion at PPP)
GDP (USD (2010) per capita at PPP)

Oil (billion barrels)

3.7

Gas (trillion cubic metres)

2.9

2 143.9

Coal (billion tonnes)

28.0

8 684

Uranium (kilotonnes U)-

Source: a. (EDMC, 2014); b. Proven reserves at the end of 2012 (BP, 2014).
ENE RG Y S U PPLY AN D DE M A ND
PRIMARY ENERGY SUPPLY
In 2012, Indonesia’s total primary energy supply (TPES) was 184 604 kilotonnes of oil equivalent (ktoe) ofcommercial energy, made up of oil (45.0%), coal (26.2%), natural gas (20.5%) and other energy (mainlyhydropower and geothermal) (8.3%), and 44 834 ktoe of biomass. Indonesia is a net exporter of energy, andoverall energy exports of crude oil, condensates, natural gas, liquefied natural gas (LNG), petroleum
products and coal totalled 228 400 ktoe in 2012. Total energy exports in 2012 slightly increased by 5.0%
from 2011 (10,959 ktoe), an increase driven primarily by coal exports.
OIL
In 2012, Indonesia produced 50 330 ktoe of crude oil and condensates; of this, 17 633 ktoe (35%) was
exported or decreased by 15% compared to 2011’s export. Since oil production has declined significantly
over the past decade (in 1997 Indonesia produced 72 474 ktoe of crude oil and condensates), the economy
imported 14 672 ktoe of crude oil and 31 182 ktoe of petroleum products in 2012 in order to meet its
domestic oil requirements, up 12.2% from total of 41 148 ktoe in 2011 (EDMC 2014).
Most crude oil is produced onshore from two of Indonesia’s largest oil fields: the Minas and Duri oilfields in the province of Riau on the eastern coast of central Sumatra. As 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 69 435 ktoe of natural gas in 2012, a decrease of 4.6% from the 72 796 ktoe produced
in 2011 (EDMC, 2014). Of the total natural gas production, 39.0% was converted to LNG for export
shipping. The economy produced 27 077 ktoe of LNG in 2012, a decrease of 16.1% from 32 283 ktoe in
2011. In 2012, Indonesia also exported 10 219 ktoe of natural gas (14.7% of its total natural gas production)
through pipelines to Singapore and Malaysia (ESDM, 2013b). 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 from
West and East Java. LNG exports from Tangguh, Papua began in 2009 with gas supplied from the onshore
and offshore Wiriagar and Berau gas blocks, which are estimated to have reserves of 14 trillion cubic feet(Tcf).
COAL
In 2012, Indonesia produced 226 909 ktoe of coal, an increase of 9.2% from 207 723 ktoe in 2011. Most ofIndonesia’s coal production in 2012 (178 782 ktoe, or 78.8%) was exported with domestic demand (48 300
ktoe in 2012) being allocated for power generation (64.3%), and industry (35.7%) uses (EDMC, 2014).
About 57.0% of Indonesia’s total recoverable coal reserve is lignite, 27.0% is sub-bituminous coal,
14.0% is bituminous 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,while 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 1.0%).
ELECTRICITY
Indonesia had 45 253 MW of electricity generation capacity in 2012, which was owned by the state-owned
electricity company (PLN) and independent power producers (IPPs). In 2012, 197 328 GWh of electricity
were generated, of which 24.1% was supplied by IPPs and 1.5% was imported from Malaysia. In 2012,
several types of power plants produce electricity, namely coal-steam power plants (48.0%), combined gassteam power plant (20.0%), renewable energy power plants (geothermal, hydro, biomass, solar, and wind)(11.0%), diesel power plants (11.0%), gas power plants (5.0%), gas-steam power plants (3.0%), and oil
powered thermal plants (2.0%) (ESDM, 2013b).
FINAL ENERGY CONSUMPTION
The total final energy consumption was 127 168 ktoe in 2012, an increase of 10.1% from 115 504 ktoe in
2011. The share of final energy consumption by sector in 2012 was 41.9% for industry, 35.1% for transportand 23.0% for other sectors. Indonesia’s economy is highly dependent on oil; final energy consumption ofoil in 2012 was 77 432 ktoe (60.9% of the total final energy consumption) (EDMC, 2014).
Table 2: Key data and economic profile, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous productiona

355 873 Industrial sector

53 279 Total

196 053

Net imports and other–182 244 Transport sector

44 625

Thermal

173 689

Total PES184 604 Other sectors

29 264Hydro

12 799Coal

48 300 Total FEC

127 168

Nuclear–Oil

83 098Coal

17 240

Others

9 565

Gas

37 760Oil

77 432Others15 446

Gas

17 532

Electricity and Others

14 963

Source: EDMC (2014); a. Excludes biomass.
E N E RG Y I N T E N S I T Y

In 2012, Indonesia’s primary energy intensity was 86.1 tonnes of oil equivalent per USD million, a slightdecline of 0.6% from its previous year level. This indicates Indonesia’s energy intensity has improved inrecent years, but there is still room for the economy to improve its energy efficiency. In terms of final energy
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demand, the energy intensity amounted to 59.3 tonnes of oil equivalent per USD million, a 3.6% increase
from 2011, which was mostly driven by increasing energy consumption in other sectors.
Table 3: Energy Intensity Analysis
EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)

Change (%)

2011

2011 vs 2012

2012

Primary Energy

86.6

86.1

-0.6

Final Energy Demand

57.3

59.3

3.6

Industry

25.6

24.9

-3.0

Transportation

19.9

20.8

4.6

Others

11.7

13.7

16.5

Source: (EDMC, 2014).
POLI C Y OV ERVI 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, security of supply, energy conservation,
protection of the environment with regard to energy use, pricing of energy and international cooperation. It
defines the outline of the National Energy Policy (Kebijakan Energi Nasional, or KEN); the roles andresponsibilities 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 will address the sufficiency of energy to meet theeconomy’s needs, energy development priorities, utilisation of indigenous energy resources and energy
reserves. The Energy Law mandates the creation of a National Energy Council (Dewan Energi Nasional,
DEN). Its tasks 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, DEN is headed by the minister
responsible for energy affairs, and it 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 andappointment of members of DEN was finalised in late 2008.
After getting approval from the parliament (the DPR), on 17 October 2014 the government issued the
new National Energy Policy under the Government Regulation No. 79/2014 to replace the existing National
Energy Policy that was established by Presidential Regulation No. 5/2006. This policy is intended to create
energy security and resilience through an energy management policy for period of year 2014 to 2050.
The National Energy Master Plan (RUEN) implements the KEN. By law, RUEN is drafted by thegovernment, namely the Ministry of Energy and Mineral Resources, in a process that involves the related
ministries and other government institutions, state-owned companies in the energy sector, and regional
governments, as well as academia and other energy stakeholders, with due regard to input from the public.
In order to give guidance how to drafting the National Energy Master Plan, the Government has just issued
the Presidential Regulation No. 1/2014 on 2 January 2014. Under this regulation, RUEN should be preparedbased on the National Energy Policy, engagement of the local government, and considering the 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 to promote an increased role for business in the energy supply chain, in termsof 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.
In 2004, the Constitutional Court rejected an advanced reform of the electricity sector, which would
have established the possibility of direct competition in power generation through Law No. 20/2002(currently annulled).
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. Explorationand production activities were conducted based on a fiscal contractual system that relies mainly on
production sharing contracts (PSCs) between government and private investors, which may include foreignand 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
was in conflict with the Constitution of 1945 and ordered its dissolution. At the time of this writing, thegovernment is drafting a new Oil and Gas Law that will determine a new industry structure and until thislaw can be enacted, an Interim Working Unit for Upstream Oil and Gas Business Activities (SKSPMIGAS)
has been established under the Ministry of Energy and Mineral Resources (MEMR) to take over all BP Migas
roles and responsibilities. Furthermore, on 14 January 2013, the government issued Presidential Regulation
Number 9 Year 2013 as the umbrella for the establishment of the working Unit for Upstream Oil and Gas
Business Activities (SKKMIGAS) with its tasks in managing the upstream oil and gas business in Indonesia.
BPH MIGAS has supervisory and regulatory functions in the downstream oil and gas sector with theaim of ensuring availability and distribution of fuel throughout Indonesia and the promotion of gas
utilisation in 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,
relinquish its governmental roles to the new regulatory bodies BP MIGAS (now handed over 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 new law on 12 January
2009 as Law No. 4/2009 on mineral and coal mining.
The new Mining Law basically 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 from the central 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 to by both the government and the investor.
By instituting permits, the government expects to be better positioned to promote investments and to
regulate mining.
The law creates greater opportunity for smaller investments in mining and gives regional governments
a greater role in regulating the industry, along with revenue from mining. The Mining Law called forregulations on:Concession areas and concession periods (for exploration permits) and production limits (forproduction permits) in 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;
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I N D ON E S I AAn obligation for foreign companies to divest shares to the government or to state-owned businessand private companies registered in Indonesia;

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

Reclamation and post-mining costs.

A set of government regulations with regard to the Mining Law was completed in 2010 and these are
now operational.
ELECTRICITY LAW
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 aprovisional 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 so had
made it responsible for providing electricity to all parts of Indonesia.
Under the new Electricity Law, the electricity industry will be made up of electricity business entities thatare title holders of electricity supply business licences, or Izin Usaha Penyediaan Tenaga Listrik (IUPTL).
The IUPTL integrates electricity supply, power generation, transmission, distribution or retailing ofelectricity. Indonesia’s electricity systems will retain vertically integrated configurations. However, these willconsist of several licensed systems, such as PLN’s numerous power systems, provincial government-owned
systems (to be established, where necessary), and private sector power systems, each operating within theirrespective business areas. Licence holders of specific electricity supply types (such as the IPPs, as licenceholders in power generation for the supply of electricity to the public) will participate in the verticallyintegrated systems.
By law, the government and regional governments regulate the electricity industry within their respective
jurisdictions and through electricity regulatory authorities. The Electricity Law allows electricity tariffs to bedifferentiated 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 between regions. At the time 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, MEMR issued three government regulations (GR), namely GR No.
14/2012 on electricity supply businesses activity, GR No. 42/2012 on the buying and selling of electricity
across Indonesia’s borders, and GR No. 62/2012 on electricity support businesses.
GEOTHERMAL LAW
Geothermal development activities are defined as mining activities under the Geothermal Law No. 27/2003
and according to the Forestry Law, no mining activities are allowed to occur in protected forest areas(protection and conservation forest); 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 in protected forest areas, the government
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 after the government has changed the schemeof permitting from ‘Geothermal Mining Permit’ to ‘Geothermal Permit’. This new law has stated thatgeothermal energy can be developed in production, protection and conservation forests after getting apermit from the Ministry of Forestry under the category of environmental service use permit.
The new regulation also states that the government sets the tariff on geothermal electricity, offering
incentives to developers as well as affirming that the Central Government holds the authorisation power to
conduct tenders on Geothermal Working Areas (GWA) and then control of the project. The Local
Government, on the other hand, is authorised to utilise geothermal for direct use (other than electricity
generation).
Geothermal exploration and exploitation are based on awarding licences. The process involves the Central
Government offering GWA for competitive bidding to prospective business investors. Public, private andcooperative entities may submit bids on GWA that are being offered. Successful bidders are awarded GWA.
The width of the concession areas will be determined based on the capacity of the individual geothermal
system. The successful bidders have the right to conduct exploration for five years with two extensions of72

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up to one year per extension and 30 years for exploitation from the date that a feasibility study has been
approved by the government. The government can approve extensions to geothermal resources exploitation
permission 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 the electricity 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 28.0% from the previous maximum progressive rate of 30.0%. Tax rates
are to be further reduced to a flat rate of 25.0% in 2010 (ASEAN Affairs, 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 the governments whose economies producehydrocarbons now use PSCs (Johnston, 2008). Several types of PSC have since emerged internationally.
Technically, PSCs do not have the type of royalties that apply 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 etal., 2008). In a PSC, title to the hydrocarbons passes to the contractor at the export or delivery point.
In 1988, Indonesia’s third-generation PSC introduced a new contract feature called first tranche
petroleum (FTP). The contractor’s share of FTP is taxed, and the remaining production is available for cost
recovery. Some industry analysts view FTP as a royalty (Johnston, 1994). Indonesia has other types of joint
contract schemes for oil and gas, such as technical assistance (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, so that it usually covers exploitation only. Operating costs are recovered from production. The
contractor does not typically share in production. A TAC can cover both exploitation and exploration if it
involves an area where the Indonesian government has encouraged exploration. In 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 has been some flexibility in the
production sharing percentage offered;

PSCs now provide for a domestic market obligation for natural gas;BP MIGAS is entitled to FTP of 10.0% of the petroleum production that is not shared with thecontractor;



The profit sharing percentages appearing in the contract are determined on the assumption that thecontractor 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 thesigning 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 25.0% 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
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an agreement between the contractor and prospective buyers is not reached, the contractor may sell its entire
share to the international market.
UPSTREAM
In 2012, the Directorate General of Oil and Gas, the Ministry of Energy and Mineral Resources signed 25
new Production Sharing Contract-PSC. Out of this additional number, PSC under control the upstream oil
and gas implementing agency—BP MIGAS (before being changed to SKKMIGAS) reached about 308 PSCs
at the end of 2012, consisted of 75 oil and gas production, 179 oil and gas exploration and 54 coal bed
methane (SKKMIGAS, 2012).
In order to increase production of oil and gas, SKKMIGAS has made the development of national oil
and gas in the new field through a number of major projects, namely (SKKMIGAS, 2012):
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 (Northwest Natuna) Pte. Ltd.;

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

Ruby – PearlOil (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 5.21 billion litres of heavily subsidised kerosene for household use in those
provinces.
In an extension of the program, 4.7 million three-kilogram LPG canisters were distributed in 2010. As
of May 2011, some 2.4 million three-kilogram LPG cylinders had been distributed. In 2012, the program
expects to distribute 800 000 cylinders with the same characteristics.
COALBED METHANE
Oil and gas laws and regulation also govern coalbed methane. The Directorate General of Oil and Gas has
oversight of business activities in coalbed methane gas development. MEMR issues regulations andestablishes and offers coal methane gas work areas. The Directorate General of Oil and Gas technicallyestablishes and offers coalbed methane work areas, with due consideration given to BP MIGAS’ opinion(since handed over to SKKMIGAS).
Ministerial Regulation No. 36/2008 Regarding Business in Coal Methane Gas regulates coalbed methanedevelopment. The regulation covers exclusive rights and business related to coal methane gas; the methodof determining and the offering of coal gas methane work areas; use of data and information, equipment
and facilities; research, assessment and development of coal gas methane; dispute resolution; ruling on coalmethane gas as an associated natural resource; and the utilisation of coalbed methane for domestic needs.
MINERALS AND COAL MINING
Indonesia’s new Minerals and Coal Mining Law (Law No. 4/2009) replaced the systems of contract of work
(COW) and work agreements for coal mining businesses (PKP2B) with two forms of permits: specifically,mining business permits (Izin Usaha Pertambangan, IUPs) and citizens mining permit (Izin Pertambangan
Rakyat, IPRs), and a contract called the mining business contract (Perjanjian Usaha Pertambangan, PUP).
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The IUPs apply to large-scale mining. The PUP is a contract between the government and a private mining
company, where the government is represented by an implementing body yet to be established.
Under the new law, the mining fiscal regime includes corporate tax under the prevailing taxation law, asurtax of 10.0%, 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 for 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 on transition states that existing contracts will be upheld, but
the specific scheme for the transition of existing concessions is yet to be formulated.
PUBLIC PRIVATE PARTNERSHIP
With the signing of project documents in late 2011, the Central Java ultra-supercritical coal power plant two
1 000 MW will 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 and guarantees 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 throughPrivate Infrastructure Guarantors.
Government guarantees for the PPP Central Java power plant project are an advanced step in
infrastructure development in Indonesia, since it is considered more transparent and accountable. The PPP
scheme to be used for the Central Java power plant project is the Build-Own-Operate-Transfer (BOOT),
which has a concession period of 25 years. Commercial operation is expected to commence at the end of
2016.
GEOTHERMALIn order to promote geothermal development, the government has provided some fiscal incentives forincome tax, value added tax, import duty, and withholding income tax for import under the taxation
regulations (MoF, 2014), as follows:•Tax Holiday, exemption of corporate income tax (from five to ten tax years) and after the period ofcorporate income tax exemption ended, the developers are given reduction 50.0% of corporate income
tax due for two tax years;•

Investment Allowance for Geothermal which facilities are given including reduced net income tax for
30.0% of total investment (5.0% a year for six years); accelerated depreciation; income tax rate 10.0% orlower based on tax treaty on dividend paid to non-resident tax payer; and compensation for losses incertain circumstances. However, the developers may only get one of these two incentives, either Tax
Holiday or Investment Allowance;•

Exemption of Value Added Tax for import of machinery and equipment, not including spare part;•

Exemption of Import Duty for machinery, goods, and materials for construction and development aslong as the machinery, goods, and materials have not been produced in domestic area, have been
produced in domestic area yet its specification do not meet the criteria, and have been produced indomestic area yet the quantity is not sufficient; and•Exemption of Withholding Income Tax Art 22 for import of machinery and equipment, not including
spare part.
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: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;Appointment of an energy manager, energy audits and an energy conservation programme for final
energy users of 6 000 toe or greater;Implementation of energy efficiency standards and energy labelling;

Government incentives in the form of tax exemptions, fiscal incentives on the import of energy-saving
equipment, and low-interest lending rates to encourage investments in energy conservation; and75

APEC E N E RG Y O VE R VI E W 2014

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 stated:Energy source users and energy users who use energy sources and/or energy of 6000 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 6000 toe per
year shall carry out energy management and/or implement energy savings;

Energy conservation programmes consist of short term programmes (improvements in operatingprocedures, maintenance, and installation of simple device controls), medium- to long-term
programmes (increasing efficiency of equipment, and fuel switching), and continuous improvement of
employee or operator awareness and knowledge of energy conservation techniques;An energy audit shall be conducted periodically, on at least the main energy-consuming appliances andequipment at a minimum of once every three years;An annual report on energy management implementation shall be provided by energy source users andenergy users to ministers, governors and regents or mayors within their respective jurisdictions; andGive incentives to energy source users and energy users who have succeeded in reducing their specificenergy consumption by at least 2.0% 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 or mayors within their respective
jurisdictions. Impose disincentives to energy source users and energy users who have not implemented
energy conservation through energy management. These disincentives include written notices tocomply, public announcements of non-compliance, monetary fines (calculated at 5.0% of the cost ofenergy used during the one year reporting period), and/or reduced energy supply for non-compliance(maximum 5.0% of contract capacity for a period of one month, with an extension possible).

As part of the government commitment to increase energy efficiency and conservation, the Ministryof Energy and Mineral Resources 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 lightning by replacing conventional lightningtechnology with energy efficient technology, namely Light Emitting Diode (LED) in urban areas. The SSLI
will be implemented in 22 cities in Indonesia to promote transformational changes in this particular sector.
With improvement, this program will be implemented all over Indonesia. The SSLI has been registered with
UNFCCC’s NAMA in May 2014 to seek international support for implementation. The project has been
attracting several development partner supports, namely the Asian Development Bank, USAID, AFD,
besides being proposed to the NAMA Facility.
Moreover, with regard to energy efficiency, Indonesia has also issued standard and regulation on energy
efficiency in building, namely: National Standard (SNI) No. 03-6390-2011: Energy Conservation for Air
Conditioning System in Building; SNI 03-6197-2011: Energy Conservation for Lighting System in Building;
SNI 03-6389-2011: Energy Conservation for Building Envelope; and SNI 03-6196-2011: Procedure forEnergy Audit in Building. The implementation of this standard is carried out by the Local Government,such as City of Jakarta as part of Governor Regulation on Green Building in Jakarta. Each building, both
existing and the new one, must conform to the green building standard, including energy efficiency in orderto obtain or renew its building permit. Some buildings, new and existing, are also participating in theGreenship Program by Green Building Council Indonesia. The Greenship Program has four criteria, whichare:sustainable building material;water and waste water management;energy efficiency; andwaste management.



Currently, there are 41 new buildings and 3 existing buildings registered under this program.
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APEC E N E RG Y O VE R VI E W 2014

I N D ON E S I ABARRIER REMOVAL
Indonesia is participating in a UNDP–GEF project that involves six developing Asian economies. This
project, Barrier Removal to the Cost Effective Development and Implementation of Energy Efficiency
Standards and Labelling Project (BRESL), has five major programmes promoting energy standards andlabelling: policy making, capacity building, manufacture support, regional cooperation and pilot projects.
As part of promotion of the establishment of a legal and regulatory basis for removing from the market
technologies that are less energy efficient and produce more emissions, and the adoption of high-efficiency
technologies, some of the achievements in 2012 were (UNDP, 2014):
 Regulation No.6/2011 on CFLs, which was issued by the Minister of Energy and Mineral Resources andfollowed by a Technical Guideline which has been signed and released by the Directorate General of
New Renewable Energy and Energy Conservation (DGNREEC);
 Two drafts of ministry regulation on refrigerator and air conditioner labels were submitted to the
DGNREEC and will be the basis for creation of technical guidelines for labels;
 Drafts of energy performance tests on rice cookers and electric fans were finalised and submitted to the
DGNREEC, to be enacted as the Indonesian Standard for Energy Performance;
 Testing protocol of electronic ballast was submitted to DGNREEC to be evaluated and included as
Technical Guideline under ministerial regulation; and Regional feasibility study on CFL conducted based on Australian practices and updated for standard
harmonisation of CFL energy performance.
RENEWABLE ENERGY
On 17 October 2014 the government has issued the new National Energy Policy under the Government
Regulation No. 79/2014 to replace the existing National Energy Policy that was established by Presidential
Regulation No. 5/2006. The aim of this policy is to: Achieve energy elasticity to GDP of less than one by year 2025;
 Achieve reduction of final energy intensity to 1.0% per year up to year 2025; and Realise an optimum primary energy consumption mix where the share of the new and renewable energy
will be at least 23.0% by 2025 and at least 31.0% by 2050.
As part of the government commitment to mitigate climate change, the Ministry of Energy and Mineral
Resources has developed a renewable energy project a Nationally Appropriate Mitigation Action (NAMAs),
specifically, 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, byincreasing the institutional capacity of financial institutions and project developers. Its activities will include
technical assistance as well as financial facilities of the renewable energy developer. In addition to thisproject, Indonesia is currently developing another NAMA project, focusing 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, which made biofuel consumption mandatory from 2009.
It regulates:the utilisation priority of biofuels;

 biofuel categories;
 standards and specifications of quality; price setting; biofuel commerce, as another fuel; directives and oversight; and sanctions.
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APEC E N E RG Y O VE R VI E W 2014

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In order to reduce fuel imports by accelerating the improvement and expansion of biofuels, theGovernment revised Ministerial Regulation No. 32/2008 on 28 August 2013. This regulation sets mandatory
targets for the percentage share of biofuels in the share of total fossil consumption (biofuel blend), as shownin Table 4.
Table 4: Minimum obligations for biofuel use (% blend)
Sector

Sep
2013

Jan
2014

Jan
2015

Jan
2016

Jan
2020

Jan
2025

PSO transport

10

10

10

20

20

25

Non-PSO transport

3

10

10

20

20

25

Industrial andcommercial

5

10

10

20

20

25

7.5

20

25

30

30

30

PSO transport

-

0.5

1

2

5

20

Non-PSO transport

1

1

2

5

10

20

Industrial andcommercial

-

1

2

5

10

20

Industry

1

5

10

20

20

20

Marine

-

5

10

20

20

20

Aviation

-

-

-

2

3

5

Electricity generation

1

6

15

20

20

20

Biodiesel

Electricity
generation
Ethanol

Straight
oil fuelvegetable

Source: (ESDM, 2013). PSO = public service obligation fuel means subsidised fuel.

Until the end of 2012, the realisation of biodiesel (biofuel and bioethanol) utilisation was 544 963 kLor 38.9% from 1 400 000 kL of the mandatory regulation target under Ministerial Regulation No. 32/2008.
GEOTHERMALIn 2012, Indonesia’s total geothermal capacity was 1 341 MW, which is 4.7% of the total geothermal
potential of 28 617 MW (EBTKE, 2013). Indonesia has identified 4 855 MW of geothermal power potential,from existing geothermal plants, through capacity expansion of productive geothermal resources, and fromnew geothermal projects at 51 sites, specifically 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, 2014).
This geothermal power potential will be developed under the 10 000 MW Accelerated Development ofElectricity Generation—Phase II programme, and it is expected that these projects will commence operation
between 2014 and 2022. Of this total capacity, 4 515 MW will be developed by IPPs and 340 MW by PLN.
Under PLN’s Electricity Power Supply Business Plan 2013–2022 (Rencana Usaha Penyediaan Tenaga Listrik, or
RUPTL), a further increase in geothermal capacity by 1 205 MW is expected between 2014 and 2022 (PLN,
2013).
HYDROPOWER
In 2012, Indonesia’s total hydropower capacity was 4 146 MW (including 69 MW of micro and mini hydro),which was 5.5% of the total hydropower potential of 75 GW (ESDM, 2013). Under the 10 000 MW
Accelerated Development of Electricity Generation—Phase II programme 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 Electricity Power Supply Business Plan (RUPTL) also expects an additional 3 891 MW ofhydropower capacity during 2014–22 (including mini hydro and pump-storage plants); of this capacity,
339 MW would be developed by PLN, 1 423 MW by IPPs, and the rest of the project’s 2 129 MW is not
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I N D ON E S I A

yet decided, however private participation is still open for the project. The hydropower capacity addition
includes two pump-storage power plants in Java—specifically the Upper Cisokan (1 040 MW) in West Javaand 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 9 840 MW, or
13.1% 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 to save energy and water within their institutional domains and/or in the domainsof State Owned Business and Regional Government Owned Business within their jurisdiction.
The Presidential Instruction assigns an electricity savings target of 20.0% from the average electricity
use over the six months prior to the Presidential Instruction; fuel savings targets of 10.0% throughregulations to limit use of subsidised fuels; and water savings targets of 10.0% 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; the Ministerof Energy and Mineral Resources is Executive Chief and a member of the National Team; 11 cabinet
Ministers are also members of the National Team. The National Team is supported by the Executing Teamheaded by the Secretary of the National Team.
NUCLEARIn 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, but to date the team has not conducted any significant activities or performed relevanttasks. The legal basis of Indonesia’s nuclear power development includes Law 17/2007 on Long Term
Development, Years 2005–2015, and Government Regulation 43/2006 on Licensing of Nuclear Reactors.
Indonesia has developed an indigenous nuclear fuel cycle, although certain stages are still at thelaboratory scale. 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 kW Triga Mark-II reactor in Yogyakarta; and the Bandung 1000 kW Triga Mark-II
reactor in Bandung. A fourth 10 MW pool-type research reactor is planned for development in the near
future.
Indonesia currently has two prospective uranium mines. The first is the Eko-Remaja prospect of the
Remaja-Hitam Ore Body, a uranium vein in fine-grained metamorphous rock, estimated to contain between
5 000–10 000 tonnes of uranium with a grade ranging between 0.10–0.30. The second is the Riang Tanah
Merah Ore Body, a uranium vein that may contain fewer than 5 000 tonnes of uranium of a grade ranging
between 0.30–1.00. 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 making development uncertain. Hence, the government has
stated that nuclear power will be the last option to achieve Indonesia’s energy demand, which means
prioritising renewable energy sources.
CLIMATE CHANGE
Indonesia strongly supports the objectives of the United Nations Framework Convention on Climate
Change (UNFCCC) to prevent atmospheric concentrations of anthropogenic gases exceeding a level thatwould endanger the existence of life on Earth. To indicate its firm decision and serious concerns 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 boundby the rights and obligations it stipulates.
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As a non-Annex 1 party in the Kyoto Protocol, Indonesia has no obligation to reduce GHG emissions.
However, the Indonesian Government is committed to participating in and cooperating with 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 to reduce GHG
emissions from forestry and the energy sector by 26.0% through domestic efforts, and by up to 41.0%
through cooperation with other economies.
In response to this commitment and the challenges of climate change, the Indonesian government has
set out a roadmap to integrate climate change issues into development planning. The climate change
roadmap will integrate mitigation and adaptation into policy instruments, regulations, programmes, projects,
funding schemes and capacity building in all development sectors. Two initial phases of the roadmap are
the integration of climate change into the Mid-Term Development Plan 2010–2014 (Rencana Pembangunan
Jangka Menengah 2010–2014, RPJM) and the launching of the Indonesia Climate Change Trust Fund
(ICCTF) on 14 September 2009.
The ICCTF is a financing mechanism for climate change mitigation and adaptation within Indonesia’s policy
framework. The ICCTF has two key objectives: Achieving Indonesia’s goal of a low-carbon economy and greater resilience to climate change throughthe facilitation and acceleration of investment in renewable energy and energy efficiency, sustainable
forest management and forest conservation; and reducing vulnerability in key sectors, such as coastal
zones, agriculture and water resources; and Enabling the government of Indonesia to increase the effectiveness and impact of its leadership andmanagement in addressing climate change by bridging the financial gap to address climate change
mitigation and adaptation; and increasing the effectiveness and impact of external finance for climatechange 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 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 programmes, projects andinitiatives by private parties. The Transformation Fund is not a grants fund but a revolving fund, so projects
are expected to generate returns on the fund’s investments.
NOTA BLE EN E RG Y D EV EL O PM E NT S
ELECTRICITYACCELERATED ELECTRICITY GENERATION PHASE I AND PHASE II
The accelerated power development program 10 000 MW Phase I had completed 4 520 MW of new
generation capacity as of the end of November 2012. With regard to project constraints, the Ministry ofEnergy and Mineral Resources has set a new final completion date for the 10 GW Phase I of 2014.
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 68.0% coal, 19.0% geothermal, 10.0%
combined cycle gas and 3.0% hydropower. The two-phase accelerated power development program is
expected to rapidly increase generating capacity, encourage renewable energy utilisation, and at the sametime eliminate oil-based power plants, except in regions where there are no other competitive alternative
energy sources.
The composition of generation capacity mix for Phase II of the 10 GW Accelerated Power Program isrequired to be updated to accommodate the current situation condition. In 2014, MEMR established a new
final energy mix for the 10 GW Phase II, with a total capacity of 17 458 MW, 60.0% of which will be
developed from coal, 28.0% from geothermal, 10.0% from hydropower, and 2.0% from gas. The scheduled
completion date for the 10 GW Phase II is 2022

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HYDROELECTRIC POWER
The Upper Cisokan pumped storage hydroelectric power plant four 260 MW project in West Java received
government loans from the World Bank/IBRD in late 2011. Completion of the project is expected in 2017.
The Upper Cisokan pumped storage hydropower plant will be the first of its kind in Indonesia.
PLN has also secured financing for construction of the Jati Gede hydroelectric power plant two 55 MW
in West Java, Baliem hydroelectric power plant 50 MW in the province of Papua, Asahan III hydroelectric
power plant 174 MW in the province of North Sumatera, Sumatera, and the Merangin hydroelectric power
plant two 175 MW in the province of Jambi, Sumatra.
REGULATIONSPOWER PURCHASES FROM GEOTHERMAL POWER PLANT AND GEOTHERMAL STEAMBY PLNOn 3 June 2014, the government introduced a ceiling price mechanism under the Ministerial Regulation No.
17/2014 to replace the Feed-in Tariff (FiT) scheme, which was introduced in 2012 (the Ministerial
Regulation No. 22/2012). Under this new ceiling price mechanism, the government through the Ministry ofEnergy and Mineral Resources (MEMR), assigns PLN to purchase electricity from geothermal developers
based on price auction results (ceiling price has been set ranging from USD 11.8 cent/kWh to USD 29.6
cent/kWh depending on commercial operation date of the project and the region where the project islocated); and within 6 months after PLN got the assignment to purchase electricity from the government,
PPA must be signed by both parties. If the delay of PPA is caused by disagreement of geothermal price,
independent body to recalculate the geothermal price under the developers cost must be appointed by bothparties. The calculation of 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 HYDRO POWER PLANT BY PLN
On 13 August 2014, the government has established Feed-in-Tariff (FiT) for hydro power plant with thecapacity up to 10 MW through the Ministerial Regulation No. 22/2014. Under the FiT mechanism, PLN is
obliged to purchase electricity from hydro power plant with the capacity up to 10 MW at a predetermined
price. The FiT is set from approximately USD 8.9 cent/kWh to USD 10.6 cent/kWh for the first year to
the eighth year depending on the location of the projects within Indonesia and the voltage connection point;
and it will be decreased to approximately USD 6.3 cent/kWh to USD 6.4 cent/kWh for the ninth year to
the twentieth year depending on the location of the projects within Indonesia and the voltage connection
point.
POWER PURCHASES FROM BIOMASS AND BIOGAS BASED POWER BY PLN
On 16 October 2014, the government established Feed-in-Tariff (FiT) for biomass and biogas-based power
through the Ministerial Regulation No. 27/2014. Under the FiT mechanism, PLN is obliged to purchasebiomass electricity and biogas electricity at a predetermined price (Biomass: from approximately USD 9.6
cent/kWh to USD 12.5 cent/kWh depending on the voltage connection point; and 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 if the project is located in different location areas or islands since there isregional factor (F) with ranges from 1.00 up to 1.60. In addition, there is an incentive to encourage investor
interest in biomass power plants and biogas-based power plants if they are operated as load followers.
REF ER EN CE S
ASEAN (Association of Southeast Asian Nations) Affairs (2008). Indonesia’s Tax Overhaul Seen a Boost.
11 September. http://www.aseanaffairs.com/page/indonesia_s_tax_overhaul_seen_a_boost
BP (2014). Statistical Review of World Energy June 2014. https://www.bp.com/content/dam/bp/pdf/Energyeconomics/statistical-review-2014/BP-statistical-review-of-world-energy-2014-full-report.pdf
BPS (Statistics Indonesia) (2013).Trends of Selected Socio-Economic Indicators of Indonesia, August 2013.
http://www.bps.go.id/booklet/Boklet_Agustus_2013.pdf
EBTKE (Directorate General of New, Renewable Energy and Energy Conservation) (2013). Statistik
EBTKE 2013, December 2013.

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EDMC (Energy Data and Modelling Center) (2014). APEC Energy Statistics 2012, Energy Working Group
November
2014,
InstituteofEnergyEconomics(IEEJ),
Tokyo,
Japan.
www.ieej.or.jp/egeda/database/database-top.html
ESDM (Ministry of Energy and Mineral Resources) (2013a). Laporan Akuntabilitas Kinerja Instansi Pemerintah(LAKIP) KESDM Tahun 2012, March 2013.
http://prokum.esdm.go.id/Lain-lain/Lakip/Lakip%202012%20Komplit.pdf––––(2013b). Handbook of Energy and Economic Statistics of Indonesia 2013.
http://prokum.esdm.go.id/Publikasi/Handbook%20of%20Energy%20&%20Economic%20Statistics%20of%20Indonesia%20/HANDBOOK%20ESDM%202013.pdf––––(2014). Ministerial Regulation No. 32 of the year 2014 regarding the third revision of Ministerial
Regulation No. 15 of the year 2010.
http://prokum.esdm.go.id/permen/2014/Permen%20ESDM%2032%202014.pdf
Johnston D (1994). International Petroleum Fiscal Systems and Production Sharing Contracts.
Johnston D, Johnston D and Rodgers T (2008). International Petroleum Taxation for the Independent Petroleum
Association of America. Daniel Johnston & Co., Inc., Hancock, New Hampshire.
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
PLN (State Electricity Company) (2013). Rencana Usaha Penyediaan Tenaga Listrik 2013–2022 (RUPTL)
PwC (Pricewaterhouse Coopers Indonesia) (2012). Oil & 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) (2012). Laporan Tahunan 2012.
http://www.skkmigas.go.id/wp-content/uploads/2012/08/Laporan-Tahunan-2012.pdf
UNDP (United Nations Development Programme) (2014). Barriers Removal to the Cost-Effective Development ofEnergy Efficiency Standards and Labeling BRESL Indonesia, accessed on November 2014.
http://www.id.undp.org/content/indonesia/en/home/operations/projects/environment_and_energ
y/barriers-removal-to-the-cost-effective-development-of--energy-ef.html
U SEF UL LI N K S
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
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 consists of several thousand islands, the largest of which are Honshu, Hokkaido,
Kyushu and Shikoku. Most of its land area, of approximately 377 800 square kilometres, is mountainous andthickly forested. Japan is the world’s and APEC’s third largest economy after the United States and China.
Its real GDP in 2012 was approximately USD 4 365 billion (USD 2010 at PPP). Japan’s population of 127.6
million people in 2012 had a per capita income of USD 34 222. Japan’s GDP increased by 1.5% in 2012
compared to 2011. Since indigenous energy resources are modest, Japan imports nearly all of its fossil fuels
to sustain economic activity. As of the end of 2011, proven energy reserves included approximately
44 million barrels of oil, 21 billion cubic metres of natural gas and 350 million tonnes of coal.
Table 1: Key data and economic profile, 2012
Key data

Energy reserves (a)Area (thousand sq. km)

377.8

Oil (million barrels)

44

Population (million)

127.6

Gas (billion cubic metres)

20.9

GDP (USD (2000) billion at PPP)

4 365.4

Coal (million tonnes)

350

GDP (USD (2000) per capita at PPP)

34 222

Uranium (kilotonnes U)—

Sources: (EDMC, 2014); a) Proven Reserves at the end of 2011 (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 2012, Japan’s total primary energy supply was about 450.1 million tonnes of oil equivalent (Mtoe), 2.9%
less than in 2011. By fuel types, oil contributed the largest share (47.0%), followed by coal (25.0%) andnatural gas (23.0%). In 2012, net imports of energy sources accounted for 97.0% of the total primary energy
supply. With limited indigenous energy sources, Japan imported about 99.6% of its oil, 99.3% of its coal and
97.2% of its gas.
In 2013, Japan was the world and APEC’s third largest oil consumer after the United States and China(BP, 2014) and almost all of the oil was imported. The bulk of the imports (73.4% in 2013) came from
economies in the Middle East such as the United Arab Emirates, Saudi Arabia, Iran, Qatar and Kuwait (BP,2014). In 2012, the primary oil supply was 212.0 Mtoe, an increase of 5.1% from the previous year.
Japan is endowed with only limited coal reserves (347 million tonnes). Japan is the world’s largest
importer of coking coal for steel production and of steam coal for power generation, and pulp, paper andcement production. Japan’s main steam coal suppliers are Australia, Indonesia, Russia, China, Canada, theUnited States, and South Africa, while for coking coal the main sources are Australia, Indonesia, Canada,
the United States, Russia and China.
Natural gas resources are also scarce in Japan. Domestic reserves stand at 20.9 billion cubic metres andare located in the prefectures of Niigata, Chiba and Fukushima. Domestic demand is met almost entirely byimports in the form of liquefied natural gas (LNG) (BP, 2014), which come from Australia (20.5%); Qatar(18.4%); Malaysia (17.1); Russia (9.8%); Indonesia (7.2%); the United Arab Emirates (6.2%); Brunei
Darussalam (5.8%); Oman (4.8%) and other economies. In 2013, LNG imports to Japan comprised 36.5%of the total world LNG trade. Natural gas is mainly used for electricity generation, followed by reticulationas city gas and use as an industrial fuel. In 2012, the primary natural gas supply was 105.2 Mtoe, an increaseof 10.4% from the previous year.
Japan has 287.327 GW (EDMC, 2014) of installed generating capacity and generated 1 113 149 GWhof electricity in 2012. Electricity is generated from thermal fuels (coal, natural gas and oil—84.6%), nuclear(1.6%) and hydro (7.6%); geothermal, solar and wind technologies produce the remainder (6.2%).
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

83

Power generation(GWh)

APEC E N E RG Y O VE R VI E W 2014

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Indigenous production

25 142

Industry sector

134 538

Total

1 113 149

Net imports and other

436 012

Transport sector

78 169Thermal

941 527

Total PES

450 164

Other sectors

98 875Hydro

84 157

Coal

112 341

Total FEC

311 582

Nuclear17 991

Oil

212 037

Coal

33 310Other

69 474

Gas

105 248

Oil

160 230

Other

20 538Gas

30 841

Electricity andothers

87 201

Source: (EDMC, 2014).

FINAL ENERGY CONSUMPTION
In 2012, Japan’s total final energy consumption was 311.6 Mtoe, or 0.4% less than in the previous year. The
industrial sector consumed 43.0% of the total, followed by the transportation sector at 25.0%. By energy
source, petroleum products accounted for 51.0% of the total final energy consumption, followed byelectricity and other (28.0%), coal (11.0%) and gas (10.0%).
In 2012, energy consumption in the industrial sector decreased by almost 1.6%. The transport sector’s
consumption increased by 0.7%, and the other sector’s energy consumption also increased by 0.4%.
ENERGY INTENSITY ANALYSISAll energy intensity indices in Table 3, from primary energy to final energy demand by sector, show
improvements from 2011 and thus contribute to APEC’s overall aspirational goal of a 45.0% intensity
reduction by 2035 (2005 as base year). Japan’s energy intensity of the primary energy in 2012 was 103.1
tonnes of oil equivalent per million USD, a decrease by 4.3% from 107.71 tonnes of oil equivalent per
million USD in 2011. The energy intensity of the final energy demand increased by 1.8% from 72.7 tonnesof oil equivalent per million USD in 2011 to 71.3 tonnes of oil equivalent per million USD in 2012. The
industry sector shows the largest energy intensity (30.8 tonnes of oil equivalent per million USD in 2012)
and the largest improvement (3.0%), while the energy intensity of the transportation sector and other sectors,
which mainly include the commercial and residential sectors, has decreased by 0.7% and 1.1%, respectively.
Table 3: Energy Intensity Analysis, 2012
EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

107.7

103.1

-4.3

Final Energy Demand

72.7

71.4

-1.8

Industry

31.8

30.8

-3.0

Transportation

18.0

17.9

-0.7

Others

22.9

22.7

-1.1

Source: (EDMC, 2014).
P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORKThe Ministry of Economy, Trade and Industry (METI) is responsible for designing Japan’s energy policy.
Within METI, the Agency for Natural Resources and Energy is in charge of the rational development ofmineral resources, securing stable supplies of energy, promoting efficient energy use, and regulating
electricity and other energy industries. The Nuclear and Industrial Safety Agency, which was responsible forthe safety of energy facilities and industrial activities in METI, was abolished in September 2012. Its
functions in relation to nuclear energy were transferred to the newly-established Nuclear Regulation
Authority (NRA), which is an independent commission body affiliated to the Ministry of Environment(MOE), with the aim of achieving ‘the separation of nuclear regulatory body from promoting agency.’ The84

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Ministry of Foreign Affairs formulates international policies, while MOE is responsible for environmental
and global warming-related matters.
Before the Great East Japan Earthquake in March 2011 and the subsequent Fukushima Daiichi Nuclear
Power Plant Accident, the aim of Japan’s energy policy was to achieve the ‘3E’ goals—energy security,
economic growth and environmental protection (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 programme of action that extends to 2030 and it places considerable
emphasis on achieving energy security. Its five targets are further energy efficiency improvements of at least
30%; increasing the share of electric power derived from nuclear energy to more than 30%–40%; reducing
oil dependence in the transport sector to about 80%; raising Japan’s investment in oil exploration anddevelopment projects; and reducing overall oil dependence below 40%.
The Strategic Energy Plan based on the law was revised in 2007 (METI, 2008). It focused on achieving
the construction of an international framework for energy conservation and countermeasures to global
warming; the establishment of a nuclear fuel cycle at an early stage; the promotion of new energy sources
for electric power suppliers; assurance of a stable supply of oil and other fuels; the promotion of international
cooperation in the energy and environmental fields; and the development of 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 to be revised, if needed. In this revision, two new principles—energy-based economic growth andreform of the energy industrial structure—were added to the three existing principles of energy security,environmental suitability and economic efficiency (METI, 2010). The Strategic Energy Plan aims tofundamentally change the energy supply and demand system by 2030 and has set ambitious targets for 2030:
 Doubling the energy self-sufficiency ratio (18% at present) and the self-developed fossil fuel supply ratio(26% at present) and as a result, raising Japan’s energy independence ratio to about 70% (38% at present); Raising the ratio of zero-emission power sources to about 70% (34% at present); Halving CO2 emissions from the residential sector;
 Maintaining and enhancing energy efficiency in the industrial sector at the highest level in the world; and Maintaining or obtaining top-class shares of global markets for energy-related products and systems.
If the policies in the Strategic Energy Plan are implemented in a strong and sufficient manner, theeconomy’s total energy-related CO2 emissions are expected to be reduced by 30% or more in 2030
compared to the 1990 level. A 30% emissions reduction means that about a half of the reduction that has
to be achieved from the current level to 2050 (80% reduction compared to 1990) will have been realised in
2030.
Following the Great East Japan Earthquake in March 2011 and the subsequent Fukushima Daiichi
Nuclear Power Plant Accident, the Japanese Government decided to review its Strategic Energy Plan. In
June 2012, the Energy and Environment Council of the Japanese government announced ‘Options forEnergy and Environment.’ The Energy and Environment Council showed three scenarios for the share of
nuclear energy in the power generation mix in 2030, namely, (1) a 0% scenario, (2) a 15% scenario, and (3)a 20-25% scenario (NPU，2012).
However, Prime Minister Shinzou Abe, who was inaugurated on 26 December 2012, has stated that thecoalition of the Liberal Democratic Party and Clean Government Party would reconsider the Democratic
Party’s nuclear energy policy. In April 2014, the Cabinet decided to approve the revised Strategic Energy
Plan. This forth plan gives a direction of Japan’s energy policies for medium/long-term (about next 20 years),and it declares that a period from now to 2018-2020 should be a special stage to reform a variety of energy
systems (METI, 2014a). The major principles of energy policy and viewpoints for reform in the fourth plan
are as follows: Renewables (solar, wind, geothermal, hydro and biomass) are promising, multi-characteristic, important
low carbon and domestic energy sources. Japan will accelerate their introduction as much as possible forthe next three years, and then maintain their expansions.
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J AP AN Nuclear is an important base-load power source as a low carbon and quasi-domestic energy source,
contributing to the stability of energy supply-demand structure, based on the premise of ensuring its
safety because of the following perspectives: 1) superiority in stability of the energy supply and efficiency,2) low and stable operation cost and 3) free from GHG emissions during operation.
 Dependency on nuclear power generation will be lowered to the extent possible by energy saving andintroducing renewable energy as well as improving the efficiency of thermal power generation, etc.
 Japan will revaluate coal as an important base-load power source in terms of stability and costeffectiveness, which will be utilised while reducing environmental load (utilisation of efficient thermal
power generation technology, etc.).
 Japan regards natural gas as a main intermediate power source, expanding its roles in a variety of fields,
and also regards oil as an important energy resource as well as raw material for the transport/consumer
sectors and for a peaking power source.
 Energy mix will be shown soon after this plan, taking a number of consideration factors, including therestarting of nuclear power plants, expansion of renewables, etc.
ENERGY MARKETSOILJapan aims to decrease its oil dependency, partly because of its experiences during the oil crises in 1973 and1979. However, oil still accounts for around 40% of Japan’s total primary energy supply and is expected tocontinue to dominate Japan’s future energy supply. Securing a stable supply of oil will remain one of Japan’smajor energy policy issues.
Japan’s oil supply structure is vulnerable to disruption because Japan imports almost all of its crude oil.
In preparation for possible supply disruptions, Japan has created emergency oil stockpiles and independently
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. Japan’s oil stocks are well in excessof the International Energy Agency’s 90-day net import requirements. As of September 2014, Japan held
the equivalent of 204 days of net imports, including state-owned stocks, private sector stocks and joint oil
storage programs with oil producing countries (PAJ, 2014).
Competition in the domestic oil product market continues. 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 thatheavy oil cracking unit capacity at petroleum companies is raised to 13% of total distillation capacity.
The number of service stations in the economy decreased from 59 615 in 1996 to 34 706 in 2013 as aresult of market liberalisation (NPA, 2014). The Provisional Measures Law on Importation of Specific Kinds
of Refined Petroleum Products was abolished in March 2012. In this context, the Japanese Government
aims to establish a fair and transparent market in terms of quality and prices, where oil product retailers areable 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 September 2014. Refining
capacity decreased from 5.27 million barrels/day (mbd) in 1996 to 3.95 mbd in September 2014 (Sekiyu
Tsushinsha, 2013); (PAJ, 2014).
NATURAL GAS
Demand for natural gas has been increasing rapidly over the past two decades. Between 1990 and 2012,
natural gas demand grew at an annual rate of 4.1% (EDMC, 2014). This robust growth is expected tocontinue, partly for environmental reasons and partly due to its ease of use. Since 1995, Japan has undertaken
natural gas market reform in an attempt to lower the cost of gas supply and increase the economy’s industrial
competitiveness in the global market.
Natural gas is supplied almost entirely by imports in the form of LNG. Since Japan has placed priority
on a stable and secure supply of LNG, Japanese LNG buyers have generally been paying a higher price thanbuyers in Europe or the United States under long-term ‘take or pay’ contracts with rigid terms on volume
and price.
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However, Japanese gas and electric utilities are faced with mounting pressure to reduce costs because of
the deregulation of the gas and electricity markets. The utilities have been making efforts to secure LNG
supply on flexible terms that enable them to quickly respond to changes in the market situation and to supply
gas at lower prices.
In addition, Japan has promoted technological developments in the production and processing of
methane hydrate, which is abundant in the ocean areas surrounding Japan and is viewed as a future energy
resource.
COAL
In 2012, 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 for iron, steel, cement, papers and pulp
production. Japan is the second biggest coal importer in the world, accounting for about 14.4% of total
global coal imports in 2012 (IEA, 2013).
ELECTRICITY MARKET
Electricity was the second largest contributor, after the petroleum industry, to the total final energy
consumption in 2012. Increased use of electrical appliances in the home, the widespread use of personal
computers and related information technology in offices, and a shift in industry structure to more servicesbased sectors has driven the steady increase in electricity consumption in recent years.
Japan’s electricity prices have been among the highest of the developed economies. In order to lower
electricity prices and increase industrial competitiveness, Japan has undergone a programme to reform theelectricity sector, through amendments to the Electricity Business Act in 1995, 1999, 2004, 2008, 2013 and 2014,
respectively.
The three main points of the electricity sector reform in Japan after 2013 are as follows (METI, 2013a): First stage: Establishment of the Organisation for Cross-regional Coordination of Transmission
Operators (OCCTO);
 Second stage: Full power retail liberalisation; and Third stage: Legal unbundling of the transmission/distribution sector and full liberalisation of retailelectricity rates.
The amended Electricity Business Act 2013 for the first stage was enacted in 2013, and, on June 27,
2014, the Cabinet decided to approve the Cabinet Order to stipulate the enforcement date of the OCCTO
and other entities as of 1 April 2015.
The amended Electricity Business Act 2013 for the second stage was enacted in June 11, 2014. The
framework for full retail competition is planned to be enforced in about 2016 (METI, 2014b).
As for the third stage, it will be implemented by approximately 2018-2020, and the bills for the third
stage are planned to be submitted in 2015 (METI, 2014b).
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 offer financial support to companies.
In the short term, the government will concentrate on financial support for existing upstream projects
to assist with start-up and continuation. In the mid-term, the government will continue to appropriately
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 is the basis of all energy conservation policies in Japan. It wasestablished in 1979, triggered by the Oil Crisis of 1979. It requires improving the energy efficiency of theindustrial, consumer (commercial and household) and transport sectors. Japan has improved energy
efficiency by approximate 40% after the crisis. The Energy Conservation Law 1979 was partially amended
in May 2013. The amendment includes the expansion of the top runner program; not only energy consuming
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APEC E N E RG Y O VE R VI E W 2014

J AP ANitems but also items, which do not consume energy but contribute to high efficiency or energy conservation,such as building insulation materials, were added to the top runner program.
In 2014, the revised Strategic Energy Plan set these initiatives (METI 2014a):
 Enhancing Japan’s energy efficiency (already at the highest level in the world) through introduction of
the most advanced technologies for replacing equipment in the industrial sector;
 Enhancing support and regulatory measures (including top-runner program) to increase the adoption ofhighly efficient equipment in each sector. Expanding the coverage of the program; now in includes
industrial refrigerators, printers, heat pumps, LED lumps as well as building insulation materials;
 Replacing 100% of lighting with high-efficiency lamps (including LED and organic EL lighting) on aflow basis by 2020 and on a stock basis by 2030;
 Achieving net zero energy with regard to a newly constructed public building by 2020 and to all newly
constructed buildings on average by 2030;
 Raising next-generation vehicles’ share of new vehicle sales to 50-70% by 2030 while promoting
comprehensive measures, including improving traffic flow such as introducing the 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 ISO50001 standard.
RENEWABLE ENERGY
Japan has a system of feed-in tariffs, where electric power companies are obliged to buy electricity generated
from renewable sources at a certain price. Utilities are required to pay attention to the burden on consumers
and implement measures for stabilising the power grid.
In August 2011, the Purchase of Renewable Energy-Sourced Electricity by Electric Utilities Act 2011
was passed by the Diet (Japanese parliament). This Act took effect on 1 July 2012. It obliges electric utilities
to purchase electricity generated from renewable energy sources (solar photovoltaic, wind power, small andmedium-sized hydro power, geothermal and biomass) based on fixed-period contracts with fixed prices.
Table 4 shows prices for the Feed-In Tariff in FY 2014. Solar power prices for the Feed-In Tariff werereduced from the FY 2013 levels (METI, 2014c).
Table 4: Prices for Feed-In Tariff in FY 2014
Renewable Energy
Solar

Prices (JPY per kW)

Years

Over 10 kW

34.56

20

Less than 10 kW

38.00

10

Less than 10 kW

31.00

10

Over 20 kW

23.76

20

Less than 23 kW

59.40

20

38.88

20

From 1,000 kW to 30,000 kW

25.92

20

From 200 kW to 1,000 kW

31.32

20

Less than 200 kW

36.72

20

Over 15,000 kW

28.08

15

Less than 15,000 kW

45.36

15

Methane fermentation gasification

42.12

20

Unused woods

34.56

20

General woods

25.92

20

Waste (excluding woods)

18.36

20

(Double generation)
Onshore Wind

Offshore Wind
Hydro

Geothermal

Biomass88

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Recycled woods

14.04

20

Source: (METI, 2013b); (METI, 2014c). Note: 8% of tax is included.

Costs incurred by the utilities in purchasing renewable energy-sourced electricity shall be transferred toall electricity customers, who will pay a surcharge for renewable energy at a rate proportional to theirelectricity usage. Surcharge for renewable energy is calculated as follows (METI, 2014d):
Surcharge for renewable energy= Monthly electricity consumption (kWh) ×(0.75 JPY/kWh＋Solar added unit price JPY/kWh)
Each 10 Electric Utility Company has a different level for its solar-added price from 0.03 JPY/kWh to 0.05
JPY/kWh.
Electric utilities are obliged to allow grid connections and execute contracts as required for that purpose.
Feed-in tariff (FIT) 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 set by the
Minister of Economy, Trade and Industry and will be based on the recommendations of a newly-establishedindependent committee every year. To promote the generation of renewable energy-sourced electricity,
special consideration shall be given to the profits of renewable energy-sourced electricity suppliers when
decisions are made about the FIT rate for the three years from the enforcement of the Act （METI, 2011).
Table 5 shows the installed generation capacity for each renewable source of energy after the
introduction of FIT （METI, 2013c; METI, 2014). Two year after the introduction of FIT, in total 72 370
MW of generation capacity based on renewable energy has been authorised under the FIT scheme, while
accumulated generation capacity based on renewable energy by the end of June 2012, that is to say, before
the introduction of FIT, was 20 600 MW. This indicates that the generation capacity based on renewableenergy has become 4.5 times since the introduction of FIT. The table shows solar capacity boom in Japan,
98.1% of newly installed capacity after FIT and 95.9% of authorised capacity. Start-up generation capacity
based on renewable energy is 12 559 MW, only 17.4% of the authorised capacity.
Table 5: Installed Generation Capacity by Renewable Energy after Introduction of FIT (Unit: MW)
Introduced and Started-up Capacity

Authorised
Capacity

Before FIT

After FIT

After FIT

Accumulated capacity

July 2012 –July 2012 –by the end of June 2012

August 2014

August 2014

Solar (Residence)

4 700

2 564

3 066

900

9 762

66 356

Wind

2 600

111

1 296

Medium Hydro

9 400

20

285

200

9

35

Biomass

2 300

91

1 317

Geothermal

500

0.26

14

20 60012 55972 370

Solar (Non-Residence)(Over 1 000 kW)
Medium Hydro(Less than 1 000 kW)＊TotalSource: (METI, 2013c); (METI, 2014e).

NUCLEAR ENERGY
Japan’s Nuclear Energy Policy is under review following the Fukushima Daiichi Nuclear Power Plant
Accident. Nuclear power plants in Japan have historically stopped operation for periodic inspections, once
every 13 months in succession, regardless of the Fukushima Daiichi Nuclear Power Plant Accident.
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However, in April 2012, the four units of the Fukushima Daiichi Nuclear Power Plant were decommissioned
and by May 2012 Japan had no operating nuclear power plants.
In July 2012, two nuclear power plants (Ohi units 3 and 4) restarted operations, but stopped operations
again for periodic inspections in September 2013. Since then, Japan has again had no operating nuclear
power plants.
New regulations for nuclear power plants came into force in June 2013. Five Electric Utilities
Companies have submitted application for the re-start of their nuclear power plants to Nuclear Regulation
Authority (NRA). In September 2014, NRA gave the final safety approval to the Sendai Nuclear Power
Plant (2 units) owned by Kyusyu Electric Power Company. The power company continues to make progress
toward the restart, and, on 7th November, the prefectural assembly of Kagoshima passed a petition for it.
CLIMATE CHANGE
In 2007, the Japanese government announced Cool Earth 50, a cooperative initiative with major greenhousegas (GHG) emitters to reduce worldwide emissions by 50% from the current levels by 2050. The actions
required to achieve these goals are set out in the Cool Earth Innovative Energy Technology Programme,
which includes the Innovative Energy Technology Roadmap (METI, 2008b) and the Technology
Development Roadmap (METI, 2008).
At the United Nations Summit on Climate Change in September 2009, then-Prime Minister Yukio
Hatoyama pledged that Japan would cut its GHG emissions by 25% from its 1990 levels by 2020. The target
is premised on the establishment of a fair and effective international framework in which all major
economies participate, and on those economies agreeing on ambitious targets. Japan’s GHG emissions stoodat 1 341.00 million tonnes of CO2 equivalent in 2012 (preliminary figures, an increase of 2.5% compared tothe previous year and an increase of 6.3% compared to the base year 1990) (MOE, 2013).
Japan’s GHG emissions in the first UNFCCC’s commitment period between 2008 and 2012 stood at
1 279.00 million tonnes of CO2 equivalent. Therefore, Japan exceeded its emission target of reducing GHGs
by 1.4%. The carbon sink by forest ecosystems is equivalent to a 3.8% reduction of GHG, while Kyoto
Mechanism Credit is equivalent to a 5.9% reduction of GHG. If these were taken into account, Japan would
be able to achieve an 8.2% GHG emission reduction compared to the levels for 1990) (MOE, 2013).
The Tax for Promotion of Global Warming Countermeasures took effect in 1 October 2012 (MOE,
2012b). This tax is levied on crude oil/oil products, gas and coal (MOE, 2012a). The tax value is JPY
289/ton- CO2 for each kind of product. Revenue from this tax is used for implementing various measures
to promote energy efficiency and renewable energy, as well as the use of clean fossil fuels.
The tax values for crude oil/oil products, gas and coal were raised in phases as follows.
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/ton)

260

520

780

Coal (JPY/ton)

220

440

670

Source: (MOE, 2012a).

At the COP 19 Meeting in November 2013, the Japanese Government, through the Ministry of theEnvironment, announced that Japan would cut its GHG emissions by 3.8% in 2020 compared to those of
2005. This is an aspirational goal of improving energy efficiency, which already stands at the highest level inthe world, by 20%. Moreover, Japan does not take into account the effect of nuclear power plants on
reducing GHG emissions.
NOTA BLE EN E RG Y D EV EL O PM E NT S
THE STRATEGIC ENERGY PLAN
As mentioned in ‘Energy Policy Framework’ part above, in April 2014, the Cabinet decided to approve therevised Strategic Energy Plan. This forth plan gives a direction of Japan’s energy policies for medium/longterm (approximately the next 20 years), and it declares that a period from now to 2018-20 should be a special
stage to reform a variety of energy systems. The government of Japan (GOJ) confirms ‘3E+S’ concept(Energy Security, Economic Efficiency, Environment and Safety) as the basic viewpoint for its energy
strategies. In the plan, GOJ regards renewable as the promising, multi-characteristic, important, low carbon
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J AP ANand domestic energy sources, and accelerates their production as much as possible for the next three years
and maintains their expansion after that. As for nuclear power, GOJ realises that the effort towards
restoration and reconstruction of Fukushima is the starting point for rebuilding Japan’s energy policies, andreaffirms its importance as a base-load, low carbon and quasi-domestic energy source, contributing to thestability of the energy supply-demand structure, based on the promise of ensuring its safety (METI, 2014a).
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U SEF UL LI N K S
Agency for Natural Resources and Energy— http://www.enecho.meti.go.jp/en/
Institute of Energy Economics, Japan—http://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 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 Northeast Asia between China and Japan. It has an area of 99 538
square kilometres and a population of around 50 million people as of 2012. Korea’s population density isvery high, with an average of more than 500 people per square kilometre. 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 andmountains, with wide coastal plains in the west and the south. The climate is relatively moderate with four
distinct seasons. Air conditioning is commonly necessary during the tropical hot summers and buildings
need to be heated during 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 6.6% per year from 1980 to 2012, reaching
USD 1 594 billion (USD (2010) Price and 2010 PPP) in 2012. GDP (PPP) per capita income in 2012 was
USD 31 883, almost six times higher than in 1980. Korea’s major industries include the semiconductor,
shipbuilding, automobile, petrochemicals, digital electronics, steel, machinery, parts and materials industries.
Korea has few indigenous energy resources. It has no oil resources, only 326 million tonnes ofrecoverable coal reserves and 3 billion cubic metres of natural gas. To sustain its high level of economic
growth, Korea imports large quantities of energy products. Korea imported about 90.0% of its primaryenergy supply in 2012. It was the world’s fifth-largest importer of oil and the world’s second-largest importerof both coal and liquefied natural gas (LNG).
Table 1: Key data and economic profile, 2012
Key data

Energy reserves

Area (sq. km)

99 538

Oil (barrels)–

Population (million)

50.00

Gas (billion cubic metres)3

GDP (USD (2010) billion at PPP)

1 594.3

Coal (million tonnes)

326

GDP (USD (2010) per capita at PPP)

31 883

Uranium (kilotonnes U)

3 471.5

Sources: (EDMC, 2014) (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 2012, from 38.3 million
tonnes of oil equivalent (Mtoe) in 1980 to 262.8 Mtoe in 2012. In particular, from 1990 to 2000, the energy
supply increased at an annual average rate of 7.3%, far exceeding the economic growth rate of 6.5% for thesame period. Likewise, the per capita primary energy supply grew from 1.0 tonne of oil equivalent in 1980
to 5.1 tonnes of oil equivalent in 2012. The increase was similar to that of Japan and most European
economies.
In 2012, Korea’s total primary energy supply was 262.8 Mtoe, a 01.0% increase from the previous year.
By energy source, oil represented the largest share (37.0%), followed by coal (29.0%), and gas (17.1%). The
remaining 16.9% of the primary energy supply came from nuclear and hydro energy sources. Korea imported
around 90.0% of its total energy needs in 2012, including all of its oil, 99% of gas requirements and 98.0%
of its coal supply. Energy imports accounted for almost one third of Korea’s total import value in 2012.
The oil supply in 2012 was 97.2 Mtoe, a 3.8% increase from the previous year. In 2012, the economy
imported more than 80.0% of its crude oil from the Middle East. In the case of coal, its supply in 2012
totalled 76.3 Mtoe, a 4.6% decrease from the previous year. Korea has modest reserves of low-quality, highash anthracite coal that are insufficient to meet its domestic demand. Almost all of Korea’s coal demand istherefore met by imports. Korea is the world’s second-largest importer of both steam and coking coal after
Japan. Main coal imports come from Australia; Canada; China; Indonesia; Russia; and the United States.
Since the introduction of LNG in 1986, natural gas use in Korea has grown rapidly. Gas supply reached45.0 Mtoe in 2012; its share of the primary energy supply was 17.1% in that year. Most of Korea’s LNG
imports come from Qatar, Indonesia, Oman, Malaysia, Brunei Darussalam and Russia’s Sakhalin-2 LNG
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plant. Korea began producing natural gas domestically in November 2004, after a small quantity of natural
gas was discovered in the Donghae-1 offshore field in the south-east of the economy.
Korea’s electricity generation in 2012 was 476.9 Terawatt-hours, a 1.0% increase from 2011. Generationby thermal sources, including coal, oil and natural gas, accounted for 66.8% of the total electricity generated,followed by nuclear at 31.5% and hydro at 1.3%.
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)
Total

Indigenous production

46 040Industry sector

47 461476 890

Net imports and other228 101

Transport sector

30 277

Thermal318 984

Total PES262 763

Other sectors

88 364

Hydro

3 969

Coal

76 309Total FEC

166 104

Nuclear150 327

Oil

97 151

Coal

9 265

Other

3 610

Gas

44 990Oil

84 734

Other

44 312

Gas

22 904

Electricity and other49 201

Source: (EDMC, 2014).

FINAL ENERGY CONSUMPTION
Korea’s total final energy consumption in 2012 was 166.1 Mtoe, a 3.2% increase from the previous year.
The industry sector accounted for the largest share at 28.6%, while the transport sector accounted for 18.2%.
The remainder (53.2%) 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 industry sector
has weakened since the late 1990s, and demand in the transport and commercial sectors has increased.
By energy source, petroleum products accounted for 51.0% of total energy consumption, followed byelectricity and other (29.6%), natural gas (13.8%), and coal (5.6%). Natural gas consumption has increased
significantly due to the economy’s policy measures.
ENERGY INTENSITY ANALYSIS

Table 3: Energy Intensity, 2012
EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

167.0

164.8

-1.3

Final Energy Demand

103.2

104.1

0.9

Industry

30.4

29.8

-2.0

Transportation

18.9

19.0

0.5

Others

540.0

55.0

2.7

Sources: (EDMC, 2014).

The growth of Korean GDP of 2.3% in 2012 resulted in 1.3% improvement in the economy’s total
primary energy supply. This could be translated to an economy-wide energy intensity level of 2.2 tonnes ofoil equivalent per USD million USD. For final energy demand, energy intensity level increased by 0.9%
from 2012 level of 103.2 tonnes of oil equivalent per million USD to 104.2 tonnes of oil equivalent per
million USD in 2012. On per sector analysis, the industry registered the largest reduction of 2.0% in energy
use per USD million of GDP from a year ago level of 30.4 tonnes of oil equivalent per million USD to 29.8
tonnes of oil equivalent per million USD. The transport sector posted a lower intensity at 19.0 tonnes of oil
equivalent per million USD, a increase of 0.5% from its previous year’s level. The other sectors’ energy
intensity also went up by 2.7% from 2012 level.

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P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORKIn the past, Korea’s energy policy focused on ensuring a stable energy supply to sustain economic growth.
The government is now seeking a new direction in energy policy with the aim of supporting sustainable
development that fully considers the 3Es (energy, economy and environment).
The responsibility for energy policy development and implementation is divided between a number ofgovernment institutions. The Ministry of Knowledge Energy (MKE) is the primary government body forenergy policy.
In 2006, the Korean Government established the National Energy Committee, which is chaired by thepresident and includes government and non-governmental experts. The committee’s role is to deliberate
and mediate major energy policies and plans. In addition, it discusses the National Basic Plan for Energy,
emergency preparedness, foreign energy resource development, nuclear energy policy, the coordination ofenergy policies and projects, the prevention and settlement of social conflict related to energy issues, thetransportation of and physical distribution plan for energy, the effective execution of the energy budget, andenergy issues within the United Nations Framework Convention on Climate Change.
As part of its liberalisation efforts in the energy sector, in 2001 the government established the Korea
Electricity Commission (KOREC) 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, which monitors monopoly problems and unfair
business practices in the energy sector.
The Korea Energy Economics Institute (KEEI) develops energy policies related to the production ofenergy statistics, as well as demand and supply overviews, energy conservation and climate change, thepetroleum industry, the gas industry, the electricity industry, and the new and renewable energy industry,
among others. It is financed directly by the government.
The Korea Institute of Energy Research (KIER), funded by the government, is Korea’s major energy
technology research institute. KIER’s mission is to contribute to an economy-wide economic growth bydeveloping industrial core energy technologies and deploying outcomes.
The Korea Energy Management Corporation plays a key role in achieving Korea’s research anddevelopment (R&D) policy goals for energy efficiency, energy conservation, clean energy, and new andrenewable energy technologies. It also manages R&D planning and financial support and management.
In August 2008, faced with high energy prices and rising concerns over climate change, Korea
announced a long-term strategy that will determine the direction of its energy policy until 2030.
On 14 January 2014, Korea launched ‘The 2nd Energy Basic Plan,’ which is the main legal plan inenergy sector with a timeframe up to 2035. According to the 2nd energy plan, the total primary energy
demand is projected to grow at an annual average rate of 1.3% between 2011 and 2035. Final energy demand
will grow at 0.9 % per year. Energy intensity is expected to drop from 0.3 in 2011 to 0.2 in 2035 with an
improvement of 1.4% per year, resulting in 30% improvement of energy intensity, which is equivalent to13.3% reduction in the final energy consumption.
The government proposes six major policy agenda as follows: Shift to Energy Management-Oriented Policy;
 Building a Power Generation System based on Distributed Generations (DGs);
 Pursuit of Harmonisation between the Environment and Safety;
 Pursuit of Harmonisation between the Environment and Safety;
 Building a Stable Energy Supply by Source; and Pursuing of Energy Policy along with People.
Heavy dependence on the Middle East for its crude oil supply has led the economy to a policy of diversifying
its oil supply during the outlook period. The state-owned Korea National Oil Corporation (KNOC) willcontinue to be responsible for the economy’s preparedness for an oil emergency situation by operating oilstockpiling facilities and pursuing stakes in oil projects around the world.
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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 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, Korea Electric Power Corporation.
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, the government announced there would be no further privatisation of KEPCO and its five subsidiaries.
At the end of 2009, 51.0% of KEPCO, as a holding company, was owned by the Korean Government.
KEPCO is still a dominant player in the electricity sector, controlling 94.0% of total power generation and
100.0% of transmission and distribution in Korea (KEPCO, 2009).
The Korean Government has also made moves to restructure the gas industry. In November 1999, thegovernment sold 43% of its equity in the KOGAS and developed the Basic Plan for Restructuring the Gas Industry
to further promote 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 how to achieve the smooth succession of the existing import and transportation contracts, theprivatisation of import and wholesale businesses, stabilise prices and balance supply and demand, and therevision of related legislation and enforcement (KEEI 2002).
Regarding competition in the import and wholesale sectors of KOGAS, a final decision on whether tosplit 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 tobe maintained. Competition in the retail sector, which is currently operated under a monopoly system withineach region, will be introduced in stages, in conjunction with the progress made in the wholesale sector. Asof the end of 2011, no decision on the liberalisation of the gas market had been made.

OIL, GAS AND ELECTRICITY MARKETSOIL
Due to Korea’s dependence on oil imports, the government has been trying to secure supplies for the shortand long terms. To ease short-term supply disruptions and to meet International Energy Agency (IEA)
obligations, the Korean Government has been increasing its oil stockpile since 1980. At the end of August
2011, Korea held 117 million barrels in strategic reserves and had already purchased 2.3 million barrels, or
94.0% of that year’s purchase target. Korea aims to build its strategic reserves to 141 million barrels,
stockpiled at nine locations across the economy, by 2013. The economy-wide stockpile capacity substantiallyexceeds the IEA’s 90-day requirement.
The state-controlled Korea National Oil Corporation has been actively exploring and developing oil
and gas, both locally and abroad, 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 active in the oil and gas sector, as well as the downstream market and wholesale imports
areas.
To encourage private companies to invest in development projects overseas, the Korean Government
has expanded its policy of supplying long-term, low-interest loans through the Special Account of Energy
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, but the economy’s dependency on oil imports from the Middle
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East remains high (84.5% in 2009). Korea is also actively strengthening its bilateral relations with oilproducing economies as well as its multilateral cooperation through the IEA, APEC, the Association ofSoutheast Asian Nations (ASEAN)+3, the International Energy Forum and the Energy Charter, 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 by creating a collaborative framework on energy
cooperation.
NATURAL GAS
To reduce the economy’s dependence on imported oil, Korea introduced natural gas-based city gas to theresidential sector in the 1980s. Since then, gas use has grown rapidly and has replaced coal and oil in theresidential 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 importer, it also promotes thedevelopment of natural gas resources abroad in such countries as Australia, Uzbekistan and Nigeria.
The Ninth Plan for Long-Term Natural Gas Demand and Supply, finalised by MKE in December 2008,
projected natural gas demand would grow by 0.2% per year from 2007-30. By sector, the city gas sector’s
demand for natural gas is projected to increase by 2.0% per year, while the demand for gas for power
generation is projected to decrease by 3.8% per year.
The Korean Government is considering new reforms for the gas industry, with the introduction of gasto-gas competition by unbundling imports and sales activities from the operation of terminals andtransmission facilities, and by instituting an open access regime for receiving terminals and the transmission
network.
ELECTRICITY
Due to 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 2009, installedcapacity increased by more than threefold from 21 GW in 1990 to 78 GW in 2009.
The Fourth Basic Plan of Electricity Demand and Supply (2008–22), finalised by MKE in December
2008, projects that electricity demand will grow by 2.1% per year from 2008-22 and an additional capacityof 33.6 GW will be required by 2022. When decommissioning is taken into account, this translates to about
101 GW of total generation capacity for that 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.
To rectify an energy supply and demand structure that is overly dependent on oil, the construction ofoil-fired power plants was strictly controlled and the development of nuclear, coal and natural gas electricity
generation units was promoted. Gas-fired power plants were first introduced in 1986. During the period of
the Fourth Basic Plan, 12 nuclear-energy power plants, seven coal-fired power plants, and 11 gas-fired power
plants are planned for construction. Korea has been building nuclear-energy power plants since the 1970s
as nuclear energy is a strategic priority for the government. Its share of total electricity production capacity
is projected to increase to 32.6% in 2022.
FISCAL REGIME AND INVESTMENTIn December 2009, the Korean Government approved tax reforms to foster a business-friendly
environment and to promote investment. The tax changes include a reduction in corporate tax rates and anincrease in tax benefits for research and development (R&D).
In 2007, the corporate tax rate was 25.0% on taxable income over KRW 200 million and 13.0% on
taxable income below that amount. Under the tax reforms, these rates were scheduled to be lowered further
from 22.0% in 2009 to 20.0% in 2010, and from 11.0% to 10.0% for the same period, respectively. However,
implementation of the tax rate reduction was postponed until the end of 2011.
To promote investment in R&D that will boost economic growth, the government has increased its tax
assistance for R&D. The new measures include an R&D reserve fund, which will be deductible up to 3% ofsales revenue, an increase in investment tax credits for R&D facilities from 7% to 10% and an increase in
the deduction for R&D grants paid by corporations to universities from 50% to 100%.
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ENERGY EFFICIENCYThe Korean Government has allocated around USD 14.2 billion for an energy efficiency initiative that is
effective until 2012. This initiative aims to improve energy efficiency by 11.3% by 2012 compared with 2007
and to save 34.2 Mtoe. Announced in August 2008, it is part of Korea’s long-term energy plan, which aims
to achieve a 4.6% annual energy efficiency improvement compared to the previous year by 2030.
To meet the target, the government will provide incentives for companies to invest in energy efficiency,
to phase out incandescent lamps by 2013 and to implement a programme modelled on Japan’s Top Runner
Program that will complement the current Energy Efficiency Label and Standard Programme.
RENEWABLE ENERGY
In September 2014, the Korean Government announced the 4th Korea’s National Basic Plan for New andRenewable Energy. According to the plan, Korean government plan to provide 11% of total primary energy
supply with new and renewable energy (NRE) by 2035. Development of solar and wind power as mainenergy sources will allow that 13.4% of total electric energy in Korea will 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 friendlyone.
To realise this vision, the Presidential Commission on Green Growth was established in February 2009.
The Basic Act on Low Carbon and Green Growth was subsequently submitted, and took effect in April
2010. This legislation provided the legal and institutional basis for green growth. To implement the visionof green growth more effectively, the National Strategy for Green Growth was adopted along with the FiveYear Plan for Green Growth in June 2009.
The National Strategy for Green Growth calls for building a comprehensive, long-term (2009–50)
master plan to address the challenges caused by climate change and resource depletion. The strategy consistsof three main objectives and 10 policy directions: Mitigation of climate change and achievement of energy independenceo Effective reduction of greenhouse gas emissions (MKE, 2009b)
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, 2010b)
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, 2010c).
 Improvement in the quality of life and enhanced international standingo Greening the land and water, and building a green transportation infrastructureo Building the green revolution into people’s daily liveso Becoming a role model for the international community as a green growth leader.
To fulfil the policy goals set out in the strategy, the Korean Government is adopting the practice of
five-year planning. Five-year plans are mid-term programmes designed to implement the long-term strategy
for green growth. Table 4 outlines the policy indicators for the first plan for 2009–13 and shows the years
beyond as a reference.
The Five-Year Plan for Green Growth envisages fiscal spending of KRW 107 trillion (USD 86 billion)
for 2009–13. Under the plan, three objectives and 10 policy directions will be implemented in an efficientand predictable manner. The fiscal budget will be mainly spent on R&D in green technology, such as solar
energy and fuel cells, the restoration of the four major rivers and green transportation.

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Table 4: Policy indicators, five-year plan, 2009–2013
Policy indicator

2009

2013

2020

2030

Energy intensity(toe/USD ’000)

0.317

0.290

0.233

0.101

27

42

54

70

Energy independence (%)
Source: (MKE, 2009a).

Roughly 2.0% of the economy’s annual GDP is being allocated to green investment, which is twice theamount recommended in the Green Economy Initiative advocated by the United Nations Environment
Programme (1.0% of GDP). Table 5 shows the rates of green investment in Korea up to 2013.
In its response to climate change, the Korean Government a) has set an economy-wide greenhouse gas(GHG) reduction goal; b) supports voluntary reduction efforts by industry; c) has activated the carbon
market by expanding market mechanisms such as the carbon neutral programme and the carbon fund, andfosters companies that specialise in emissions trading schemes; and d) is considering introducing a system
for the mandatory supply of new and renewable energy focusing on the electricity generation sector. It will
also introduce legal controls in part, such as obligating Renewable Portfolio Agreements based on existing
voluntary agreements.
Table 5: Rates of green investment, 2009–13 (KRW trillion)
Category

Total

2009

2010–20

2012–13

Rate ofincrease
(%)

Total

107.4

17.5

48.3

41.6

10.2

Mitigating climate change andachieving energy independence

56.9

8.6

29.2

19.2

14.0

Creating new engines for economic
growth

28.6

4.8

10.7

13.1

9.4

Improving quality of life and enhancing
international standing

27.9

5.2

10.5

12.2

3.6

Source: (MKE, 2009a).
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 EFFICIENCY
R&D PLAN TO NURTURE THE GREEN INDUSTRY
As part of its efforts to become one of the world’s top-five green energy powerhouses by 2020, Korea
intends to double its budget for energy R&D between now and then. Under a plan announced in November
2011, Korea will strengthen its core technology in the area of green energy and secure 10.0% of the global
market. Technology development and R&D carried out under the plan will effect a 12.0% increase in energy
efficiency and account for half the reduction in emissions needed for Korea to meet its 2020 target of 30.0%
below the business-as-usual level (MKE 2011).
GREENHOUSE GAS EMISSIONS AND ENERGY TARGET MANAGEMENTThe GHG Emissions and Energy Target Management scheme aims to set and implement a target for GHG
emissions reductions that will apply to large public/private emitters.
Controlled entities are selected by their average GHG emission and energy consumption performances
over the last three years. Table 6 shows the suggested GHG emissions and energy standards of specified
controlled entities; the standards will be valid from 2011–14 during the first phase.

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Figure 1: Operational process and roles in GHG emissions and energy target management
The government specifies controlled entities and negotiates to set the target for GHG emissions
and energy consumption.

Controlled entities should submit performance plans and reports to sectoral responsibleorganisationsa in observance of the Low Carbon Green Growth Law.

The government evaluates the reports and issues improvement orders if an entity’s performance
has not reached the target or the reports have not been done adequately.
a. Sectoral responsible organisations: Industry and electricity generation: Ministry of Knowledge Economy;

Building and transport: Ministry of Land, Transport, and Maritime Affairs; Agriculture and livestock:
Ministry for Food, Agriculture, Forestry, and Fisheries; and Waste: Ministry of Environment (mainauthority).
Table 6: GHG emissions and energy standards in Korea of specified controlled entities, valid from2011–14
Concept

GHG
emission

Until 12 December
2011

From 1 January 2012

Company

Businessunit
withincompany

125 000

500

From 1 January 2014

Company

Businessunit
withincompany

Company

Businessunit
withincompany

25 00087 500

20 00050 000

15 000

100

350

90

200

80

(tCO2)
Energyconsumption(TJ)

Source: (Republic of Korea, 2011). Note: 1 TJ = 23.8846 toe; 1 toe = 3.2 tCO2.

To increase the awareness of business and to enhance the acceptability of the system, the government
launched pilot projects for the industry sector from December 2009 to June 2010. Forty-seven companies,
including the top 10 energy consumers in 15 areas, participated in pilot projects. Total energy consumption
for all participating companies accounts for 41.0% of the total energy use in the industry sector.
After the pilot projects, the government selected 471 controlled entities in 2010. GHG emissions fromthose entities account for approximately 60.0% of the total emissions in Korea. These entities also accountfor 40.0% of the economy’s total energy consumption. The industry and power generation sectors are thebiggest consumers, accounting for 80.0%. The number of entities will be increased until 2014.
Table 7: Specified controlled entities in Korea for GHG emissions and energy c onsumption
performances
SectorNo. of entities

Percentage

Industry, power generation

375

79.6

Building, transportation

46

9.8

Agriculture, livestock

27

5.7

Waste

23

4.9

Total

471

100.0

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Source: (Republic of Korea, 2014). Note: Sector estimated and target GHG emission in 2012 (unit: thousand tonnes of
CO2).

The sectoral responsible organisations evaluate the performance of the controlled entities in terms of
GHG emissions and energy consumption, and take any necessary measures, including enforcement notices.
Entities with improvement orders are expected to incorporate the improvements into their new
implementation plans. The government has the right to impose penalties if companies fail to follow thescheme.
The government is focusing on building infrastructure, supporting finance, and supporting small andmedium-sized enterprises to stimulate the early stage of implementing the GHG Emissions and Energy
Target Management scheme.
President Park Geun-hye in October 2013 proposed the ‘Eurasia Initiative’ that calls for linking theenergy and logistics infrastructure across the continent. It would expand ties among Eurasian countries
through connections of energy infrastructure, roads and railways to build the new ‘Silk Road Express,’ which
would run from South Korea to Europe via North Korea, Russia and China.
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EDMC (Energy Data and Modelling Centre) (2014). APEC Energy Database. Institute of Energy
Economics, Japan. www.ieej.or.jp/egeda/database/database-top.html
EIA (Energy Information Administration) (2014). www.eia.doe.gov/emeu/international/reserves.html
KEPCO (Korea Electric Power Generation Corporation) (2014). Annual Report 2014.
KNOC (Korea National Oil Corporation) (2013). Annual Report 2012. www.knoc.co.kr
KOGAS (Korea Gas Corporation) (2013). Annual Report 2012. www.kogas.or.kr
MKE (Ministry of Knowledge Economy) (2008). Energy policies: Promote overseas energy development projects.
www.mke.go.kr/language/eng/policy/Epolicies_02.jsp––––(2009a). ‘Korea unveils national renewable energy plan’. Press release, 20 January 2009. www.mke.go.kr––––(2009b). ‘Korea promises to cut carbon emissions’. Press release, 18 November 2009. www.mke.go.kr––––(2011). ‘Korea announces R & D plan to nurture the green industry’. Press release, 23 November 2011.
www.mke.go.kr
MOTIE and KEEI (2014). Yearbook of Energy Statistics.
http://www.keei.re.kr/main.nsf/index_en.html?open&p=%2Fweb_keei%2Fen_publish.nsf%2FX
ML_Portal_New%2F3F8A294A167D57B249257DC2002C1FA7&s=%3Fopendocument%26men
ucode%3D
Republic of Korea (2011). Statement on Notable Energy Developments. 42nd APEC EWG meeting, October
2011, Chinese Taipei. www.ewg.apec.org
USEFUL LINKS

Korea Electric Power Generation Corporation—www.kepco.co.kr/eng/
Korea Energy Economics Institute—www.keei.re.kr
Korea Energy Management Corporation—www.kemco.or.kr
Korea Gas Corporation—www.kogas.or.kr
Korea National Oil Corporation—www.knoc.co.kr
Ministry of Trade, Industry and Energy—www.motie.go.kr/language/eng/index.jsp
Ministry of Strategy and Finance—http://english.mosf.go.kr/
Statistics Korea— http://kostat.go.kr/portal/english/index.action

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

Malaysia is located in Southeast Asia with a total territory of about 330 803 square kilometers covering thestates in Peninsular Malaysia, the Federal Territories of Kuala Lumpur Putrajaya, and Labuan, and Sabah
and Sarawak on the island of Borneo. Kuala Lumpur is the capital of Malaysia, while Putrajaya is in the seatof the Federal Government (EPU, 2013). In 2012, the economy’s population stood at 29.2 million, whichgrew by 1.7% from the previous year’s level of 28.7 million (WB IBRO-IDA, 2014).
Malaysia’s GDP in 2012 reached USD 627.94 billion (USD 2010 Price and 2010 PPP), an improvementof 5.6% from USD 594.42 billion GDP in 2011 (EDMC, 2013). Among the sectors, services andmanufacturing exhibited the largest contributions to GDP at 54.6% and 24.9%, respectively. However, it
may be noted that the construction sector registered the highest growth at 18.1% compared to its last year’s
performance (MOF, 2014). The main export products of the economy are electrical and electronics (E&E)
products (about 30.0% share to total export), palm oil products (10.0% share), petroleum products (8.0%
share), liquefied natural gas (LNG) (8.0% share), and crude petroleum (5.0% share). The economy’s exports
fell by 5.8% in 2012 from a year ago level due a decrease in E&E and palm oil exports (DOSM, 2013). Withbetter economic performance, GDP per capita (USD 2010 Price and 2010 PPP) likewise improved by 3.9%
from USD 20 669 per person in 2011 to USD 21 476 per person (EDMC, 2014).
Malaysia is endowed with rich energy resources both conventional and renewable energy. In 2012, theeconomy’s oil reserves (including condensate) were 5.9 billion barrels, 40.0% of which is found in Peninsular
Malaysia (Malay basin). The abundant natural gas reserves of the economy are estimated at 2.58 trillion cubic
metres (92.12 trillion standard cubic feet) with nearly 50.0% is in Sarawak basin. On the other hand, the coalreserves deposit, which is assessed at 1 938 million tonnes, is shared mostly by Sarawak and Sabah (EC,2013). Likewise, the economy has vast hydropower potential sites with an estimated capacity of 29 000
megawatts, the majority (85%) of which is found in East Malaysia. Palm oil, wood and agro-industrial wastes
are the main sources for biomass (APERC, 2011).
Table 1: Key Data and Economic Profile, 2012
Key Data

Energy Reserves

Area (sq. km)a

330 803

Oil (billion barrels)—provenc

5.9

29.24

Gas (trillion cubic metres)—provenc

2.58

Population (million) b
GDP (USD (2010) billion and 2010 PPP)b

627.94

Coal (million tonnes)c

1 938

GDP (USD (2010) per capita at PPP)b

21 476

Uranium (million tonnes)

N/A

Sources: a. (EPU, 2013); b. (EDMC, 2014) ; c. (EC, 2013).

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 at 76 621 kilotonnes of oil equivalent (ktoe) in 2012, with a very
nil increase of 0.08% from a year ago level of 76 555 ktoe. Natural gas contributed the largest share at 42.0%(32 222 ktoe), followed by oil with 35.5% share (27 170 ktoe) and coal with 20.6% share (15 796 ktoe).
Meanwhile, other resources including hydro provided a minimal share of 1.9% (1 433 ktoe) to the primaryenergy supply (EDMC, 2014).
The economy also exports energy products, mainly crude oil and petroleum products, LNG andnatural gas. The economy registered total energy exports of 53 230 ktoe in 2012, which was up by 8.3%
from previous year’s level of 49 142. The economy is the second-largest exporter of LNG in the world, andthe second-largest producer of crude oil and natural gas in Southeast Asia (EIA, 2014). In the same year,
energy imports of the economy also increased by 8.7% from 41 244 ktoe in 2011 to 44 823 ktoe (EC, 2013).
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OILMalaysia’s oil reserves are the fourth largest in Asia Pacific, which come mostly from offshore fields. The
economy’s continental shelf is divided into three producing basins, namely: Malay basin in offshore ofpeninsular 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 are light and sweet crude oil (EIA, 2014).
The economy’s average daily oil production was 584.8 thousand barrels per day (mbbl/d) in 2012,around 80.0% of which was crude oil. Malay basin yielded almost 50.0% of total oil production and theremaining was shared by Sarawak and Sabah basins (EC, 2013).
The economy has five (5) oil refineries with a combined capacity of 566 mbbl/day (including
condensate splitter capacity). Petronas, which has three (3) refinery facilities, provided more than 50.0% of
the total daily refinery production. Petrol and diesel accounted for about 70.0% of the total domestic
consumption of petroleum products in 2012. For the same year, the economy imported a total of 13 966
ktoe of petroleum products to meet the growing domestic requirement (EC, 2013).
NATURAL GAS
Most of the gas reserves of Malaysia are in offshore of Peninsular Malaysia in the eastern areas, Sarawak and
Sabah. Most of the economy’s gas reserves are non-associated, while the remaining is associated with oilbasins. Sarawak hosts 47.0% of the total reserves followed by Peninsular Malaysia with 39.0% and Sabah
with 14.0%. In 2012, the average daily natural gas production was at 184.65 million cubic meters per day(mcmd) (6 521 million standard cubic feet per day), lower by 10.7% from last year’s level of 206.7 mcmd
due to decreased production from Peninsular Malaysia and Sarawak gas fields (EC, 2013). Most of the
production came from Sarawak with 60.8% share to total, Peninsular Malaysia with 32.5% share, and Sabah
with 6.7% share. In order to meet the local demand, the economy imported gas via pipeline from Thailand
and Indonesia. As such, natural gas imports picked up by 12.7% during the same year from 6 979 ktoe in2011 to 7 886 ktoe (EC, 2013).
Malaysia has an extensive gas pipeline network running through Peninsular Malaysia and pipelines
connected to offshore fields at the eastcoast of Peninsular Malaysia. The Peninsular Gas Utilisation (PGU)
network, which started in 1984, covers over 2,500 kilometers (km) pipelines composed of main pipelines,
supply pipelines and laterals linking most cities in Peninsular Malaysia and with cross-bordersinterconnections to Singapore and Songkhla, Thailand. The PGU network is comprised of six (6) gasprocessing plants with a combined capacity of 56.2 mcmd (2,000 million standard cubic feet), producing
methane, ethane, butane and condensate (Gas Malaysia, 2012). The PGU is linked to the Trans ThailandMalaysia Gas Pipeline System (Joint Development Area) for additional supply security for Malaysia(Petronas-PGU). The network receives gas from offshore Peninsular Malaysia fields and imports from the
Joint Development Area and West Natuna. Nearly half of the gas from PCU is distributed for power plants
usage, and the rest is consumed for non-power uses in industries and exported to Singapore (Maybank,2012).
The second gas pipeline linking the states of Sabah and Sarawak—the Sabah-Sarawak Gas Pipeline(SSGP)—is under construction and expected to be completed in 2014. The SSGP is one of the componentsof the Sabah-Sarawak Oil and Gas Project, which also includes Sabah Oil and Gas Terminal (SOGT) (EIA,2014). The pipeline system is approximately 521 km (323 miles) in length that will transport 0.28 billion
cubic meters per day (bcmd) (1 billion cubic feet/day) of gas from SOGT in Kinamis, Sabah to Bintulu,
Sarawak for processing into LNG facility for export. Further, the pipeline system will have provisions for
future domestic consumption in Sabah and Sarawak (Petronas-SSGP).
The economy has extensive LNG export facilities and contributed about 10.0% of the world’s LNG
exports (BP, 2013). In 2012, Japan remained the largest importer for the economy’s LNG with about a
62.0% share, followed by Korea with 17.0%, Taiwan with 12.0% and China with 9.0% (EC, 2013).
COAL
Malaysia’s coal resources are mostly made up of bituminous and sub-bituminous coal with estimated reservesof about 1,938 million tonnes, which are found in Sabah and Sarawak. Even with substantial coal resources,
domestic coal production has not been that aggressive since most of the coal deposits are far inland with noadequate infrastructure in place that makes extraction costs high. Likewise, some areas have been declaredprotected areas, such as the Maliau Basin in Sabah, prohibiting coal mining activities. It is only in Sarawak
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2,316,103 metric tonnes production in 2012, Kapit with 600,959 metric tonnes, and Sri Aman with 33,975
metric tonnes (EC, 2013).
In 2012, the economy’s domestic coal consumption decreased slightly by 0.85% from 1 759 ktoe in2011 to 1 744 ktoe. Of the total coal consumption, about 90.0% was consumed by the power generation
sector, while the remainder was consumed by the industry—iron and steel and cement industries. The
economy imports coal to meet its growing requirements from Australia, Indonesia and South Africa (EC,2013).
ELECTRICITY
Malaysia’s total installed power generation capacity in 2012 was recorded at 29 143 MW, a minimal increaseof 1.4% from 2011 level of 28 749 MW. Such an increase in the installed capacity was attributed to theadditional capacity of 300 MW from Bakun hydro project in Sarawak. About 60.0% of the total installedcapacity was owned by the independent power producers (IPPs) and the rest by government-linked utilities,
self-generation and co-generation facilities (EC, 2013).
In the same year, total electricity generation was at 132 493 gigawatt-hours (GWh), an improvementof 5.6% from the previous year’s level. Thermal generation, mostly from natural gas and coal, accounted for
93.0% of the total power generation, while hydropower accounted for the remainder (EDMC, 2014).

FINAL ENERGY CONSUMPTION
Table 2: Energy Supply and Consumption, 2012
Primary Energy Supply (ktoe)

Final Energy Consumption (ktoe)

Power Generation (GWh)

Indigenous production

85 883

Industrial sector

15 310Total

Net imports and other- 8 291

Transport sector

15 146

Thermal123 239

Total PES

76 621Other sectors

14 163

Hydro

9 254

Coal

15 796

Total FEC

44 619

Nuclear–Oil

27 170

Coal

1 744

Geothermal–Gas

32 222

Oil

22 716

Other

–

Other

1 433

Gas

10 147

Electricity and other10 012132 493

Source: (EDMC, 2014).
For full details of the energy balance table, see www.ieej.or.jp/egeda/database/database-top.html.

In 2012, Malaysia’s final energy consumption reached 44 619 ktoe, registering an increase of 2.8%
from a year-ago level. The industry sector was the biggest energy consumer, overtaking the transport sector,
accounting for 34.3% share of the total final energy consumption or about 15 310 ktoe. The transport sector
followed next with 33.9% share or 15,919 ktoe. However, the sector’s energy consumption declined 11.2%
from previous year’s level. The other sectors used by 31.7% of the total, with an increase of 9.2% (EDMC,
2014).
In terms of fuel type, oil was still the most consumed fuel, particularly for the transport sector,
accounting for about half of the total energy demand, followed by gas with 22.7% share, electricity with
22.4% share, and coal with 3.9% share. Oil consumption went down by 5.1% from a year-ago level of 23
943 toe to 22 716 toe. On the other hand, natural gas consumption expanded by 19.8% due to the increasein demand of petrochemical industry (EC, 2013).

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E N E RG Y I N T E N S I T Y A NA LY S I STable 3: Energy Intensity Analysis

EnergyEnergy Intensity (Toe/Million
USD)
2011

2012

Change (%)

2011 vs. 2012

Primary Energy

128.79122.02-5.3

Final Energy Demand

73.02

71.06

-2.7

Industry

22.49

24.38

8.4

Transportation

28.71

24.12

-16.0

Others

21.82

22.56

3.4

Source:(EDMC,

2014).

The economy’s real GDP growth (USD 2010 Price and 2010 PPP) of 5.6% in 2012 resulted in primaryenergy intensity of 122.02 tonnes of oil equivalent per USD million GDP (toe/USD million), a decline of
5.3% from previous year’s energy intensity, while final energy consumption dropped by 2.7%.
By sector, the industry sector consumed more energy per output as the energy intensity accelerated by
8.4%. However, the transport’s energy intensity fell by 16.0% from the level a year ago, which may be
attributed to the increasing use of more efficient alternative fuels or technologies for transport. The othersectors’ energy intensity demonstrated that the higher energy intensity increased by 3.4% from the 2011
level.
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 and consists of the following three (3) 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 diversification of energy supply
from domestic and international sources; The Utilisation Objective: To promote efficient utilisation of energy and to discourage wasteful andnon-productive patterns of energy consumption; and The Environmental Objective: To minimise the negative impacts of energy production, transportation,
conversion, utilisation and consumption on the environment (KeTTHa, 2010).
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 to safeguard and preserve the economy’s energy
resources, particularly its oil and gas resources. Under this policy, total annual production of crude oil should
not exceed 3.0% of “oil initially in place,” which effectively limits the production of crude oil to 650 mbbl/d.
The policy also extended to the production of natural gas imposing a limit of 2000 million standard cubicfeet (56.6 mcmd) in Peninsular Malaysia (UNPAN).
After a year, the economy introduced the Four-Fuel Diversification Policy to expand the fuel mix for
power generation. Initially, the focus of the policy was to reduce the economy’s dependence on oil as thedominant energy source. It likewise aimed to optimise the fuel mix for power generation, which consists offour (4) fuels—oil, gas, coal and hydro. With this policy, the contribution of oil in power generation
significantly reduced and was replaced with gas and coal. The scope of the Four-Fuel Policy was further
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expanded in 2001 through the implementation of the Fifth-Fuel Diversification Policy, which incorporated
renewable energy (e.g. such as biomass, solar and mini-hydro) as the fifth fuel.
In support of the Fifth-Fuel Policy, the National Biofuel Policy was launched in 2006 to diversify fuelfor non-power sectors, specifically for the transport sector, and also to reduce dependence on fossil fuels.
The policy mandates a 5.0% biodiesel blend from processed palm oil with diesel fuel. To ensure effective
implementation of the policy, the economy sets industry quality standards for diesel, as well as encourages
investment in building additional biodiesel plants to stimulate production.
The National Renewable Energy Policy and Action Plan (NREPAP) was formulated in 2009 as thepolicy framework to advancing the development of indigenous renewable energy and expand its
contribution to the power generation mix. The NREPAP provides long-term goals and holistic approachfor sustainable development of renewable energy with the following policy objectives:
 To increase RE contribution in the national power generation mix;
 To facilitate the growth of the RE industry;
 To ensure reasonable RE generation costs;
 To conserve the environment for future generations; and To enhance awareness on the role and importance of RE.
The NREPAP intends to accelerate the renewable energy power capacity to 2,080 MW (11.3 GWh)
by 2020 and 4,000 MW (17.2 GWh) by 2030, contributing 11% and 17% share, respectively, to the total
generation mix. Such targets could bring about an estimated cumulative CO 2 avoidance of 42.2 million
tonnes (mmt) in 2020 and 145.2 mmt in 2030 (APERC, 2014).
The Tenth Malaysia Plan (2011-2015), the government’s latest five-year economic plan published in
10 June 2010, includes the New Energy Policy, which consists of short-and medium-term energy strategies
with emphasis on energy security, economic efficiency, and environmental and social considerations. The
New Energy Policy has identified five (5) strategic pillars: Strategic development of energy supply by diversifying energy resources to include renewable energy
resources, as well as nuclear to be considered as an alternative energy option; Rationalise pricing through adoption of market-based energy pricing; Accelerate energy efficiency implementation;
 Strong governance; and,
 Managing change through integrated approach (EPU, 2010 and 2010b).
ENERGY SECTOR STRUCTURE
Petronas owns Malaysia’s oil and gas reserves. It is a government-owned corporation created under the
Petroleum Development Act of 1974, which holds the exclusive rights for exploration and production of
petroleum, as well as the responsibility for the planning, investment and regulation of the upstream sector.
Foreign and private companies can only operate through a production-sharing contract (PSC) with Petronas.
On the other hand, the economy’s power industry is dominated by three (3) 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 thelargest power utilities, which is publicly listed, while SESB is a subsidiary of TNB with 80% owned by TNB
and 20% by the State Government of Sabah. SEB is wholly-owned by the Sarawak State Government(HAPUA, 2013). Various independent power producers (IPPs), dedicated power producers and cogenerators complement the three utilities.
The key ministries and government agencies for the economy’s energy sector are (APERC, 2014):
 The Energy Planning Unit sets the general direction and strategies for the economy’s energy policies.
 The Ministry of Energy, Green Technology and Water, formulates plans and implements policies,
programmes and projects of the energy sector covering electricity supply, development of renewableenergy and promotion of energy efficiency, among others. Part of its role is the formulation of energy
policy in coordination with the EPU.
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M AL AY S I A The Energy Commission is a statutory body established in 2001 to serve as a regulator for electricity andpiped gas supply industries in Peninssular Malaysia and Sabah. The commission’s main functions are toprovide technical and performance regulations for the electricity and piped gas supply industries, to act
as the safety regulator, and to protect consumers by ensuring the quality of services and the supply ofelectricity and piped gas, and at reasonable prices.
ENERGY SECURITY
The New Energy Policy under the Tenth Malaysia Plan outlines the strategic approaches to improve energy
supply security. One of the measures identified is the diversification of energy resources, specificallyincreasing the contribution of renewable energy in primary energy and power generation mix. Nuclear energy
has also been considered as a possible energy supply option for the economy in the future.
Another measure to improve energy security is through importing liquefied natural gas (LNG). The
economy is confronting the issue of the geographic disparity of the natural gas supply and demand amongits regions. The Western of Peninsular Malaysia is requiring more natural gas supply for power and industrial
uses, while Sarawak and Sabah are producing natural gas but lack local demand. To address these concerns,
LNG Regasification Terminals (RGTs) are being put up to increase the supply security thorugh imports of
LNG from the global gas market (EIA, 2014). The economy completed its first RGT in Malacca (Melaka),
which commenced operation in May 2013 with a capacity of 2 x 130,000 cubic metres with an annual storage
volume of 3.8 million mt (15 mcmd) (Petronas, 2012). The RGT will improve the security of the natural gas
supply in Peninsular Malaysia and can also accommodate LNG importation. The building of a second RGTis planned for Johor in the Peninsular Malaysia as part of the Pengerang Integrated Petroleum Complex(PIPC), which also comprises the Refinery and Petrochemical Integrated Development (RAPID) project.
The PIPC is seen to be the next regional downstream oil and gas industrial hub in Asian region (Petronas,2014). A third RGT is proposed for Lahad Datu in Sabah to fuel a 300-MW power plant (EIA, 2014).
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 to further enhance petroleum security in
the ASEAN region. The ASEAN members through the Trans-ASEAN Gas Pipeline Project (TAGP) andthe ASEAN Power Grid Project (APG) have also entered into interconnection cooperation agreements on
power and natural gas. The TAGP will provide the region with a secure supply of natural gas by way ofinterconnection of gas pipelines and associated infrastructure. The economy 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 for regional sales of electricity, which will also optimise the development ofenergy resources in the region.
GREEN TECHNOLOGY POLICY
In pursuing low-carbon economy, Malaysian government launched the National Green Technology Policy
in July 2009, which serves as the basis for all Malaysians to enjoy an improved quality of life, by ensuringthat the objectives of the national development policies will continue to be balanced with environmental
consideration. The policy is built on four pillars i.e.:Energy – Seek to attain energy independence and promote efficient utilisation;Environment – To conserve and minimise environmental impacts;



Economy – To enhance economic development through the use of green technology;Society – To improve quality of life for all.

Four sectors have been identified as the primary focus of the policy:Energy. 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 demand-side management programs;

Buildings. Adoption of green technology in the construction, management, maintenance anddemolition of buildings;



Water and waste management. Use of green technology in the management and use of water
resources, wastewater treatment, solid waste and sanitary landfill; and,

Transport. Incorporation of green technology into transportation infrastructure and vehicles, inparticular biofuels and public road transport (KeTTHA, 2011).
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M AL AY S I AAmong the policy’s long-term goals include: infuse in the Malaysian culture the green technology andsignificant reduction of energy consumption. Malaysia has joined the global endeavour by earmarking topromoting Green Technology through the establishment of the Ministry of Energy, Green Technology andWater in April 2009 replacing the Ministry of Energy, Water and Communication. In addition, the Malaysian
Energy Centre was restructured into the Malaysian Green Technology Corporation, becoming the leadagency of the Ministry for the promotion, development and implementation of green technology.
The -Green Technology Master Plan is formulated to provide strategic directions for the
implementation of the green technology policy and to realise its aspirations and goals. The Master Plan also
serves as a guiding reference in developing action plans, programmes and projects for the 11 th and 12th
Malaysia Plan.
The Green Technology Financing Scheme (GFTS) launched in 2010 with allocated government fundamounting to MYR 1.5 billion (USD 427 million), is a special financing scheme for soft loans to companies
that produce and utilise green technology. As of the end of December 2012, 102 projects have been granted
certification under GTFS. Due to the overwhelming response on GTFS, the government allocated another
MYR 2 billion (USD 570 million) for the scheme to be utilised until December 2015 (GreenTechMalaysia,
2013). By December 2014, RM 2.04 billion has been approved under the Green Technology Financing
Scheme.
The introduction of) MyHIJAU Labelling Programme will ensure the availability of green products
and services to be on par with international standards and regulations. This includes the National Eco
Labelling Program to certify eco-friendly domestically manufactured products, and the Energy Star Rating
certification for energy-efficient home appliances.
The Green Building Index (GBI) has also been developed as a rating tool to promote green technology
in the building sector. It also intends to raise awareness for developers and building owners to design andconstruct green and sustainable buildings. A GBI certificate is being granted to developers and building
owners who have satisfied the standards in six (6) areas: energy efficiency, indoor environmental quality,
sustainable site planning and management, materials and resources, water efficiency, and innovation.
Building owners acquiring GBI certificates from 24 October 2009 to 31 December 2014 will be given
income tax exemptions equivalent to the additional capital expended in obtaining such certificates.
Meanwhile, buyers purchasing buildings or house with GBI certificates from developers will be given stamp
duty exemptions on instruments of transfer of ownership. Such exemption is the amount equivalent to theadditional cost incurred in obtaining the GBI certificates. The exemption is given to buyers who execute
sales and purchase agreements from 24 October 2009 to 31 December 2014.
Other initiatives being implemented are the Government Green Procurement (GGP) and Green
Township projects. The GGP integrates environmental considerations in the public sector procurement
process to protect the natural environment, conserve resources and lessen the harmful effects of humanactivities. By 2020, the GGP will be implemented in all government offices, and will ensure that 20.0% of
the public sector’s purchases of products and services are green -labelled. The Green Township advocates
for the adoption of “Low Carbon City Framework (LCCF)” by the city councils, developers and town
planners. The project provides a systematic process and strategies for reducing carbon emission in urban
developments (GreenTech-Flagship and Ongoing Projects).
ENERGY MARKETSMARKET REFORM
Malaysia’s energy market is under a regulated environment and the government provides subsidies to energy
consumers. However, the economy will be embarking on implementing energy market reforms as postulated
in the Tenth Malaysia Plan through the gradual removal of energy subsidies. As a strategy to rationalise
subsidies, the plan states that gas prices for both power and non-power sectors will be revised every six (6)months to gradually reflect market-based prices. The approach would be to unbundle energy bills to itemise
subsidy values, which will eventually delink subsidies from energy use. The first round of subsidy cuts forthe power sector’s natural gas prices has been in place since 1 June 2011. As a social safety net, government
assistance in different forms will be extended to low-income households and other groups. To
institutionalise greater market discipline, other measures like separate accounting for generation,transmission and distribution activities, performance-based regulations and review and renegotiation of
power purchase agreements will also be pursued (EPU, 2010).
As part of the market reform and to move towards a better regulation, the Energy Commission
will start to impose Incentive Based Regulation (IBR) on the utility companies. TNB, as the largest utility
company in the economy, will be the first company that need to abide to the IBR which it will be later on
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expanded to other utility companies. IBR is a mechanism or methodology to determine the electricity tariff,
focusing more efficiency gains and a structured process in tariff evaluation. It is considered as an effective
mechanism that being used globally, sometimes called as performance-based regulation. Through the IBR
implementation, only the efficient cost (CAPEX and OPEX) in electricity supply will be accounted in thetariff calculation. The IBR is expected to benefit both, the utility companies as well as the consumer in termsof electricity tariff (EC, 2013).
UPSTREAM ENERGY DEVELOPMENTAs the Malaysia’s oil and gas basins are becoming mature fields, the government, through Petronas, hasintensified exploration efforts in more challenging fronts of underexplored deepwater and ultra-deepwater,high pressure, high temperature (HPHT) and high CO2 fields. In 2013, 100 active production-sharing
contracts (PSC) are in operation as a result of having favourable upstream investment environment—stable
fiscal environment, commercial and tax incentives, infrastructure support, and availability of local-based
service companies that support upstream activities. PSC is a sort of public-private partnership model where
Petronas holds the public responsibility and the contractors take on the private interest. The year also saw
10 new discoveries with estimated additional reserves of 0.98 billion barrel of oil equivalent (boe). To date,
about 30 players are already engaged in upstream activities in the economy, which include eminentinternational oil exploration companies (Petronas, 2013).
To aggressively encourage players to explore and develop marginal fields, Petronas introduced avariation of the PSC in 2011 known as Risk Service Contract (RSC). The RSC involves risk shared between
Petronas, the project owner and contractor. Under this service contract model, the contractors will provide
the upfront capital expenditure (capex), but the capex will be reimbursed upon first commercial production.
The contractor will also be entitled to a Remuneration Fee per barrel from a pre-determined percentage ofthe field revenue. There are already four awarded RSCs with the first RSC (Berantai Field) commenced gas
production in 2012. The other two RCS—the Balai Cluster awarded in 2011 and Kapal Banang Meranti in
2012—also showed significant progress and expected their first hydrocarbon production in 2013 (Petronas,2013).
In 2013, the economy’s total reserves increased slightly by 1.5% to 22.57 billion barrels of oil equivalent(boe) from 22.24 billion boe a year ago. It may be noted that in 2012 total reserves ALSO went up by 4.4%
from its 2011 level. The top two new notable discoveries in 2012 were the Kasawari gas field and Kuang
North. Such accomplishments were achieved through improved gas recovery (IGR), improved oil recovery(IOR) and enhanced oil recovery (EOR) projects.
ELECTRICITY AND GAS MARKETS
Malaysia’s electricity supply industry is monopolistic in nature as it is vertically integrated where each of theutility companies (TNB, SESB and SEB) undertakes generation, transmission and distribution of electricity
in its respective region. However, there are IPPs operating and providing a portion of electricity supply toutility companies. All electricity utilities have government stake—as government-owned or as a main
shareholder. The industry is highly regulated and governed by several institutions (EPU, KeTTHa and ST)
with each having specific functions and jurisdiction.
In view of the global energy prices volatility and declining domestic gas production, the economy willcontinue its efforts to ensuring greater electricity supply and a sustainable electricity supply system as
adopted under the Tenth Malaysia Plan. Further, the Plan also espouses the importance of enhancing
productivity and efficiency of utility providers. Strategies identified in the Plan for having a reliable andstable electricity supply industry include: increasing and diversifying generation capacity; strengthening
transmission and distribution networks; restructuring the electricity supply industry; and, improving
customer service delivery.
In order to increase and diversify its generation capacity, the economy will aggressively develop
alternative sources of energy, specifically hydro, and increase coal and LNG importation by 2015. There areplans to expand the generating capacity of coal-fired power plants in Peninsular Malaysia and Sarawak using
more efficient coal technology, which include supercritical or ultra-supercritical technology. This newtechnology will reduce CO2 emission from coal-fired power plants (EPU, 2010). Nuclear energy will also be
explored as a long-term option for electricity generation. It may be recalled that prior to the Fukushima
incident the economy considered building nuclear power facilities by 2021 (EIA, 2014).
On the other hand, transmission and distribution systems will be expanded and improved to minimise
losses. The System Average Interruption Duration Index (SAIDI) will be put in place by 2015 to enhance
supply reliability from 68 to 50 minutes per customer per year in Peninsular Malaysia. The possible
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M AL AY S I Aapplication of Smart Grid system will be studied and considered to reduce losses and costs, as well as increase
reliability (EPU, 2010).
The gradual reduction of the subsidy for gas would eventually allow for the adoption of a market pricelevel for gas, which is expected to have a significant effect on the electricity supply industry. Currently, gas
for power generation supplied by the Peninsular Gas Utilisation (PCU) pipeline system is heavily subsidisedby the government. Other reforms will likewise be implemented such as the introduction of performancebased regulation, the renegotiation of power purchase agreement, and separate accounting (unbundling) for
generation, transmission and distribution activities.
The use of new technologies and performance-based regulation will be instituted to accelerate deliveryof services by utilities to new and existing customers like faster and better response for new electricalconnections and in restoration of supply interruptions.
In addition, access to electricity supply in rural areas will be extended through grid expansion andalternative systems, such as mini hydro and solar hybrid. By 2015, the coverage of the electricity supply, onhousehold basis, is targeted to be nearly 100% in Peninsular Malaysia and 99% in Sabah and Sarawak (EPU,
2010).
ENERGY EFFICIENCYEnergy efficiency has been an important element in the Malaysia’s plan and energy policy. The Tenth
Malaysia Plan incorporates energy efficiency measures to realise energy savings potential, as well as reduce
CO2 emissions and dependency on fossil fuels. Energy efficiency strategies are categorised per demand
sectors as follows: Residential sector: Phasing out of incandescent light bulbs by 2014 to reduce energy usage and carbon
dioxide emissions. And, increasing energy performance labelling from four (air conditioner, refrigerator,
television and fan) to ten electrical appliances (six additional appliances—rice cooker, electric kettle,
washing machine, microwave, clothes dryer and dishwasher) to enable consumers to make informed
decisions as they purchase energy efficient products.
 Township: Introduction of guidelines for green townships and rating scales based on carbon footprint
baseline and promoting such townships, starting with Putrajaya and Cyberjaya.
 Industrial: Increasing the use of energy efficient machineries and equipment such as high efficiency
motors, pumps and variable speed drive controls. And, introducing minimum energy performancestandards for selected appliances to restrict the manufacture, import and sale of inefficient appliances to
consumers.
 Buildings: Revising the Uniform Building By-Laws to incorporate the Malaysian Standard: Code ofPractice on Energy Efficiency and Renewable Energy for Non-Residential Buildings (MS1525). This
allows for integration of renewable energy systems and energy saving features in buildings. Wider
adoption of the Green Building Index (GBI) to benchmark energy consumption in new and existingbuildings. Increasing the use of thermal insulation for roofs in air-conditioned buildings to save energy(EPU, 2010).
A National Energy Efficiency Master Plan (NEEMP) under formulation with the primary aim ofpromoting and implementing energy efficiency measures in a well-coordinated and cost-effective way in theindustrial, commercial and residential sectors. This is in line with the policy direction of ‘Promoting Energy
Efficiency to Ensure Productive Use of Energy and Minimise Waste to Contribute to Sustainable
Development and Increase Welfare and Competitiveness.’ The NEECMP is crafted based on five major
thrusts, which include: Establishing an overall long-term national plan for energy efficiency; Strengthening implementation capacity to promote energy efficiency;
 Creating adequate and sustained funding mechanism for energy efficiency; Implementing energy efficiency programmes; and Enabling commercial finance institutions to support energy efficiency.
Likewise, the NEEMP proposes five key initiatives on energy efficiency programmes, which are: rating andlabelling of appliances; minimum energy performance standards (MEPS); energy audits and management inbuildings and industries; energy efficient building design; and, a support programme to cover additional
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costs of efficient technology. The overall target of the plan is to reduce electricity consumption by 6.0%
over the 10 years during which the Plan is implemented (APERC, 2011).
RENEWABLE ENERGY
Malaysia’s Fifth-Fuel Policy in 2001 recognised the importance of renewable energy and adopted as the fifth
fuel in the energy supply mix together with natural gas, oil, hydro and coal. Under the Tenth Malaysia Plan,the economy sets a target of 985 MW additional capacity from renewable energy resources by 2015 to comefrom biomass (330 MW), biogas (100 MW), solid waste (200 MW), mini-hydro (290MW), and solar
photovoltaic (65 MW) sources. These capacity additions from renewable are expected to contribute 5.5%
to the total generation mix.
The National Renewable Energy Policy and Action Plan (NREPAP) in 2009 paved the way for theenactment of two (2) important legislations, the Renewable Energy Act 2011 and the Sustainable Energy
Development Authority (SEDA) Act 2011. The primary role of SEDA is to administer and manage theimplementation of the feed-in-tariff (FIT) mechanism as mandated in the Renewable Energy Act 2011. FIT
is a fixed premium payable for each unit of renewable energy sold to distribution utilities, which is aguaranteed return on investments for the RE players. FIT eligible renewable energy resources are biomass,
biogas, small hydro and solar photovoltaic.
CLIMATE CHANGE
Malaysia is a signatory to the United Nations Framework Convention on Climate Change (UNFCC) andratified it on 17 July 1994. The National Climate Committee was established in 1995 composed of various
government agencies and stakeholders from business and civil society groups to guide national responses toclimate change mitigation and adaption. At the 2009 Climate Change Summit in Copenhagen, Malaysia’s
Prime Minister made a pledge for a voluntary reduction of up to 40% of CO2 emission intensity of GDP
by 2020 compared to 2005 levels. However, the reduction is conditional on financial and technical assistancefrom Annex 1 partners (developed countries) corresponding to what is required to realise the goal. To
support the said goal, two significant policies were approved in 2009—the National Green Technology
Policy and the National Climate Change Policy—to strengthen the national agenda on environmental
protection and conservation.
The National Climate Change Policy has three main objectives. First to mainstream measures toaddress climate change through efficient management of resources and enhanced environmental
conservation resulting in strengthened economic competitiveness and improved quality of life. Second,
integration of responses into national policies, plans and programmes to strengthen the resilience ofdevelopment from arising and potential impacts of climate change. Third, strengthening of institutional andimplementation capacity to better harness opportunities in reducing negative impacts of climate change. The
Policy outlines 10 strategic thrusts and 43 key actions based on five principles: Development on a Sustainable Path. Integrate climate change responses into national development
plans to fulfil the aspiration for sustainable development.
 Conservation of Environmental and Natural Resources. Strengthen implementation of climatechange actions that contribute to environmental conservation and sustainable use of natural resources.
 Coordinated Implementation. Incorporate climate change considerations into implementation ofdevelopment programmes at all levels.
 Effective Participation. Improve participation of stakeholders and major groups for effective
implementation of climate change responses.
 Common but Differentiated Responsibilities and Respective Capabilities. International
involvement in climate change issues will be based on the principle of common but differentiatedresponsibilities and respective capabilities (NRE, 2009).
The Tenth Malaysia Plan also stressed the efforts to address the challenges of climate change bydeveloping a roadmap for climate resilient growth covering adaptation and mitigation approaches. In
reducing the economy’s carbon footprints, efforts will focus on the development of renewable energy,
promotion of energy efficiency, forest conservation and solid waste management.

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M AL AY S I ANOTA BLE EN E RG Y D EV ELO PM E NT S
IMPLEMENTATION OF THE B7 (BIODIESEL) PROGRAMME FOR THE
SUBSIDISED SECTOR
B7 programme (blending of 7% palm biodiesel with 93% petroleum diesel) for the subsidised sector will be
implemented in Peninsula in stages beginning November with Sarawak, Sabah and Wilayah Persekutuan
Labuan by December 2014. 4. This programme will consume 575,000 tonnes of biodiesel and it is expected
to contribute towards a savings of 667.6 million litres of diesel a year. The move to implement B7 has
positioned Malaysia at par with other nations in the use of renewable energy sources (MPIC, 2014).
INTRODUCTION OF MANAGED FLOAT SYSTEM FOR FUEL PRICINGThe Malaysian Government announced to completely remove the subsidies for fuel (Petrol RON 95 anddiesel) beginning 1 December 2014. The price of fuel will be fixed accordingly to a managed float system
whereby average price difference in the cost of the fuels in a month would determine the retail prices forthe following month (KPDNKK, 2014).
PENGERANG INTEGRATED PETROLEUM COMPLEX (PIPC)The Pengerang Integrated Petroleum Complex (PIPC) was declared a National Project of Strategic
Importance during the Economic Council Meeting in February 2012 chaired by the Malaysia Prime Minister.
The PICP is being developed as part of the Economic Transformation Programme to establish a dynamic
oil and gas downstream industry. The project is located on a single plot of land (about 8,100 hectares) in
Pengerang, Johor at the south-east tip of Peninsular Malaysia, which is strategically accessible to majorinternational shipping lanes. 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 PICP will house oil refineries, naphtha crackers, petrochemical plants, LNG import terminal anda regasification plant. As of January 2013, two projects have been committed in the PICP area. The first is
the Pengerang Independent Deepwater Petroleum Terminal (PIDPT), a deepwater oil terminal that is
expected to be completed by 2020 with planned total storage capacity of five million cubic metres. Oil
refineries in PICP will be value added to imported crude oil through PIDPT. The other project is the
PETRONAS’s Refinery and Petrochemical Integrated Development (RAPID), which will include a 300
Mbbl/d crude oil refinery to provide feedstock for the RAPID’s petrochemical complex as well as produce
gasoline and diesel that meet European specifications. (MPRC, 2013)
On April 2014, PETRONAS made an announcement on the Final Investment Decision (FID) for thedevelopment of the PIPC with a total investment of USD27 billion inclusive of RAPID’s development andother facilities. (PETRONAS, 2014)
NEW ENERGY POLICY STUDY (2013-2050)
The Economic Planning Unit (EPU) of the Prime Minister’s Office conducted a study for the formulationof an energy policy for Malaysia covering a longer horizon of 2013-2050. The objectives of the study are: toconduct a comprehensive review of energy and energy-related policies; formulate a long-term energy policy
for Malaysia; and to develop the implementation plan for the energy sector. Seven working groups were
established to study the broad issues in the energy sector comprising of energy security and emergency, gas
and LNG, power, energy efficiency, transport, refining and petrochemicals, energy security, and evengovernance. The study’s initial findings revealed opportunities for improvement that need to be addressedin the proposed policy. The final report of this study will include an implementation plan, policy
recommendations and an energy balance model. The results of this study are expected to be part of theEleventh Malaysian Plan that currently is being drafted by the Economic Planning Unit. The Eleventh
Malaysian Plan is expected to be unveiled by middle of 2015 by the Government of Malaysia. (EPU, 2013b).

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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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http://aperc.ieej.or.jp/file/2014/6/2/PRLCE_Report_Malaysia_Endorsed_by_EWG_20140526.pd
f–––– (2011). Peer Review on Energy Efficiency in Malaysia, May 2011.
http://aperc.ieej.or.jp/file/2013/7/23/PREE_201105_Malaysia.pdf
BP (BP Statistical Review of World Energy) (2013).
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DOSM (Department of Statistics, Malaysia) (2013). Malaysia External Trade Statistics, 2012.
www.statistics.gov.my/portal/images/stories/files/LatestReleases/trade/bi/Dec12/External_Trade_Dec12_BI.pdf
EC (Energy Commission) (2013). National Energy Balance 2012.
http://meih.st.gov.my/documents/10620/717f207d-1308-4d2c-b5e1-9f84b24d2e0b–––– (2013). Review on Electricity Tariff in Peninsular Malaysia under the Incentive-based Regulation
Mechanism (FY2014-FY2017). http://www.st.gov.my/index.php/en/download-page/category/107briefing-session-on-electricity-tariff-in-peninsular-malaysia-19-december2013.html?download=427:briefing-session-on-electricity-tariff-in-peninsular-malaysia-19-december2013
EDMC (Energy Data and Modelling Center) (2014). APEC Energy Database, Institute of Energy
Economics, Japan. www.ieej.or.jp/egeda/database/database-top.html
EIA (US Energy Information Agency) (2014). Malaysia Country Analysis Brief. September 2014.
http://www.eia.gov/countries/analysisbriefs/Malaysia/malaysia.pdf
EPU (Economic Planning Unit) (2013). Malaysian Economy in Figures 2013.
http://www.epu.gov.my/documents/10124/1e9cd2e5-67a8-4b6c-b530-b1448a6a1475–––– (2013b). Highlights of the New Energy Policy Study (2013-2050), presentation at the 5th National
Energy Forum on 3 September 2013.
http://www.malaysiangas.com/portal/document/publication/1378911948_PanelD1_Dr.pdf–––– (2010). Tenth Malaysia Plan 2011-2015.
http://onlineapps.epu.gov.my/rmke10/rmke10_english.html–––– (2010b). Speech of the Prime Minister on Tenth Malaysia Plan. 10 June 2010.
http://www.epu.gov.my/en/c/document_library/get_file?uuid=902fde99-06fa-4361-8737b671d2261a46&groupId=283545
Gas Malaysia (2012). ‘Peninsular Gas Utilisation Project’ website page,www.gasmalaysia.com/about_gas/peninsular_gas_utilisation_project.php
GreenTech (Malaysia Green Technology Corporation) (2013). Annual Report 2012.
http://www.greentechmalaysia.my/file/download/GTM-%20Annual%20Report%202012.pdf–––– Flagship and Ongoing Projects.
http://www.greentechmalaysia.my/content.asp?zoneid=2#.VEm0TfmUdig–––– Introduction to GTFS.
http://www.greentechmalaysia.my/content.asp?zoneid=16&articleid=52#.VJpFFF4AKw
Hapua (Head of ASEAN Power Utilities/Authorities Council) (2013). Malaysia Country Report,
http://www.hapuasecretariat.org/doc2013/Country_Reports/05_Malaysia_Country_Paper_HAPU
A_2013.pdf
KeTTHa (Ministry of Energy, Green Technology and Water) (2014). National Energy Efficiency Action
Plan (2014)
http://www.kettha.gov.my/kettha/portal/document/files/NEEAP%20For%20Comments%20Fina
l%20January%202014.pdf–––– (2011). NGTP (National Green Technology Policy).
http://www.kettha.gov.my/portal/index.php?r=kandungan/index&menu1_id=3&menu2_id=75&
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M AL AY S I A–––– (2010). National Energy Policy
http://www.kettha.gov.my/portal/index.php?r=kandungan/index&menu1_id=2&menu2_id=26&
menu3_id=110#.VEDh5_mSxig
KPDNKK (Ministry of Domestic Trade, Co-Operatives and Consumerism) (2014), Price of RON 95 On
Managed Float. http://kpdnkk.bernama.com/newsEn.php?id=1087114
Maybank (2012), Oil and Gas Sector Update, January 2012, www.maybank-ib.com/pdf/Oil and Gas
Sector 2012.pdf
MOF (Ministry of Finance) (2014). Economic Report 2013/2014.
http://www.treasury.gov.my/index.php?option=com_content&view=article&id=2735:laporanekonomi-2013-2014&catid=262&Itemid=2478&lang=ms#
MPIC (Ministry of Plantation Industries and Commodities( (2014), Implementation of the B7 Programme.
http://www.kppk.gov.my/index.php/utama/sumber/press-statement-2013/3565-implementationof-the-b7-programme-blending-of-7-palm-biodiesel-with-93-petroleum-diesel-for-the-subsidisedsector.html
MPRC (Malaysia Petroleum Resources Corporation). Pengerang Integrated Petroleum Complex.
http://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.http://www.nre.gov.my/msmy/PustakaMedia/Penerbitan/Dasar%20Perubahan%20Iklim%20Negara.pdf
PETRONAS (2014). “Petronas Reaches Final Investment Decision for Pengerang Integrated Complex,”
Press Release
http://www.petronas.com.my/media-relations/media-releases/Pages/article/PETRONAS-REACHESFINAL-INVESTMENT-DECISION-FOR-PENGERANG-INTEGRATED-COMPLEX.aspx–––– (2013). Petronas Annual Report 2013. http://www.petronas.com.my/investorrelations/Pages/annual-report.aspx#–––– (2012). “Malaysia’s First LNG Re-gasification Terminal Reaches Completion,” Press Release
http://www.petronas.com.my/media-relations/mediareleases/Pages/article/MALAYSIA%E2%80%99S-FIRST-LNG-RE-GASIFICATIONTERMINAL-REACHES-COMPLETION.aspx–––– PGU. Peninsular Gas Utilisation Project. http://www.petronas.com.my/our-business/gaspower/gas-processing-transmission/Pages/gas-processing-transmission/peninsular-gasutilisation.aspx–––– SSGP. Sabah-Sarawak Gas Pipeline Project. http://www.petronas.com.my/our-business/gaspower/gas-processing-transmission/Pages/gas-processing-transmission/sabah-sarawak-integratedoil-gas-project.aspx
UNPAN (United Nations Public Administration Network) (1999). Sustainable Energy Policy andStrategies: A Pre-Requisite for the Concerted Development and Promotion of the Renewable Energy
in Malaysia. http://unpan1.un.org/intradoc/groups/public/documents/apcity/unpan003226.pdf
WB IBRO-IDA (World Bank IBRO-IDA). World Population Ranking. September 2014.
http://data.worldbank.org/data-catalog/Population-ranking-table
U SEF UL LI N K S
Prime Minister Office—www.pmo.gov.my
Economic Planning Unit, Prime Minister’s Department—www.epu.gov.my
Energy Comission—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
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Sabah Electricity Sdn.Bhd.—www.sesb.com.my
Sarawak Energy Berhad—www.sarawakenergy.com.my
Tenaga Nasional Berhad—www.tnb.com.my

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

The United Mexican States (Estados Unidos Mexicanos in Spanish), more often known simply as Mexico, is afederal republic located in North America, bordered by the United States to the north, by Belize andGuatemala to the South and by the Atlantic and Pacific Oceans. Owing to its cultural settings and historicroots, Mexico is also one of APEC’s three Latin American economies.
Mexico has an approximate land area of 2.0 million square kilometers rich in biodiversity and natural
resources that include oil and gas. The economy’s climatic conditions range from very dry with hightemperatures in the north, to very humid with high temperatures in the south, mild temperatures in thecenter and warm on the coasts. According to official statistics (CONAPO, 2014), Mexico’s total population
by mid-2013 amounted to 118.4 million, and it is expected to grow to 150 million by 2050. According to theWorld Bank the total population in 2013 was slightly higher, with about 122.3 million that put Mexico in
the 11th place among worldwide economies, and the sixth in APEC after China, United States, Indonesia,
Russia and Japan (World Bank, 2014).
Within its territory, Mexico City not only is the capital city but represents as well one of the largest
urban centers in the world, with more than 20 million inhabitants living in an area that includes Mexico’s
Federal District and 60 surrounding municipalities spanned in other two Mexican States (INEGI, 2013).
After Mexico City, the economy’s most important cities are Guadalajara and Monterrey, which arerespectively located in the west-central and northeastern side of the territory.
Mexico’s economy is mainly composed by crude oil exports, remittances (mostly from the US),
manufacturing and tourism, with the Mexican Peso (MXN) as its currency. The economy’s growth between
2000 and 2012 has been meager, rising at an annual average rate barely above 2.0%, with Mexico’s real grossdomestic product in 2012 amounting to USD 1 878 billion in USD 2010 on a PPP basis- (EDMC, 2014).
As of recently, and due to the accomplishment of significant political, fiscal and economic reforms, Mexico’s
economy has been stronger, growing 4.0% from 2011 to 2012 (EDMC, 2014). In line with these structuralchanges, official projections expect annual growth rates in Mexico’s gross domestic product to reach 3.7%
by 2014, 4.9% by 2015 and 5.1% from 2016 to 2020 (SHCP, 2014). In spite of the economic progress, by
the end of 2012, approximately 45.0% of the Mexican population was deemed poor and 10.0% was still
living under extreme poverty conditions.
The energy sector is highly relevant to the Mexican economy, and it is poised to become one of theeconomy’s main growth levers through the structural changes recently approved. The oil sector in particular
is a central component, and even though oil exports just represented 13% of Mexico’s total exports in 2013,
they provided one-third of the government’s total revenue, of which a large share is allocated to social
development expenditures (Banxico, 2014), (INEGI, 2014). As shown in Table 1, Mexico’s proven primaryenergy reserves were 10.2 million barrels of crude oil (11.4, if gas liquids are included), 0.35 trillion cubic
meters of natural gas, 1.2 billion tonnes of coal, and 2.8 thousand tons of uranium.
Table 1: Key data and economic profile
Key dataa

Energy reserves

Area (million sq. km)

2.0

Oil (billion barrels) b

10.1

Population (million)

118.4

Gas (billion cubic metres) b

0.4

GDP (USD (2010) billion at PPP)

1 878

Coal (billion tonnes)c

1.2

GDP (USD (2010) per capita at PPP)

15 542

Uranium (kilotonnes) d

2.9

Source: a. By mid-2013 (CONAPO, 2014); b. As of 1 January 2013; Oil reserves do not include condensates andnatural gas liquids, ‘Gas reserves’ refers to dry gas, (PEMEX, 2013); c. At the end of 2013 (BP, 2014); d. As of 1
January 2013, ‘Reserves’ refers to reasonably assured resources, (NEA, 2014); for all other figures (EDMC, 2014).

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ENE RG Y S U PPLY AN D DE M A ND
PRIMARY ENERGY SUPPLY
Mexico’s net primary energy supply in 2012 amounted to 188 514 kilotons of oil equivalent (ktoe), a 2.6%
increase from 2011, mainly as a result of a higher production of oil and gas, as fossil fuels remained dominantwith nearly 90.0% of the economy’s primary energy supply; non-fossil sources such as nuclear power andrenewable energy made up the remainder (EDMC, 2014). According to official information, by the end of
2012, Mexico’s proven oil reserves were 10.1 billion barrels and proved natural gas reserves were 0.4 trillion
cubic meters. Owing to these figures, Mexico was the 18th economy in the world for its oil reserves and the30th for its natural gas reserves (PEMEX, 2013).
In 2013, Mexico produced 2.5 million barrels per day of crude oil, mostly heavy oil. In recent years,
PEMEX has focused its efforts on discovering and exploiting new fields to offset the natural decline of its
once largest oil asset, Cantarell, which peaked in 2004 with 2.1 million barrels per day of oil and has dropped
ever since at very fast rates. Mexico is a net crude oil exporter with around half of its total indigenous crude
oil production, sent overseas, especially to the United States, making Mexico the third largest oil supplier tothat economy after Canada and Saudi Arabia (EIA, 2014). Mexico’s National Refining System (Sistema
Nacional de Refinación, or SNR) is made up by six oil refineries located across its territory (Cadereyta,
Madero, Minatitlán, Salamanca, Salina Cruz and Tula). In spite of the total distillation capacity of 1.7 million
barrels per day of crude oil, this infrastructure is still insufficient to meet the domestic market’s demand foroil products, which has resulted in Mexico being a net oil product importer, especially of gasoline. In 2013,
about 43.0% of the economy-wide gasoline demand was met through imports (Secretaria de Energia, 2014b).
Mexico’s proven natural gas reserves at the beginning of 2013 totalled 0.4 trillion cubic meters, withproduction in the same year reaching 0.2 billion cubic metres per day, of which roughly 70.0% was associatedwith crude oil production. As a net natural gas importer, Mexico looks forward to boosting its domestic gas
resources, including shale gas, although these efforts have yielded few results so far and depend on the
success of the energy reform. Due to the lower levels in the Henry Hub marker price, which is used as areference to set gas prices in Mexico, demand in the industrial and electricity generation sectors has expanded
substantially in recent years, leading to a rapid growth in the natural gas imports of about 9% from 2012 to2013, reaching nearly 66 million cubic meters (CRE, 2014). More than half of these imports came by pipelinefrom the United States, while the rest were received as liquefied natural gas (LNG) from shipping tankers
arriving to Mexico’s three regasification terminals, two of them in located in its Pacific Coast (Ensenada,
Baja California and Manzanillo, Colima) and another one in its Atlantic Coast facing the Gulf of Mexico(Altamira, Tamaulipas).
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

218 999 Industry sector

30 197 Total

293 862

Net imports and other-22 885 Transport sector

52 411

Thermal

240 916

Total PES

188 514 Other sectors

34 407Hydro

31 855Coal

9 183 Total FEC

117 015

Nuclear

8 770

Oil

102 006

Coal

1 746

Geothermal

12 321Gas

58 487

Oil

73 796

Others293 862

Other

18 838Gas

14 445

Electricity and other27 028Source: (EDMC, 2014).

COAL
In Mexico, coal represents only a small proportion of the total primary energy supply, equivalent to less than
5.0% in 2012, or 9 183 ktoe (EDMC, 2014). Most of Mexico’s recoverable coal reserves of 1.2 billion tons
are located in the state of Coahuila in the northeastern part of its territory, while some significant additional
resources are found in Sonora in the northwest and Oaxaca in the south. Around 71.0% of the recoverable
reserves are of anthracite and bituminous types, while 29.0% are of sub-bituminous and lignite types (BP,2014).
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ELECTRICITYElectricity generation in Mexico amounted to nearly 294 terawatt hours (TWh) in 2012, with the majority
coming from thermal power plants (EDMC, 2014). In 2013, the total installed power capacity for public
service was of 54 035 megawatts, an increase of 920 megawatts from 2012, as a result of new power plants
and also upgrades. A little more than three-quarters of this capacity for public service was run by the stateowned utility Federal Electricity Commission, with the remainder coming from independent power
producers (IPPs). This capacity was made up by thermal power plants (including combined cycle
technologies from IPP generators) with 68.6%, hydropower with 21.4%, coal-fired thermal plants with 4.8%,
nuclear with 2.6%; geothermal with 1.5%, wind with 1.1% and solar photovoltaic with 0.01%.
FINAL ENERGY CONSUMPTION
Mexico’s total final energy consumption in 2012 was 117 015 ktoe, a slight increase of 0.8% from 2011. Byenergy source, oil-based products accounted for 63.1%; electricity and others for 23.1%; natural gas for
12.3% and coal for 1.5% (EDMC, 2014). This structure remained very similar to that of the previous year.
By use, the bulk of final energy consumption in 2012 was located in the transport sector (44.8%), theresidential, commercial and agricultural sectors altogether (29.4%) and the industry (25.8%) sectors.
ENERGY INTENSITY ANALYSIS
In the last decades, Mexico has implemented several actions to improve its energy efficiency, with acumulative positive effect on its energy intensity levels. As shown in Table 3, from 2012 to 2013, energy
intensity declined more than 1.0% considering the economy-wide’s energy supply. As for the final energy
demand, the effects were deeper, with total energy demand intensity dropping 3.1% in 2013 when compared
to 2012. Likewise, for the same period, energy intensity across all final sectors went down, with 5.0% for
the residential, commercial and agricultural sectors altogether, and 3.2% for the transportation sector. Not
shown in the Table below, the decline of energy intensity from 2005 to 2012 was 6.1% for the primaryenergy supply and 6.6% for the final energy demand, which confirms a descending trend in Mexico.
Table 3: Energy Intensity Analysis, 2012
Energy Intensity (tonnes of oil
equivalent per million USD)

Energy2011

Change (%)

20122011 vs 2012

Primary Energy

101.7

100.4

-1.3

Final Energy Demand

64.3

62.3

-3.1

Industry

16.2

16.1

-0.7

Transportation

28.8

27.9

-3.2

Others

19.3

18.3

-5.0

Source: (EDMC, 2014).

ENE RG Y PO LI C Y OV ERVI E W
ENERGY POLICY FRAMEWORK – ENERGY REFORM 2013
In the last decade, Mexico had made some significant changes to reorient its energy policy, but the set of
legal modifications promulgated by President Peña Nieto on 20 December 2013 has transformed the energy
sector. This reform represents an ambitious milestone of constitutional reforms that strengthen thecapabilities of Mexico’s energy sector by complementing the state-owned energy companies with private
participation across the oil and gas and electricity value chains. In this way, the energy sector’scompetitiveness is expected to improve, to ensure a steady energy supply and contribute more effectively tothe benefit of the Mexican economy and population.
Mexico’s energy policy is led by the Ministry of Energy (Secretaría de Energía, or SENER), which inaddition to the formulation of the Strategy, is required by law to develop an Energy Sector Program withthe main energy objectives 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 hampering energy supply, to promote the development of energy infrastructure, and to foster
the efficiency and modernisation of regulatory institutions and state-owned companies. In that sense, suchobjectives seem to have leapfrogged significantly through the attainment of the energy reform.
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M E XI C OWith the reforms introduced, the Ministry of Energy is strengthened as the head of the energy sector
as it defines the economy’s energy policy. In the oil and gas industry, it will adjudicate assignments toPetróleos Mexicanos (PEMEX), and award permits related to oil and natural gas processing. As for
exploration and production activities, the Ministry will select the areas and design the technical guidelines
subject to public bidding. The Ministry of Finance will determine the fiscal and economic terms for oil andgas exploration and production contracts, while the National Hydrocarbons Commission will award thosecontracts and authorise the working plans stemmed from them.
Specifically, the energy reform strives to: Strengthen the economy’s energy supply at more competitive prices; Foster economic development including social and environmental responsibility considerations; Accomplish international standards in the economy-wide energy supply in terms of efficiency, quality
and reliability; and Improve the transparency and accountability throughout the energy sector’s activities.
To that end, the following major changes were brought about: The reform to articles 25, 27 and 28 of the Mexican Constitution reaffirms the Mexican member economy
government’s ownership of all hydrocarbons in the subsoil and introduces more competition in theenergy sector.
 To promote more investment inflows that foster Mexico’s development, in addition to the state
productive enterprises, private companies are allowed to participate in the production and refining of oil,
as well as transport, storage and distribution of oil, natural gas, gasoline, diesel, other oil products andthe entire petrochemical value chain. In the electricity industry, with the exception of nuclear energy,
private parties are allowed to participate in electricity generation and marketing activities under state
regulation. Concerning transmission and distribution, private parties may participate under contract with
the Federal Electricity Commission (CFE in Spanish), which will be restructured with clear andtransparent rules.
 In their new character as ‘state productive enterprises’, PEMEX and CFE will be able to strengthen theircapabilities without being privatised. The technical, managerial and budgetary autonomy given to theseenterprises will allow them focus on the creation of economic value and maximisation of Mexico’s
income while ensuring social and environmental equality as well as accountability.
 To strengthen the regulation of the energy sector, the National Hydrocarbons Commission (CNH in
Spanish) and the Energy Regulatory Commission (CRE in Spanish) became coordinated regulatoryorganisms with own legal personality, technical and management autonomy, and budgetary selfsufficiency.
 To ensure that assignments and contracts granted to public and private enterprises contribute to theeconomy-wide industry, legislation will be required to establish minimal percentages of domestic content.
Private investment must promote the inclusion and development of domestic and local suppliers in thevalue chain of the entire industry.
 To enhance transparency, several mechanisms will be implemented, including external audits and citizens
participation to verify the payments made to companies.
To facilitate the understanding of the new institutional arrangement of Mexico’s energy sector, and its areasof influence, a schematic representation is shown in Figure 1 and its elements are examined in the sections
below.

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Figure 1: Institutional arrangement of Mexico’s energy sector after the legal reform
Sector Head

SENER

CNSNS

CONUEE

Ministry’s
Deconcentrated
Entities

CRE*

Regulatory
entities
CNH**

CFE

CENACE

ININ

IIE

NuclearElect ricit yStateProductive
Enterprises

PEMEX

Independent
Transmission
Operators

CENAGAS

TechnologicalResearch
Institutions

IMP
Areas of influence
Oil

Gas

Energy Efficiency

SENER

Ministry of Energy

CFE

Federal Electricity Commission

CNSNS

National Commission for Nuclear Safety
and Safeguards

PEMEX

PetróleosMexicanos

CONUEE

National Commission for Efficient
Energy Use

CENACE

National Center for Energy Control

CRE

Energy Regulatory Commission.
* In the oil and gas industries its
regulation is applicable only to the
midstream and downstream segments.

CENAGAS

National Center for Natural Gas Control

CNH

National HydrocarbonsCommission.
** In the oil and gas industries its
regulation is applicable only to the
upstream segment.

ININ

National Institute for Nuclear Research

IIE

Electricity Research Institute

IMP

Mexican Petroleum InstituteSource: (APERC, 2014 based on México – Gobierno de la República).

OIL AND GAS
Under the previous legal framework, PEMEX was Mexico’s only operator across the oil and gas value chain
and the actor responsible for nearly all the final distribution of most oil products in the economy. Prior to
the energy reform, the Political Constitution granted the State absolute ownership of oil and gas resources
as well as the duty to exploit them across the value chain exclusively through PEMEX, which blocked
upstream oil and gas activities to private participants since the nationalisation of the petroleum industry in1938. Considering this background and the chronic underinvestment that led to obsolete technology andinfrastructure, the energy reform looked forward to capitalising on Mexico’s resources through theintroduction of private competition that would complement PEMEX’s activities, especially in the riskiest
and most capital-intensive development projects like deep-water oil and shale gas.
With the reform enacted, the State can perform hydrocarbon exploration and extraction activities
through assignments and contracts with PEMEX, private operators, or both parties in association. Fourtypes of combinable contracts for hydrocarbons are established: services, profit sharing, production sharing,and licenses. In particular, the last three will allow the transfer to contractors of the geological and financial
risks involved in the exploration and extraction activities. To preserve PEMEX’s assets and value creation
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in this 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 will perform public biddings on hydrocarbons,
to determine winners and administer the incumbent contracts. The CNH is also responsible for thequantification of Mexico’s oil and gas potential and geological records, for the announcement, tendering andsigning of exploration and production contracts and oversees the technical issues related to all the permits
awarded to maximise the economy’s rent perceived for its hydrocarbons. In line with the competition
introduced, a National Center for Natural Gas Control (CENAGAS in Spanish) was created to administer,
coordinate and manage efficiently and independently the pipeline grid and the storage of natural gas. It will
act as an independent transmission operator
In addition, the Mexican Fund of Petroleum for Stabilisation and Development was created tosafeguard, manage and distribute the income produced from hydrocarbons assignments and contracts, withthe exception of taxes. The Fund is a trust within Mexico’s Central Bank, with a Technical Committee madeup of four independent board members and three members from the State.
ELECTRICITY
Since 1992, the public and private sector have carried out Mexico’s electricity generation, due to theindustry’s partial liberalisation 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 compete with CFE for mediumsized customers.
As this Energy Reform retains state control over transmission and distribution activities, it is expectedthat CFE will be able to contract private companies to undertake the expansion and operation of Mexico’stransmission and distribution lines, enhancing investments and introducing new technologies, which may
reduce the system’s losses and improve its reliability. Some of the most remarkable features of the Energy
Reform are the following: The government’s exclusive faculty to plan and control the National Electricity System is preserved inorder to enhance its competitiveness and drive prices down.
 The National Center for Energy Control (CENACE) will be withdrawn from the CFE to become apublic decentralised entity that will be in charge of operating the government’s power system, thewholesale power market, and will guarantee open and non-discriminatory access to the government’s
transmission grid and distribution grids.
 The Regulatory Energy Commission (CRE) is strengthened by granting it legal personality, technical andmanagement autonomy, as well as budgetary self-sufficiency. It will regulate the activities of the electricity
industry, as well as the storage, transport and distribution of oil products through the pipeline.
NUCLEAR
Mexico is experienced in the development of nuclear energy to generate electricity, with its only plant with
two nuclear reactors (Laguna Verde) in operation since 1990. As per the last edition of the National Energy
Strategy, the Mexican government has not put forward any actions indicative of a stronger will to expand
its nuclear-based electricity generation; it must be added that after the energy reform passed, this technology
remains reserved to the State.
ENERGY EFFICIENCY
Mexico has had energy efficiency programs in place since 1989. The institution in charge of promoting these
programs and providing technical advice is the National Commission for Efficient Energy Use (CONUEE
in Spanish). Through CONUEE, the government has driven the promotion and assessment of thesustainable use of energy. To strengthen Mexico’s energy efficiency policies, and in line with the energy
reform, the National Program on the Sustainable Use of Energy 2014-2018 was released on April 2014. The
program was jointly created by the Ministry of Energy and CONUEE, and encompasses the next generalobjectives:
 To design and develop programs and actions that foster an optimal energy use in the processes andactivities across the energy sector.
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 To strengthen the energy efficiency regulation of energy-based equipment and devices made and/or
marketed in Mexico.
 To strengthen the governance of energy efficiency systems at federal, state and municipal levels including
public, social, private, and academic entities.
 To promote the development of technical and technological capabilities related to the sustainable use ofenergy.
 To contribute to the development and dissemination of energy-saving practices among the population.
 To promote technological research and development in the field of energy efficiency.
RENEWABLE ENERGY
To achieve its goal of reducing hydrocarbon fuel dependency and integrating sustainability into the energy
policy framework, the 2008 Energy Reform allowed the development of new policy and regulatory
instruments to promote the introduction and growth of renewable energy, including biofuels and research
activities.
In addition, derived from the Law for the Use of Renewable Energy and Finance of the Energy
Transition, the Special Program for Renewable Energy Utilisation was issued in 2009 to provide theinstitutional framework for designing public policies in the renewable energy sector. It sets out goals andactions for promoting the use of renewable energy. The program envisions renewable energy utilisation ina sustainable way in the short and long term, with the dual goals of contributing to the economy’s
development and mitigating climate change effects.
ENVIRONMENTAL SUSTAINABILITY
With the structural changes achieved, the State will promote actions that protect the environment throughlower carbon intensity in its domestic energy demand and supply, as well as the reduction of polluting
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 to theenvironment, the Ministry of Energy coordinated a cross-institutional effort towards the development of
the Special Program for Climate Change 2014-2018. The Program contains 38 action lines oriented to theadaptation and mitigation of climate change, from which eight of them have specific goals. According to
the Program, the energy sector’s impact to climate change is considerable, as it accounts for 61.0% of the
mitigation commitments established.
Additionally, the energy reform created the National Agency for the Industrial Safety andEnvironmental Protection in the Hydrocarbons Sector, an organism attached to the Federal Ministry ofEnvironmental but with technical and management autonomy. The Agency will be responsible of thesupervision and sanction of the operators across the oil and gas value chain (upstream, midstream anddownstream) in terms of industrial and operational safety; plugging and abandonment of wells and facilities;
and control of polluting emissions and waste. In so doing, the Agency will look forward to complying withdomestic and international technical standards.
RESEARCH AND DEVELOPMENTIn Mexico, the Ministry of Energy, through its Vice-Ministry for Energy Planning and Transition, is incharge of fostering research and development policies, which are predominantly carried out by three publicresearch bodies: the Mexican Petroleum Institute, which supports the hydrocarbons sector; the Electricity
Research Institute for electric power and energy efficiency; and the National Institute for Nuclear Research,
in charge of research in nuclear-based power generation and other peaceful applications.
Energy-related research and development in strategic areas has been enhanced by the creation of two
trust funds managed jointly by the Ministry of Energy and the National Technology Council (Conacyt): theTrust Fund for Hydrocarbons and the Trust Fund for Energy Sustainability. These trust funds are financed
from fee payments collected from PEMEX Exploration and Production as required by the National Income
Law, and they are oriented to fund scientific and applied research projects, as well as supporting the
adoption, innovation, assimilation of technological development and training of specialised humanresources.
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While the Trust Fund for the Hydrocarbons Sector is oriented to upstream and downstreamhydrocarbon activities, including basic petrochemicals, the Trust Fund for the Energy Sustainability Sector
supports clean technologies, diversification of energy sources, renewable energy sources and energy
efficiency. In addition, the Trust Fund for Energy Transition and Sustainable Use, which is financed throughthe Federal Budget, aims to promote the use of renewable energy and energy efficiency. It supports projects
for the diversification of primary energy use and energy savings in industrial and domestic activities, as well
as some research projects.
NOTA BLE EN E RG Y D EV EL O PM E NT S
Please note that the majority of the relevant energy achievements are encompasses in the prior sections
regarding Mexico’s energy sector reform.
OIL AND GASAside from the scope and results brought about with the energy reform, PEMEX presented its strategies
within its Business Plan 2014-18. Four action lines are included: growth, operational efficiency, corporate
responsibility and management innovation. In terms of reserves, the following objectives are enforced:
 Implementing best practices in the field of primary oil recovery to manage the natural decline of fields.
 Increasing the oil recovery factor to a range of 3.0% to 8.0% from the original volume, through theimplementation of best practices in the field of enhanced and secondary recovery.
 Developing a master plan for the extraction and commercialisation of extra-heavy oil fields in Mexico’s
marine regions.
 Hastening the production of new fields by reducing the time between their discovery and commercial
development.
To underpin Mexico’s natural gas supply, on December 2014, the first phase of the Los Ramones
natural gas pipeline project was formally launched by President Peña Nieto. The project is an ambitioustransport system with a capacity of around 34 million cubic meters per day that goes from Agua Dulce, inTexas, United States to Los Ramones in Nuevo León, Mexico. This infrastructure will strengthen Mexico’s
natural gas market to increase natural gas flows up to the largest consuming centers.
ELECTRICITY
Most of the Mexico’s territory is covered by a single grid, although two systems remain isolated in the Baja
California peninsula; altogether, these three systems form the National Electricity System (in Spanish,
Sistema Eléctrico Nacional, or SEN). CFE manages all the electricity produced by private independent
power producers.
Several major electricity projects were underway up to the first half of 2014, most of them related toinfrastructure. This included 13 electricity generation plants, 11 of them considered of greenfield type andtwo of them in the brownfield category. Overall, these projects will add 1.9 gigawatts of installed capacity,with capital investments worth USD 2.6 billion. The margin reserve of the economy-wide grid was around
21.0%. During the same period, Mexico’s main electricity infrastructure was made up by nearly 187.6 giga
volts amps, which represented an increase of 1.5% from the first half of 2013. To catch up with the growing
electricity demand, the extension of the transmission network and the number of power substations grewfrom the first half of 2013 in 0.2% and 2.3%, to reach more than 51 209 circuit kilometers and 385
substations.
ENERGY EFFICIENCY
Mexico was able to save more than 5 000 GWh of energy during the first half of 2014. This substantial
outcome was the result of several programs, many of them implemented for long in four major areas:normalisation and standards, households, facilities (industrial, residential and commercial), and daylightsavings (Horario de Verano) (Secretaria de Energia, 2014b).
RENEWABLE ENERGY
Due to its geophysical conditions, Mexico’s potential for renewable energy development is very promising.
To this end, the economy has promoted more intensively the development of renewable technologies for
power generation, cogeneration and biofuels. By June 2014, actions relevant to be reported include: Pursuant to the Law for the Use of Renewable Energy and Funding of Energy Transition, the Special
Program for the Use of Renewable Energy was issued on April 2014. The Program sets a goal by 2018
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of 24.9% of the economy’s electricity generation based on renewable energy and cogeneration
technologies, considering a 2012 baseline of 14.7%. To that end, the Program set the next particular
objectives:oTo expand electricity’s installed capacity and generation based on renewable energy;oTo increase private and public investment inflows on electricity generation and interconnection
infrastructure for projects based on renewable energy;oTo expand the share of biofuels in the economy-wide energy matrix;o

To promote the development of technology, human resources and value chain for renewableenergy; andoTo provide equal access to renewable energy by means of rural electrification, small-scale thermal
use and social participation.

 Between September 2013 and August 2014, the Trust Fund for Energy Transition and Sustainable Use
had approved eight projects amounting to approximately USD 86 million, centered on three major areas:
energy efficiency and conservation in the residential and commercial sectors; geothermal development;
and promotion of clean energy projects.
oThrough these projects 22 500 households in the States of Chihuahua, Guerrero, Michoacán andSonora replaced their incandescent light bulbs for energy-saving fluorescent lamps; more than 5000 firms were able to purchase highly efficient freezing and air conditioning equipment; and theimplementation of two projects oriented to prefeasibility studies and the design of financial
instruments for geothermal energy will help expand the use of this resource across Mexico.

 To facilitate investment inflows for renewable energy through regulatory simplification. To that effect, agoal was set to reduce the average processing time for the operation of renewable energy projects from
620 to 465 days.
 The Large-Scale Renewable Energy Project (PERGE in Spanish) was extended by the World Bank up to
30 April 2016. Launched since 2006 and funded from a donation of USD 25 million from the Global
Environment Fund, the intention of this project is two-fold: it aims to reduce the greenhouse gas
emissions produced from the electricity generated with conventional energy sources; and to overcome
the barriers that hamper the development of markets and technologies for renewable energy.
 In step with the changes introduced with the energy reform, by the first half of 2014, two permits had
been granted to private operators for geothermal development projects; one each for the modalities ofself-supply and small producer. Mexico was a pioneer in the use of geothermal energy, with its firstgeothermal well being drilled in the 1950s. By the end of 2014, four geothermal fields were undercommercial exploitation by CFE: Cerro Prieto, Los Azufres, Los Humeros and Tres Vírgenes. These
private projects are expected to begin operations by the first quarter of 2015 and the first quarter of 2016,
respectively, and add a joint installed capacity of 65 megawatts.
 In order to provide electricity to 33 rural communities in a number of States through a microgrid of solar
photovoltaic panels, the Integral Energy Services Project under the guidance of CFE launched its firstphase by putting five solar power plants in operation up to June 2014 with investments worth more than
USD 3 million. The second leg was scheduled to begin operations during the second half of 2014, withcapital investments of more than USD 7 million. So far, the cumulative capital investment of this projectamounts to roughly USD 28 million.
 In compliance with the Law for the Use of Renewable Energy and Finance of the Energy Transition, theMinistry of Energy is responsible for the management and update of Mexico’s Renewable Energy
Inventory (INER in Spanish). This inventory is based on statistical and geographical systems to enhancethe decision-making conducive to investments on renewable energy. By the end of June 2014, theMexican compendia of biomass, tidal currents and water resources had been finished, and the ones
corresponding to solar radiation, geothermal potential and small-scale hydroenergy will be available
during 2015.
In terms of biofuels, up to the first half of 2014, there were 411 biodigesters in Mexico, most of them
distributed in the northwest and central-west parts of the territory; with 182 of them using the biogas
produced from piggeries and dairy farms for electricity generation with an equivalent installed capacity of
12.3 megawatts. With preliminary assessments that place Mexico’s potential biogas installed capacity at 500
megawatts, the Ministry of Energy launched a project that provides economic incentives to businesses
aiming to use the biogas for electricity purposes and wishing to interconnect to the main grid. As for124

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biodiesel, by the end of June 2014, 17 marketing permits and 15 permits for small producers had been
granted.
In addition, PEMEX proposed a 10-year project to introduce up to 5.8% of ethanol in the gasoline
marketed in the States of San Luis Potosí, Tamaulipas and Veracruz, which will demand approximately 190
million liters of ethanol by 2020 and opens the door to assess the volume that could be produced fromagricultural crops.
ENVIRONMENTAL SUSTAINABILITY
Owing to the predominance of fossil fuels in Mexico’s economy and energy matrix, the Ministry of Energy
fosters the application of carbon capture use and storage (CCUS) in Mexico to mitigate carbon emissions.
To that end, Mexico’s CCUS Technology Roadmap was issued, with the aims of: Outlining a critical path towards CCUS spanning its whole lifecycle;
 Developing a systemic database that facilitates the management of the economic and regulatory resources
associated to CCUS technology; and,
 Articulating the necessary research tasks and activities to optimise CCUS implementation.
RESEARCH AND DEVELOPMENT
As for the Conacyt-SENER-Trust Fund for Hydrocarbons, with four new projects authorised until the endof June 2014 and oriented to enhanced oil recovery and the reduction of field decline rates, the total numberof projects added up to 50, with resources committed for an amount of about USD 269 million. Some of
the most relevant projects refer to the acquisition, assimilation and interpretation of 3D seismic data forshale plays, a technology center for deep-water projects, and the development of specialised humanresources to improve the capabilities in the Mexican energy sector.
In the case of the Conacyt-SENER-Trust Fund for Energy Sustainability, at the end of June 2014, there
were 51 projects with resources worth USD 213 million. Some of the projects with the largest impact are
the Mexican Centers for Energy Innovation, which will promote research and development in the fields ofgeothermal, wind and solar energy.
INTERNATIONAL COOPERATION
Mexico has played a significant role in international energy cooperation for many decades. In accordancewith its foreign policy principles, Mexico has promoted comprehensive and sustainable development
through multiple bilateral and multilateral fora. During 2013 and up to the first half of 2014, Mexico
promoted strategic cooperation with a number of economies, mainly in areas of energy efficiency, energy
sustainability, climate change and geothermal development. These economies were Belize, Canada, Cuba,
Ecuador, El Salvador, Guatemala and the United States in the Americas; Denmark, France, Germany, Italy,
Portugal and the United Kingdom in Europe; Djibouti in Africa; and Japan in Asia.
On a multilateral level, Mexico participated and led several spaces of dialogue during 2013 and up toJune 2014, mainly through its Ministry of Energy. Mexico collaborated with several multilateral bodies,including the International Energy Agency, the International Energy Forum, the Nuclear Energy Agency,
the International Renewable Energy Agency, the Latin-American Energy Organisation, the Energy andClimate Partnership of the Americas, the International Atomic Energy Agency, the G20, the WorldPetroleum Council, the Carbon Sequestration Leader Forum, and the Extractive Industries Transparency
Initiative. Mexico also held the preparatory meeting towards its hosting of the Clean Energy Ministerial in
2015.
In December 2014, Mexico had signed a trilateral Memorandum of Understanding along with Canada
and the United States, concerning cooperation on energy information, with the aim of creating a common
framework for sharing publicly available energy information among the three economies. This effort looks
forward to setting the stage for dialogue, and harmonise each of the economies’ energy outlooks andinformation (NRCan, 2015). Mexico also continued enhancing its collaboration with the State governmentsof California, and New Jersey in the United States; the Basque Country in Spain; as well as China, Guatemala,
Norway and Saudi Arabia.

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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/
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Instituto Mexicano del Petróleo (IMP)—www.imp.mx/
Instituto de Investigaciones Eléctricas (IIE)—www.iie.org.mx/
Instituto Nacional de Investigaciones Nucleares—www.inin.mx/
Instituto Nacional de Estadística y Geografía (INEGI)—www.inegi.org.mx
Petróleos Mexicanos (PEMEX)—www.pemex.gob.mx
Presidencia de la República—www.presidencia.gob.mx
Secretaría de Energía (SENER)—www.energia.gob.mx
Secretaría de Hacienda y Crédito Público (SHCP)—www.shcp.gob.mx
Secretaría del Medio Ambiente y Recursos Naturales (SEMARNAT)—www.semarnat.gob.mx

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NEW ZEALANDINTRODUCTION
New Zealand is an island economy in the South Pacific, consisting of 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 is a mature economy
with a per capita GDP of about USD 31 300 (USD 2010 at PPP), although this is below the average of theOECD member economies.
New Zealand is self-sufficient in all energy forms except for oil. New Zealand has vast renewable energy
potential, which in 2013 accounted for 75.0% of electricity generation, largely from hydro, geothermal andwind. For fossil energy resources, the reserves are more modest including: 124.5 million barrels of oil,56.4 billion cubic meters of natural gas and LPG and 571 million tons of coal at the end of 2012 (MBIE,
2014; BP, 2014).
Table 1: Key data and economic profile, 2012
Key data

Energy reserves

Area (sq. km)a

269 652

Oil (million barrels)b

124.5

Population (million)

4.47

Gas (billion cubic metres)c

53.8

GDP (USD (2010) billion at PPP)

138.8

Coal (million tonnes)d571

GDP (USD (2010) per capita at PPP)

31 315

Uranium (kilotonnes U)–

Source: a. (Statistics New Zealand, 2014); b. shown as ‘Remaining Reserve P90 as at 1 January 2014’ and includes LPG(MBIE, 2014); c. shown as ‘Remaining Reserve P90 as at 1 January 2014’ (MBIE, 2014); d. Proven reserves at the endof 2013 from (BP, 2014). Other data (EDMC, 2014).
E N E RG Y S U P P LY A N D D E M A N D

PRIMARY ENERGY SUPPLY
In 2012, New Zealand’s total primary energy supply was 18,859 kilotons of oil equivalent (ktoe). A numberof energy sources contributed to this total, including oil (34.0%), geothermal (21.0%), gas (20.0%), hydro(10.0%), and coal (8.0%), with wind, biomass, biogas, waste heat and solar providing the remainder (7.0%).
It is of note that geothermal electricity generation has an efficiency of 13.0% in New Zealand (MBIE, 2014);
as such, the geothermal share of the final energy supply is significantly smaller than its primary energy supply
share. New Zealand’s energy self-sufficiency (indigenous production/primary energy supply) in 2012 was
85.0%, down from 89% in 2011 as growth in total primary energy supply outpaced growth in indigenous
production. Since 2000, growth in New Zealand’s primary energy supply has been modest, increasing at an
average annual rate of 1.2% (EDMC, 2014).
Coal, predominantly lignite, is New Zealand’s most abundant fossil energy resource. However, almost
all coal production is comprised of sub-bituminous and bituminous coals. In 2012, coal production remained
constant on an energy-equivalent basis compared with 2011 (EDMC, 2014).
Oil is sourced from 19 fields in the Taranaki region in the North Island (MBIE, 2014, p. 31). The
production of crude oil, natural gas liquids and condensate was down 11.0% on an energy-equivalent basis
in 2012 compared with 2011. Oil production peaked in 2008 underpinned by the coming on-stream of thenewest fields, Pohokura, Kupe, Tui, and Maari, and from such onshore fields as Cheal and Sidewinder (MBIE,
2014). New Zealand oil is mostly exported due to its high quality (it is ‘sweet’ and ‘light’). The vast majorityof domestic oil demand is met by importing crude oil and refining it at the one New Zealand refinery at
Marsden Point, or importing refined oil products. New Zealand is a net importer of oil, with production
meeting around 30.0% of domestic oil demand in 2013.
Natural gas is sourced from 18 fields (MBIE 2013). In 2012, natural gas production decreased by 9.0%
compared with 2011 (EDMC 2014). Gas is used for electricity generation, and in methanol and urea
production. All the gas used in New Zealand is domestically produced since there are no facilities forimporting liquefied natural gas (LNG). In 2013, there was a significant increase in gas and LPG remaining
reserves (up 31.0%), with Pohokura, Maui, and Mangahewa providing most of this increase. In 2012
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Methanex, which produces methanol with natural gas as a feedstock, signed a 10-year gas supply agreementwith the Mangahewa field operator.
In 2012, New Zealand generated 41 616 GWh of electricity, a very slight decrease on 2011 (EDMC2014). New Zealand has plentiful hydro and renewable energy resources. Reflecting this, about 73.0% ofelectricity generation was from hydro and renewable sources. Hydro is the major source of electricity
generation, accounting for 58.0% of total generation in 2012. Hydro production fluctuates from year to year
depending on rainfall. Geothermal generation accounted for another 13.0% (MBIE, 2013, Table 6). Morethan two-thirds of New Zealand’s hydroelectricity is generated in the South Island, and all geothermal
electricity is generated in the North Island. Most of the remaining electricity is generated in the North Islandusing a combination of natural gas, coal, wind and wood waste, although a small share of wind generation
is located in the south island (MBIE, 2013). The only existing coal plant is being gradually decommissioned
with two of its four 250 MW units already mothballed and the remaining two being currently assessed.
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

15 942 Industry sector

3 989 Total

41 616

Net imports and other3 793 Transport sector

4 543

Thermal

10 277

Total PES

18 859 Other sectors

4 351

Hydro

22 894Coal

1 600 Total FEC

12 883

Nuclear

Oil

6 352

Coal

567

Gas

3 841

Oil

5 778

Other

7 066

Gas

1 928

Electricity and other

4 610

–

Geothermal

8 445

Others41 616

Source: (EDMC, 2014).

FINAL ENERGY CONSUMPTION
In 2012, New Zealand’s final energy consumption was 12 883 ktoe, just over 1.0% higher than in 2011. The
transport sector consumed 35.0% of the final energy, while the industry sector consumed 31.0%, and othersectors 34.0%. Final energy consumption was dominated by oil, accounting for 5 778 ktoe (45.0%), followedby electricity and other (mainly heat) at 4 595 ktoe (36.0%), gas at 1 704 ktoe (15.0%) and coal at 556 ktoe
(4%) (EDMC, 2014).
Domestic passenger and freight transport in New Zealand is dominated by private road vehicles.
Consequently, transport is the main consumer of petroleum products, accounting for 79.0% of domestic oil
consumption in 2012. Consumption of oil products in the other sectors was shared between residential,commercial and agricultural (11.0%), industry (6.0%) and non-energy or other (5%) (EDMC, 2014).
ENERGY INTENSITY ANALYSISNew Zealand's energy intensity of primary energy in 2012 was 135.9 tonnes of oil equivalent million USD
of GDP, an increase of 1.9% from 133.3 tonnes of oil equivalent million USD in 2011. This is partly due toan increase in natural gas supply for non-energy purposes, and an increase in geothermal energy for electricity
generation. The energy intensity of final energy demand decreased by 0.9% from 93.7 tonnes of oil
equivalent million USD in 2011 to 92.8 tonnes of oil equivalent million USD in 2012. The energy intensityof both the industry sector and transport sector decreased by 2.1% and 3.0%, respectively, reinforcing theoverall improvement in consumption intensity, while the energy intensity of the other sectors, which includes
the commercial and residential sectors, has increased by 2.6%.
Table 3: Energy Intensity Analysis
EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

133.3

135.9

1.9

Final Energy Demand

93.7

92.8

-0.9

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Industry

29.4

28.7

-2.1

Transportation

33.78

32.7

-3.0

Others

30.6

31.4

2.6

Source: (EDMC, 2014).
P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORKA new Ministry of Business Innovation and Employment (MBIE) was created in July 2012 through themerger of four government ministries. These were the recently established Ministry of Science andInnovation, the Ministry of Economic Development (formerly responsible for energy policy), theDepartment 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 a number ofother 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. New Zealand generally welcomes investment in oil and gas exploration by foreign firms.
Electricity generation and marketing is also open to competition. In 2013, the government began a processof privatising 49.0% of the three remaining state-owned electricity generators. Transpower is thetransmission grid 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, although there are private operators as well.
In August 2011, the government released New Zealand's overarching energy policy framework, the New
Zealand Energy Strategy 2011–21: Developing Our Energy Potential (the Energy Strategy) (MBIE 2012a) to replacethe 2007 New Zealand Energy Strategy. The new strategy focuses on four priorities: diverse 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 2011–2016(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 efficient resource use, driven by clear price signals and, where possible, competitive markets. The
greatest change occurred in the electricity and gas markets. There the vertically integrated sectors weredismantled to separate the natural monopoly and competitive elements; the former government-owned andoperated electricity and gas monopolies were either corporatised or privatised; and the electricity market wasderegulated.
Responding to concerns about rising electricity prices, especially for residential customers, andgovernance arrangements in the electricity sector, the Minister of Energy and Resources initiated a
Ministerial Review of Electricity Market Performance in April 2009. The review was led by the independent
Electricity Technical Advisory Group (ETAG). A discussion paper was released in August 2009 (MED,
2009b). The discussion paper made a number of recommendations that were included in the Electricity
Industry Act 2010.
A key governance change in the Electricity Industry Act 2010 was replacing the Electricity Commission
with the Electricity Authority, which has more independence from the government. This change was effectivefrom 1 November 2010 (EA 2012). Some of the responsibilities of the Electricity Commission thatoverlapped with those of other agencies have been transferred to those agencies, including the promotionof energy efficiency, the approval of grid upgrades and the management of supply emergencies.
The Electricity Industry Act 2010 has several provisions to promote competition. These include
provisions for a swap of assets between the three state-owned generating companies to better align thegenerating and marketing assets of each firm, a fund to encourage customers to switch electricity providers
and better electricity market hedging arrangements. The Act also has provisions to improve the security ofsupply. These include rule changes to ensure electricity retailers do not profit from supply emergencies, andthe requirement that a state-owned reserve power station, criticised for distorting market incentives, be soldso that it can be operated on a commercial basis (NZG, 2010a). This plant was sold to Contact Energy in
2011.
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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 set out 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 the gas 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, in line with the government’s objectives for energy and economic growth. Its role isto efficiently allocate rights to prospect for, explore for and mine Crown owned minerals, the effective
management and regulation of those rights and ensuring a fair financial return to the Crown for its minerals.
NZP&M also has a role in promoting investment in the mineral estate. NZP&M 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 30.0% (Inland
Revenue 2012). The tax rate has dropped to 28.0%, 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 5.0% (i.e. 5.0% of the net
revenues obtained from the sale of petroleum) or an accounting profits royalty of 20.0% (i.e. 20.0% 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 1.0% is applied to natural gas or an
accounting profits royalty of 15.0% on the first NZD 750 million for offshore projects or 15.0% on the first
NZD 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 1.0% of net sales
revenue is payable on net sales revenue between NZD 100 000 and NZD 1 million. For producers with net
sales revenues in excess of NZD 1 million, the royalty payable is either 1% of net sales revenue or 5.0% 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 1.40 per tonne is payable for hard and semi-hard coking coal,
NSD 0.8 per tonne is payable for thermal and semi-soft coking coal, and NZD 0.3 per tonne is payable forlignite. For initial permits awarded since 24 May 2014, an ad valorem royalty of 2.0% of net sales revenueor 10.0% of the accounting profits, whichever is higher.
New Zealand has good oil and gas resources potential, but it 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 a number of 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 to foster more investment, particularly
in frontier resources; anddeveloping a fit-for-purpose legislative framework for the petroleum sector (NZG 2010b; MBIE,
2012a).

In August 2011, the government announced a new approach to allocating petroleum exploration rights.
Previously, New Zealand primarily used a ‘first-in, first-served’ priority-in-time allocation scheme.
Under the new scheme, the government will announce ‘block offers’ for specific acreage and invitecompetitive bids to develop them. The goal of the change is to attract significant additional investment
to New Zealand while providing the government with more control over where, when, and to whom
exploration rights are granted (NZP&M, 2014).

New Zealand’s environmental permitting process, known as ‘resource consent’, is governed by the
Resource Management Act 1991 (RMA) and its subsequent amendments. Resource consent is required for131

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any 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 appointed an RMA Technical Advisory Group to support the government’s programof reform. A discussion paper was released in February 2009, which made a number of recommendations
that were included in the Resource Management (Simplification and Streamlining) Amendment Act 2009
(MFE, 2011b).
A major criticism of the RMA had been that decision-making was generally delegated to local
governments, where local interests were likely to take precedence over economy-wide interests, or where
insufficient expertise and resources are available, especially for major projects. The Resource Management(Simplification and Streamlining) Amendment Act 2009 responded to this criticism by establishing atransitional Environmental Protection Authority (EPA) within the Ministry of the Environment to receive
resource consent applications for proposals of national significance and to support the boards of inquiry(or the Environment Court) in making decisions regarding those proposals (MFE, 2014). Under legislation
passed in May 2011, the EPA was changed to a stand-alone agency with expanded powers as of 1 July 2011
(NZG, 2011a).
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 of exploring better approaches to urban planning and water
management (MFE, 2014).
Further changes to the RMA have been proposed that will build on previous amendments, but that may
also include more widespread changes primarily designed to address housing affordability concerns.


In response to the Deepwater Horizon Gulf of Mexico oil spill, in June 2010 the government initiateda review of offshore petroleum health, safety and environmental (HSE) legislation. In December 2010,
the Comparative Review of Health, Safety and Environmental Legislation for Offshore Petroleum
Operations Report was released. The report concluded that New Zealand’s HSE arrangements foroffshore petroleum operations incorporate a number of key characteristics of international bestpractices. However, there were some areas in which New Zealand’s regulatory framework could be
improved (MED 2010).

Responding to a key recommendation of the review, in 2012 the government passed the Exclusive
Economic Zone and Continental Shelf (Environmental Effects) Act 2012. Currently, the Resource
Management Act 1991 regulates operations in New Zealand’s Exclusive Economic Zone (EEZ) out
to 12 miles at sea, but beyond 12 miles many activities have historically been unregulated. Thislegislation makes the Environmental Protection Authority responsible for the consenting, monitoringand enforcement of activities in the EEZ that have an impact on the environment, including petroleum
exploration and marine energy development (NZG, 2011b).



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

Some stakeholders have raised concerns about these early experiences, particularly about whether theconsenting 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 a relatively long tradition of promoting energy efficiency. It passed the Energy Efficiency
and Conservation Act 2000, which lead 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).
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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 45.0%
from its 2005 levels by 2035 (APEC, 2012).
Some of New Zealand’s major policies for promoting energy efficiency include:

for transport, fuel efficiency labelling for light vehicles and support for public transport improvements,
such as the electrification of the Auckland rail system;

for businesses, support for the innovative and replicable projects, awarding prizes for efficiency
excellence, and energy auditing support.

for buildings, assistance for an expected 188 500 homes to install insulation and clean heating
equipment by 2013, energy efficiency building codes, and energy efficiency rating tools for homes; and

for products, Minimum Energy Performance Standards (MEPS) and related labelling (coordinated with
Australia) (MBIE, 2012a).
RENEWABLE ENERGYNew Zealand is well-endowed with hydro, geothermal, wind, biomass and potentially ocean energy. New
Zealand’s high level of renewable electricity supply has historically developed without significant explicit
subsidies. Although the state-owned electricity generating companies have had a major role in thedevelopment of these resources, they are required to operate as commercial businesses and must competewith private generators (Treasury, 2011). As part of the Energy Strategy, the New Zealand government
retains the target of generating 90.0% of its electricity from renewable sources by 2025, provided securityof supply is maintained. The major tool to achieve this goal will be the Emissions Trading Scheme, discussed
in Climate Change (MBIE, 2012a).
Hydro has historically been New Zealand’s major source of renewable energy. However, the best hydrosites have already been developed, and there is strong social opposition to develop any further sites, so New
Zealand has been focusing on geothermal and wind to meet its 90.0% target. The government views the
Resource Management Act 1991 (RMA), discussed above, as a major barrier to the development of
renewable energy, and sees the reforms it is making to the RMA as beneficial for that development (NZG,
2011c).
On 14 April 2011, the government issued a National Policy Statement for Renewable Electricity
Generation. This policy statement requires decision-makers at all levels of government, especially at the local
level, to recognise the economy-wide significance of renewable electricity generation in their plans and policy
statements (MFE, 2011).
In the transport sector, a previous grant of up to 42.5 cents per litre for biodiesel producers was ended
on 30 June 2012 (EECA 2012b). However, electric and plug-in electric light vehicles continue to be exemptedfrom road user charges, which for the average user equates to a saving of around NZD 700 per year (NZG
2011d;
MT,2015).
For
more
informationseetheEnergyWise
website:http://www.energywise.govt.nz/your-vehicle/electric-vehicles/regulations.
NUCLEAR
New Zealand does not have any commercial nuclear reactors and has no plans to develop a nuclear energy
industry.
CLIMATE CHANGE
The government has adopted an economy-wide target for a 50.0% reduction in New Zealand’s carbonequivalent net emissions, compared with the 1990 levels, by 2050. New Zealand is willing to commit toreducing greenhouse gas emissions by between 10.0% and 20.0% below 1990 levels by 2020, if there is acomprehensive global agreement and certain conditions are met (MBIE, 2012a, MFE, 2012).
The Climate Change Response (Emissions Trading) Amendment Act 2008 established New Zealand’s
emissions trading scheme. The scheme places a price on greenhouse gas emissions to provide an incentive
to reduce the volume of overall emissions. Six gases covered under the Kyoto Protocol are covered under
the scheme—carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur
hexafluoride (CCINZ, 2011).

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In November 2009, the government approved a number of amendments to the emissions trading
scheme, including amendments to the timeframe for entry into the scheme. Between 1 July 2010 and
31 December 2012, participants were able to purchase permits from the government at a fixed price of
NZD 25 per ton of CO2-equivalent. Over the same period, participants in the stationary energy, industrial
and liquid fuel sectors (that is, all sectors in the scheme at that time except forestry) will have to surrender
only one permit for every two tons of CO2-equivalent emitted, effectively reducing the price of permits to
NZD 12.50 per ton. These transitional provisions were extended by the Climate Change Response(Emissions Trading and Other Matters) Amendment Act 2012 (CCINZ, 2012a).
Previously all sectors of the economy were expected to be included from at the latest 2015. However,in 2012, the government revised the scheme to exclude the agriculture sector until there are economically
viable and practical technologies. The revised timetable for sector entry into the emissions trading scheme isdetailed in Error! Reference source not found.. Furthermore, a raft of other changes was included, which
will extend the transitional period and introduce the offsetting of emissions with pre-1990s forests.
For energy, the point of obligation under the scheme generally lies with energy suppliers, not with endusers. This means that only energy suppliers and a few large industrial facilities are directly involved in thescheme. The government is providing free units to energy-intensive trade-exposed industries to protect themfrom international competition that does not face a carbon cost (FL, 2012).
New Zealand is a party to the Kyoto Protocol, and according to the latest Ministry for the Environment
projections, it will exceed its 2008–12 commitment to reduce greenhouse gas emissions by 21.9 million tons
(MFE 2011f). However, New Zealand announced it would not sign up for any continuation of the Kyoto
Protocol beyond the initial commitment period beginning 2008 and ending in 2012. New Zealand intends
instead to pursue domestic policies to reduce greenhouse gas emissions (CCINZ, 2012b).
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 has completed the partial privatisation of the three large state-owned
energy utilities by selling 49.0% of each company. The partial privatisation of government-owned utilities is
expected to raise as much as NZD 6 to 7 billion, which has been set aside for reinvestment in education andinfrastructure (FT, 2013).
Uncertainty exists regarding the demand side stemming from the reduction of capacity in New Zealandsecond largest electricity consumer; there are also doubts about the profitability the Tiwai Point Aluminium
Smelter (TPAS), which accounts for about 14.0% of New Zealand’s total electricity demand. The New
Zealand government supplied a short term NZD 30 million one-off subsidy to ensure the plant continues
to operate for the next few years (NZAS, 2013). It is uncertain as to what capacity the TPAS will be able tooperate in over the medium to long term, but a complete loss of the TPAS may result in short term overcapacity of generation and lead to market price depression until new demand can replace what is lost or
alternatively an older less efficient thermal plant is retired.
Another development includes the deployment of the smart metering devices throughout the market.
To date, approximately 52% of meters have been replaced. The key driver for this development is for134

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electricity retail operations, but the newly formed Smart Grid Forum believes there is potential to expand
benefits into streamlining the market. (MBIE, 2014b)
NEW PROJECTSAt the end of 2012, 270 MW of new geothermal generation, 60 MW of new wind and 6 MW of hydro werein construction to contribute to the total renewable generation capacity in New Zealand (MBIE, 2013). Also
importantly, 250 MW of coal electricity generation were decommissioned as unit 4 from Huntly Power
Station was put into storage (MED, 2013, p. 63).
There are a number of large-scale wind, geothermal, and hydro projects that have regulatory andenvironmental consent to proceed. However all of the large 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 energy intensity
demand, growth may be much slower in the medium to long term than seen historically.
The New Zealand grid system operator Transpower has recently completed or will complete essential
major upgrade projects to maintain grid security and keep up with 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–NZD 300 million Wairakei to Whakamaru
Replacement Transmission Line Project, due for completion in 2013; and the NZD 672 million high voltage
direct current (HVDC) Inter-island Link Project, due for completion in 2014 (Transpower, 2013).
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 by 2015 (Z Energy, 2014). In addition, a consortium
led by Z Energy and partly funded by the government is investigating the large-scale production of next
generation biofuels from domestically grown timber.
REF ER EN CE S
APEC (Asia Pacific Economic Co-operation) (2012). APEC on target to reduce energy intensity but more workneeded, says early assessment. http://www.apec.org/Press/News-Releases/2012/1109_energy.aspx.
BP (2013). Statistical Review of World Energy 2013. www.bp.com/statisticalreview.
CCINZ (Climate Change Information New Zealand) (2012a). Emissions Trading Scheme Basics.
www.climatechange.govt.nz/emissions-trading-scheme/basics.html/.
——(2012b). Questions and Answers about Amendments to the New Zealand Emissions Trading Scheme.
www.climatechange.govt.nz/emissions-trading-scheme/about/questions-and-answers.html——(2012). ETS Amendments to the New Zealand Trading Scheme: Questions and answers.
www.climatechange.govt.nz/emissions-trading-scheme/ets-amendments/questions-answers.html/.
——(2013). About Obligations. www.climatechange.govt.nz/emissions-trading-scheme/obligations/.
EA (Electricity Authority) (2012). About Us. www.ea.govt.nz/about-us/.
EDMC (Energy Data and Modelling Centre) (2014). APEC Energy Database. Institute of Energy Economics,
Japan. www.ieej.or.jp/egeda/.
EECA (Energy Efficiency and Conservation Authority) (2012a). Legislation. www.eeca.govt.nz/abouteeca/eecas-role/legislation/.
——(2012b). Biodiesel Grants Scheme. www.eeca.govt.nz/biodiesel-grants/.
FL (Frazer Lindstrom) (2012). New Zealand Emissions Trading Scheme (NZETS).
www.frazerlindstrom.com/nzets.htm.
FT (Financial Times) (2013). NZ Finance Minister bullish on privatisation schedule after Mighty River
sale. http://www.ft.com/cms/s/2/2c882f9a-bca4-11e2-9519-00144feab7de.html#axzz2jvxgUbMo/.
Harris, Rob (2004). Handbook of Environmental Law. Royal Forest and Bird Protection Society of New
Zealand, Wellington.
Inland Revenue (2012). Business Income Tax. www.ird.govt.nz/business-income-tax/imputation/.
Labour Party (2013). NZ Power. http://campaign.labour.org.nz/lower_power_prices.

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MBIE (Ministry of Business Innovation and Employment) (2012a). 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. http://www.med.govt.nz/sectors-industries/energy/energymodelling/publications/energy-in-new-zealand/Energy-in-New-Zealand-2013-print.pdf/.
——(2014). Energy in New Zealand 2014. http://www.med.govt.nz/sectors-industries/energy/energymodelling/publications/energy-in-new-zealand/Energy-in-New-Zealand-2014-print.pdf/.
——(2014). New Zealand Smart Grid Forum – Terms of Reference. http://www.med.govt.nz/sectorsindustries/energy/electricity/new-zealand-smart-grid-forum/meeting-1/final-tor-scopedefinition.pdf/at_download/file.
MRP (Mighty River Power) (2013). Ngatamariki Geothermal Power Station reaches full capacity during
testing. http://www.mightyriver.co.nz/Media-Centre/Latest-News/Ngatamariki-Geothermal-PowerStation-reaches-full.aspx.
MED (Ministry of Economic Development) (2009a). New Zealand Energy Outlook 2009/2010: Hydrocarbon
Harvest. http://www.med.govt.nz/sectors-industries/energy/energy-modelling/modelling/pdf-docslibrary/reference-scenario/archive/hydrocarbon-harvest-scenario.pdf/.
——(2009b). Improving Electricity Market Performance Discussion Document. www.med.govt.nz/sectorsindustries/energy/pdf-docs-library/electricity-market/implementing-the-electricity-market-reviewrecommendations/background-papers-on-2009-review/improving-electricity-market-performancevolume-one-discussion-document-1152-kb-pdf.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/.
——(2012). New Zealand Energy Data File 2012. www.med.govt.nz/sectors-industries/energy/pdf-docslibrary/energy-data-and-modelling/publications/energy-data-file/energydatafile-2011.pdf/.
——(2014). Gas governance. http://www.med.govt.nz/sectors-industries/energy/gas-market/governanceof-the-gas-market/.
MFE (Ministry for the Environment) (2011). National Policy Statement for Renewable Electricity Generation 2011.
http://www.mfe.govt.nz/publications/rma/nps-renewable-electricity-generation-2011.
——(2012). Climate Change: New Zealand’s 2020 Emissions Reduction Target.
http://www.mfe.govt.nz/publications/climate-change/new-zealands-2020-emissions-target/newzealands-2020-emissions-target.
——(2014). The Resource Management Act. http://www.mfe.govt.nz/rma.
MT (Ministry of Transport) (2015). Exemption for light electric vehicles from road user charges,
http://www.transport.govt.nz/land/roadusercharges/vehiclesexemptfrompayingrucqandas/
NAZS (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). EPA to Improve Environmental Management. www.beehive.govt.nz/release/epa-improveenvironmental-management/.
——(2011b). Environmental protection laws for oceans introduced. www.beehive.govt.nz/release/environmentalprotection-laws-oceans-introduced/.
——(2011c). Nick Smith Speech to the New Zealand Wind Energy Association Conference: Untying the Knots—
Releasing Wind Energy’s Potential. www.beehive.govt.nz/speech/untying-knots-%E2%80%93-releasingwind-energy%E2%80%99s-potential/.

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N E W Z E A L AN D——(2011d). 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.
http://www.nzpam.govt.nz/cms/about-nzpam/rules-and-regulations.
Samuelson, Ralph D (2008). Oil: an Introduction for New Zealanders, Ministry of Economic Development.
http://www.med.govt.nz/sectors-industries/energy/energy-modelling/publications/oil-anintroduction-for-new-zealanders.
Statistics New Zealand (2014). New Zealand in Profile: 2014.
http://www.stats.govt.nz/browse_for_stats/snapshots-of-nz/nz-in-profile-2014.aspx/.
Transpower (2012). Major Projects. www.gridnewzealand.co.nz/projects/.
The Treasury (2011). State-Owned Enterprises. www.treasury.govt.nz/statesector/soes/.
U SEF UL LI N K S
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.n137

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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 of the Pacific Ocean, just south of the equator. It is
made up of 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 north 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. The
resource development industry, which includes minerals, oil and gas, contributes to approximately 80.0% of
PNG’s export income (MRA 2012a).
In 2012, its real GDP was estimated at USD 16.74 billion (USD (2010) at PPP), an increase of 9.0%
from 2010.
Table 1: Key data and economic profile, 2012
Energy reservesa

Key data
Area (thousand sq. km)

463

Oil (million barrels)

190.0

Population (million)

7.0

Gas (billion cubic metres)

155.19GDP (USD (2010) billion at PPP)

16.7

Coal (million tonnes*)－

GDP (USD (2010) per capita at PPP)

2 336

Uranium (kilotonnes U)－

Source: (EDMC, 2014); a. Proved reserves as of 2013 (US EIA, 2013).
E N E RG Y S U P P LY A N D D E M A N D

PRIMARY ENERGY SUPPLY
In 2012, PNG’s net primary energy supply was 2 085 ktoe. Light crude oil and petroleum products accounted
for 71.9%, gas for 6.6%, and hydro and other renewables for the remaining 21.5% (EDMC, 2014).
Production of crude oil in PNG started in 1992 and peaked at over 150 000 barrels a day the following
year. However, since then, production has been declining, despite exploration activities that resulted in thedevelopment of additional oilfields, and crude oil production is expected to be depleted by 2026. Oil
production in 2009 was 35 050 barrels a day. Crude oil has been refined locally since the first refinery plant
was commissioned in 2004 (Napanapa Oil Refinery, owned by InterOil), which has a refining capacity of
33 000 barrels a day.
Much of PNG’s natural gas reserves are undeveloped, except for the Hides gas field, which provides
145–155 million cubic metres a year for power generation to supply the Porgera Gold Mine in the central
highlands of PNG. The Hides gas field has about 113 billion cubic metres of proven gas reserves.
The PNG LNG Project is operated by the Esso Highlands Limited (Company). The project is a joint
venture between Esso Highlands Limited, a subsidiary of ExxonMobil, and its partners—Oil Search
Limited, Santos, AGL, JX Nippon Oil & Gas Exploration, Minerals Resources Development Company andPetromin PNG Holdings Limited, as well as local landowners. It is a 6.9 million tonne per annum integrated
LNG project sourced from the Hides, Angore and Juha fields and from associated gas in the Kutubu, Agogo,
Moran and Gobe Main oil fields. The PNG LNG Project began production in April 2014 and the first LNG
deliveries began in May 2014, ahead of schedule (PNG LNG, 2014). It will supply LNG to major customers
in Asia.
In 2012, PNG generated 4049 gigawatt-hours (GWh) of electricity, a 3.1% increase from 2011. Sourcesof generation included thermal at 65.0%, hydro at 25.0%, and geothermal at 10.0% (EDMC, 2014). Thereis little economic potential for the expansion of large hydropower plants due to the lack of substantive
demand near the supply sources. However, greater potential exists for developing smaller hydro schemes.
Most thermal and hydro power stations are owned and operated by PNG Power Limited, formerly the PNG
Electricity Commission.
Geothermal power generation in PNG was commissioned in April 2003. In 2007 the installed capacityof the geothermal power stations was 56 MW. The Geothermal Energy Association categorises Papua New

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Guinea as an economy that could, in theory, meet all its electricity needs well into the future from geothermal
sources alone (GEA, 2010). In 2010, traditional biomass accounted for over approximately 50.0% of PNG’senergy consumption (IRENA 2013). However, as there are no recent surveys to track its use, this is largely
undocumented.
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

1 341 Industry sector

445 Total

4 049

Net imports and other-1 280 Transport sector

517

Thermal

2 632

Total PES

2 085 Other sectors

247

Hydro

995

Coal

－ Total FEC

1 209

Nuclear

－

Oil

1 500

Coal

－

Geothermal

422

Gas

137

Oil

884

Others

－

Other

449

Gas

－

Electricity and other325

Source: (EDMC, 2014).

FINAL ENERGY CONSUMPTION
In 2012, total final energy consumption in PNG was 1 209 ktoe, a decrease of 15.4% from 2011. The
industrial sector’s consumption decreased 47.5% from 2011, and the sector was the second largest end user,
accounting for 36.8% of the energy used, after the transport sector at 42.8%. The other sectors, including
agriculture and residential/commercial, were 204.4%. By energy source, petroleum products accounted for
73.1% of the total consumption, while electricity and other sources accounted for 26.9%.
In PNG, around 85.0% of the population lives in rural areas and electrification rates remain low.
Petroleum products such as diesel or petrol are used in the transport and electricity generation sectors. PNG
Power Limited (PPL) and the PNG Government, with the assistance of the World Bank, is continuously
extending its rural distribution network throughout the economy, especially within the outskirts of urban
areas. PNG aims to increase electricity access to 41.0% of the population by 2020 and to 70.0% by 2030
(IRENA, 2013).
ENERGY INTENSITY ANALYSIS
PNG’s primary energy intensity in 2012 was 124.5 tonnes of oil equivalent per million USD, which has
decreased by 14.5% from 145.6 tonnes of oil equivalent per million USD n 2011. The energy intensity of
final energy demand has increased 20.7% from 91.017 tonnes of oil equivalent per million USD in 2011 to72.2 tonnes of oil equivalent per million USD in 2012. The energy intensity of both industry sector and theother sector which includes commercial and residential sector decreased by 43.0% and 8.7% respectively,
while the energy intensity increased by 9.3% in the transport sector.
Table 3: Energy Intensity Analysis
EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

145.6

124.5

-14.5

Final Energy Demand

91.0

72.2

-20.7

Industry

46.6

26.6

-43.0

Transportation

28.3

30.9

9.3

Others

16.2

14.8

-8.7

Source: (EDMC, 2014).

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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 Papua
New Guinea government’s Energy Division within the Department of Petroleum and Energy (DPE). In
2011 the Energy Division authored a number of draft energy policies, however they have yet to receive
formal status and are under review. The key draft policies included the National Energy Policy, the Rural
Electrification Policy and Strategy, the Geothermal Policy, the Renewable Energy Policy and the Electricity
Industry Policy (IRENA, 2013). The exploration and development of petroleum resources have also beenauthorised and administered by the DPE.
The PNG Government initiated The National Strategic Plan 2010–2050, which has seven pillars.
Natural resources, climate change and environmental sustainability are among the areas of focus.
In March 2010, the Papua New Guinea Government announced the Development Strategic Plan (DSP)
2010–2030, which has five pillars, one of which is ‘natural resources and environment’. The DSP 2010–2030
also set this goal: All households are to have access to a reliable and affordable energy supply, and sufficient
power is to be generated and distributed to meet future energy requirements and demands (12.4% ofhouseholds had access to electricity in 2010).
In October 2010, the Papua New Guinea Government announced its Medium Term Development
Plan (MTDP) 2011–2015. The MTDP 2011–2015 will focus on increasing access to electricity for all
households in the member economy government. New investment from the private sector in solar
technology is also expected during the period of the first MTDP. A comprehensive analysis will be necessary
to analyse the cost effectiveness of the various alternative sources of power.
ENERGY MARKETSPNG’s power authority, PNG Power Limited (PPL) is responsible for generating, transmitting, distributing
and retailing electricity throughout PNG. Sections 21 and 23 of the Electricity Industry Act 2000 outline thefunctions and powers of PNG Power Limited. Under the Act, PNG Power Limited’s function is to planand coordinate the supply of electricity throughout the economy, 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 corporatised 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.
However, because of a lack of technical capacity to perform this regulatory role, the ICCC outsourced
this role to PNG Power Limited on a contractual basis for an initial period of two years ending in 2005. PPL
has an exclusive licences until 31 2017 to sell electricity under this contract (PPL, 2014). PPL sold 1023
GWh in 2014.
FISCAL REGIME AND INVESTMENT
In September 2003, the Papua New Guinea Government introduced special fiscal terms to provide
incentives for oil and gas 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 and 2010.
The special terms are known as ‘incentive rate petroleum operations’; they offer a revised income tax
rate of 30.0% of the taxable income, which is lower than the tax rate for income from petroleum projects
established before 1 January 2001 (50.0%), and the rate for projects established after that date (45.0%). The
new 30.0% fiscal term is available for petroleum operations that have a petroleum development licencegranted on or before 31 December 2017, and a petroleum prospecting licence granted within the period
1 January 2003 to 31 December 2007.
Papua New Guinea has arguably the most competitive terms for oil and gas investment in the region.
There is no capital gains tax, and a full (100.0%) tax deduction is available for exploration expenditure. The
PNG Government’s equity is set at 20.5% and landowners’ at 2.0%. The effective royalty rate is 2.0%, andthe government’s share of that is approximately 50.0.0 (PPL, 2008).

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ENERGY EFFICIENCYEnergy efficiency policies and regulations are regulated by the Energy Efficiency Division of the Departmentof Petroleum and Energy. While energy efficiency is not currently a major priority for the PNG government,
it might prove to be an important factor if the DSP 2010-2030 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.
RENEWABLE ENERGY
Renewable energy is also regulated by the Division of Energy. PNG’s renewable energy potential is very
high, however the remote locations and terrain have meant that renewable energy has not been readily
exploited.
In February 2007, Lihir Gold Limited, which merged with Newcrest Mining Limited in 2010, and now
operates under Newcrest Mining Limited, commissioned a 20 MW geothermal power plant. This is inaddition to a 6 MW geothermal power plant constructed in 2003, and a 30 MW geothermal plantcommissioned in 2005. The latest plant lifted Lihir Gold’s total geothermal generating capacity to 56 MW,
around 75.0% of the economy’s total electricity requirements in 2007 (Newcrest Mining, 2010).
Lihir Gold Limited was the first mining company in PNG to use geothermal energy for electricity
generation and its expansion of capacity is in line with the government’s goal of promoting green energy(see ‘Climate Change’ section) and reducing dependency on fuel oil for electricity generation. The Lihir
Mine’s geothermal plant generates approximately 40.0% of the mine’s current power requirements andprovides free electricity to residents who live near the Lihir mine site. It saves the plant approximately USD$2 000 000 per year in fuel oil costs (Booth, GMII, and Bixley, PF, 2005).
The Department of Petroleum and Energy’s Energy Division assessed 45 hydro-electricity power sites
in 1987 and completed three small hydro systems in 1992. In 2010, the Australian state of Queensland
discussed a partnership with PNG to develop a 1800 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
350km undersea cable (IRENA, 2013).
PPL is considering constructing a wind farm near Port Moresby, but they have not commenced windmonitoring. In 2002 the Chinese Government donated 50 small combined wind/solar generators, some ofwhich have been installed at coastal locations (IRENA, 2013).
NUCLEARPNG has no nuclear energy industry and there are no current plans to develop one.
CLIMATE CHANGE
Climate change is one of the important pillars in the National Strategic Plan 2010–2050 (see ‘Energy Policy
Framework’ section). The Office of Climate Change and Development (OCCD) administers the member
economy government’s Climate Compatible Development Management Policy (NCCDMP), which is basedon the National Strategic Plan. The NCCDMP aims to: achieve GDP per capital of USD 3000 by 2030;
reduce GHGs by 50.0% through land use, land-use change and forestry; and become carbon neutral by 2050
(OCCD, 2014).
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 greenhouse gas
emissions reduced by the geothermal plant is approximately 4.0% of PNG’s total CO 2 emissions (Newcrest
Mining 2012). There are currently 9 clean development mechanism (CDM) projects registered with theUnited Nations Framework Convention on Climate Change CDM Board (OCCD, 2014). DMsallow
developed countries to set up emissions reduction projects in developing countries to earn certified
emissions reduction credits under the Kyoto Protocol.
NOTA BLE EN E RG Y D EV EL O PM E NT S
UPSTREAM DEVELOPMENT
A number of 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 (PPLs)
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.

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In November 2011, Lihir Gold Ltd extended its drilling contract with Energy Development
Corporation to 31 December 2012 (The Manila Times, 2011).
LNG PROJECTSIn March 2008, a joint operating agreement (JOA) for the PNG LNG Project was signed by the project’s
participants: 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 andMoran oilfields as well as the Hides, Juha and Angore gas fields. In May 2008, a gas agreement was signedby the joint project’s participants and the state of Papua New Guinea. PNG’s Deputy Prime Minister said
the first shipment of gas would be in 2014 and that it would quadruple the GDP of Papua New Guinea.
The project aims to export 6.9 million tons of LNG from Papua New Guinea each year. ExxonMobil andits joint partners completed the front-end engineering and design phase for the project in November 2009.
In November 2011, Marubeni, a highly diversified corporation, acquired a 21.0% share of the Merlin
Petroleum Company (Marubeni, 2011). Production began in April 2014, and the first deliveries in May 2014.
It is the largest ever private sector investment in PNG and it is expected to increase 21.0% 2015 due to theproject (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 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’ (MRA 2012b).
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 given in theform of finance, expert advice and studies to help PPL and the PNG Government. The project will aim toincrease electrification rates from below 10.0% to 70.0% by 2030 (World Bank 2013).
REF ER EN CE S
ADB (Asian Development Bank) (2014). Papua New Guinea: Economy.
http://www.adb.org/countries/papua-new-guinea/economy．
Booth, GM II, and Bixley, PF (2005). Geothermal Development in Papua New Guinea, A country update report:
2000-2005. http://www.geothermal-energy.org/pdf/IGAstandard/WGC/2005/0136.pdf．
EDMC (The Energy Data Modelling Centre , The Institute of Energy Economics, Japan) (2014). APEC
Energy Statistics 2012 and the APEC Energy Database www.ieej.or.jp/egeda/database/databasetop.html/.
GEA (Geothermal Energy Association) (2013). 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.
http://www.irena.org/DocumentDownloads/Publications/Papua%20New%20Guinea.pdf
Newcrest (2010). Mining Lihir.
www.newcrest.com.au/media/our_business/Newcrest_FS_Lihir_FINAL_27_July_2012_low_res_(2).pdf.
PNG Government (2014). OCCD PNG Climate-Compatible Development Policy presentation at the
48th APEC Energy Working Group Meeting. Port Moresby.
Papua Petroleum Limited (2008). Oil & gas exploration and production: Why Papua New Guinea.
www.papuapetroleum.com/why-png/default.php．
PNG LNG (2014). About PNG LNG.PNG LNG. http://pnglng.com/project/about/．
PPL (PNG Power Ltd) (2014). PPL Energy Emergency Response presentation at the 48th APEC Energy Working
Group Meeting.Port Moresby.p. 10．

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The Manila Times (2011). EDC extends Lihir drilling contract in Papua New Guinea．The Manila
Times.net. 17 November 2011.www.manilatimes.net/index.php/business/top-businessnews/11434-edc-extends/．
US EIA Papua New Guinea Energy Data (2013).US Energy Information Administration．
http://www.eia.gov/countries/country-data.cfm?fips=pp．
U SEF UL LI N K S
Papua New Guinea, Development Strategic Plan 2010-2030—
www.treasury.gov.pg/html/publications/files/pub_files/2011/png-development-strategic-plan.20102030.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
http://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 in South America, bordered by the Pacific Ocean, Chile to the south,
Ecuador and Colombia to the north, and Brazil and Bolivia to the east. Peru is one of two APEC economies
in Latin America located on the Pacific coast of South America (the other is Chile). With a land area of
1.3 million square kilometres Peru has three main geographical regions: the Costa to the west, the Sierra(Andes mountains), and the Selva, covered by the Amazon rainforest. The economy is divided into 25
political departments (administrative regions), and in 2012 had a total population of about 29.9 million
people, which represents a growth of 1.3% from the previous year (EDMC, 2014). Around 23.9% of Peru’s
population is considered poor and 4.7% extremely poor; its major population centre is the Lima region,
which represents nine million people, nearly a third of the total population (INEI, 2013a). Peru’surbanisation rate is 76.0% (INEI, 2013b).
Peru has a market-oriented economy, which in 2013 was composed of services (47.5%), manufacturing andconstruction (21.8%) and agriculture and mining (17.3%). Economic growth, low and controlled inflation
and a decreasing unemployment rate are the fundamentals of Peruvian macroeconomic stability, which has
increased exports and sustained inflows of private investment (BCRP, 2013). The economy has been driven
by the internal demand mainly private investment, exports and domestic consumption. Mining is especially
important and Peru is a major global producer, being the third in silver, third in zinc, third in copper andtin, fourth in lead, and sixth in gold (USGS, 2012). As a consequence, mineral exports have consistently
accounted for a significant portion of the economy’s export revenue, with as much as 55.0% in 2013 (BCRP,
2014).
Peruvian economic growth marked a rate of 6.0% from 2011 to 2012, its GDP reaching USD 320.9 billion(USD (2010) at PPP in 2012), and its GDP per capita growing 4.6% to reach USD 10 702 (EDMC, 2014).
In addition, Peru’s foreign reserves reached a record USD 63.9 billion while its fiscal deficit represented
3.3% of the GDP (BCRP, 2013).
Owing to its scarce oil resources, Peru is a net importer of oil. Particularly, domestic production is not only
insufficient to meet the economy’s demand, but since most crude oil produced is of extra-heavy quality andseveral of Peru’s domestic refineries are unable to process it, a substantial share of domestic production isexported. In contrast, natural gas resources are significant and the economy is a major global gas producer.
Table 1: Key data and economic profile, 2012
Energy reservesa

Key data
Area (million sq. km)

1.3

Oil (million barrels)

Population (million)

29.9

Gas (trillion cubic metres)

0.4

320.9

Coal (million tonnes)b6.4

10 702

Uranium (kilotonnes U)c50.6

GDP (USD (2010) billion at PPP)
GDP (USD (2010) per capita at PPP)

1 400

Source: (EDMC, 2013); a. (BP, 2014); b. (MINEM, 2012); c. (Ingemet-Peru, 2007).

Peru’s proved energy reserves by the end of 2012 were 1 400 million barrel of crude oil (including gas
liquids), 0.4 trillion cubic metres of natural gas and 6.4 million tonnes of coal.
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 2012 was 20 327 kilo tons of oil equivalent (ktoe), which
represented an increase of 3.2% from 2011, due to the growth observed in the production of natural gas
and its liquids. By energy source, in 2012 almost half (10 330 ktoe) of TPES came from oil, 34.0% fromnatural gas (6 826 ktoe), and 4.0% from coal (849 ktoe). Non-fossil energy sources, such as hydro, wood,biomass, wind and others contributed to the remainder at 11.0% (2 322ktoe) (EDMC, 2014).
Peru is a major gas producer. In 2012, the economy produced around 16.4 billion cubic metres (bcm)of natural gas, an increase of 7.0% over 2011, mainly as a result of the addition of Block 56’s output whichalone represented 56.0% of the total production at Camisea (MINEM, 2012b).

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P E RUIn this regard, nearly all of the domestic supply of natural gas is non-associated to crude oil andproduced in the Camisea Basin, which encompasses several natural gas fields in the Ucayali basin in southeastern Peru, mainly in the San Martín and Cashiriari reservoirs, commonly known as ‘Block 88’, along theCamisea River. Discovered in the 80’s, it was not until 2000 that a 30-year production contract was signed
between the government and the production companies, with project development beginning in 2004. Since
Camisea´s begin, output capacity at Camisea has grown steadily as drilling activities have also expanded toBlock 56, adjacent to Block 88. While the Camisea project was initially aimed to meet domestic demand fornatural gas, production levels, which have increased at an annual average rate of 62.6% since 2004, haveallowed the development of an export market in the form of liquefied natural gas (LNG), which is sent byships primarily destined for Mexico and Europe (MINEM, 2012a). In 2012, Peruvian LNG exports from
‘Melchorita’ liquefaction plant amounted to 5.4 billion cubic metres to Mexico, Japan, Thailand, Spain andSouth Korea.
Peru’s proved coal reserves are around 6.4 million tonnes, of which most (92.2%) is anthracite and theremainder bituminous coal, with the majority of reserves being located in the La Libertad, Ancash and Lima
departments. Peru is a net importer of coal, with 73.3% of its coal demand in 2012 met by imports and16.7% by domestic production (MINEM, 2012b).
In 2012, Peru’s electricity generation totalled 39 908 gigawatt-hours (GWh), a 1.8% increase from the39 222 GWh generated in 2011. Hydropower’s share of this total was the largest, at 54.0% (21 354 GWh),
with electricity generated from thermal plants accounting for 45.0% (17 866 GWh) and the remainder being
met by other sources such as biomass and wind (EDMC, 2014).
In the other energy sectors, other types of biomass (such as firewood, vegetable coal, dung and yareta—a moss-type plant dried and then burned) are used for heating and cooking. In 2012, energy supply fromrenewable sources was made up of firewood with 40.2%, hydropower with 46.0% and other biomass sources
with the rest (MINEM, 2012b).
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)
Total

Indigenous production

21 233

Industry sector

4 264

39 908Net imports and other

2 377

Transport sector

6 873

Thermal17 866

Total PES

20 327

Other sectors

3 505

Hydro

21 354

Coal

849

Total FEC

14 642

Nuclear–Oil

10 330

Coal

574

Others

688

Gas

6 826

Oil

9 517

Others

2 322

Gas

1 427

Electricity and others

3 124

Source: (EDMC, 2014).
F I NA L E N E RG Y C ON S U M P T I O NFinal energy consumption in Peru grew by 0.9% in 2012, reaching 14 642 ktoe. Transportation was the mostdynamic sector, growing 3.9% from the previous year, and representing 47.0% of total final energy
consumption in 2012. The industrial sector’s share was 29.0%, while the combined ‘other’ residential,commercial and agriculture sectors consumed 24.0%. Accordingly, oil products dominated the total energy
consumption in 2012 with 65.0%, the majority of which was consumed as diesel, gasoline and liquefied
petroleum gas. Electricity made up 21.0% of the total end-use energy demand, while gas and coal accounted
for the remaining 10.0% and 4.0%, respectively (EDMC, 2014).
E N E RG Y I N T E N S I T Y A NA LY S I S

Peru’s energy intensity has been decreasing since 2011 as a consequence of the better use of energy sources.
Peru’s primary energy intensity in 2012 was 63.3 tonnes of oil equivalent per USD, reducing by 2.7% from2011 when it was 65.1 tonnes of oil equivalent per USD. Similarly, a reduction of 4.8% is observed in the
final energy intensity for 2012 (45.6 tonnes of oil equivalent per USD) from 2011 (47.9 tonnes of oil
equivalent per USD) levels. On a sectoral basis, energy intensity improved in the industrial, transport andothers sector over the same period.

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Table 3: Energy Intensity Analysis, 2012
Energy Intensity (tonnes of oil
equivalent per million USD)

Energy2011

Change (%)

20122011 vs 2012

Primary Energy

65.1

63.3

-2.7

Final Energy Demand

47.9

45.6

-4.8

Industry

14.2

13.3

-6.8

Transportation

21.8

21.4

-2.0

Others

11.8

10.9

-7.8

Source: (EDMC, 2014).
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 Ministry of Energy and Mines (MINEM), which is divided into
two sub-ministries: the Vice-Ministry of Energy and the Vice-Ministry of Mines. MINEM is also responsible
for environmental issues concerning energy and mining activities. Through its General Directorates(Electricity, Rural Electrification, Hydrocarbons, Energy Efficiency, Mining, Energy-Environmental Issues
and Mining-Environmental Issues), the ministry stretches across the major areas of influence in the sector,
overseeing its activities and promoting investment to achieve sustainable development. In addition to
MINEM, the autonomous regulatory agency created in 1996, Organismo Supervisor de la Inversión en
Energía y Minería (OSINERGMIN) is in charge of 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
through the design and implementation of effective regulation.
In May 2010, the Vice-Ministry of Energy issued Peru’s Energy Policy Proposal 2010–2040 for public
discussion. After forums were held and feedback received, the Energy Policy of Peru 2010–2040 was
approved on 24 November 2010 (Supreme Decree No. 064–2010–EM – El Peruano 2010) with the goal of
meeting Peru’s energy demand in a safe, sustainable, reliable and efficient way, supported by planning,
research and technological innovation with the following objectives (MINEM, 2010a):

a diversified and competitive energy matrix with emphasis on renewable energy and energy efficiency;a competitive energy supply;universal access to energy supply;the highest efficiency levels in energy production and utilisation systems;self-sufficiency in energy production;building an energy sector with minimal environmental impact and low carbon emissions, as part ofsustainable development;development of the natural gas industry and its use in household, transportation, commercial andindustrial activities as well as efficient electricity generation;

strengthening of the institutions involved in the energy sector; andjoining regional energy markets in order to achieve Peru’s long-term vision.

Stemming from Peru’s Energy Policy Proposal 2010–40, in January 2012 MINEM published a study on asustainable energy matrix proposal including its environmental assessment (Nueva Matriz Energética Sostenible
y su Evaluación Ambiental Estratégica, com oInstrumentos de Planificación), which aims to provide a reference on the
Peruvian energy sector and to support energy planning purposes towards new regulations and policies. The
main goals for the year 2040 are (MINEM, 2012):


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Diversified structure of energy supply: 40.0% hydro, 40.0% gas and 20.0% Non-conventional
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P E RU

Develop of petrochemical industry in the south of Peru;

Decentralise the transport of Gas to other regions;

Up to a 19.0% of families using natural gas at home;Energy efficiency that will bring a 15.0% reduction in the energy demand, increasing the balance tradeand energy security; andA long-term goal to increase biodiesel use to 5.0%.
ENERGY MARKETS

Peru’s economy has become more market-oriented following the structural reforms of the 1990s with themining, electricity, hydrocarbons and telecommunications industries being partially privatised. Several newlaws have established a regime under which domestic and foreign investments are subject to equal 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 establishedspecific conditions in order to promote the development of the natural gas industry, fostering competition
and the diversification of energy sources to increase the reliability of the energy supply and improve thecompetitiveness of a productive sector of the economy (El Peruano 1999).
As a part of the deregulation plan of the economy, during the 1992 the Peruvian government issued theElectric Power Concession Law. This law established a new regulatory framework to promote competitionand efficiency in generation, transmission and distribution of electric power. This law is very importantbecause permits to set electricity tariffs based on the marginal costs and free market forces. There was the
chance for the large customers to negotiate directly with generation and distribution companies.
This reform had four main components:the vertical and horizontal de-integration of the Electroperú and Electrolima companies in power
generation, transmission and distribution;the progressive and partial privatisation of those state utilities;the creation of a free market where energy providers with a capacity larger than 1 MW could freely
negotiate the conditions of their supply contracts; andthe establishment of a new mandate for the former Electricity Tariffs Commission (CTE), which in2000 merged with OSINERGMIN.

Although Peru had an open electricity market, there were still barriers to the market’s efficient operation.
On July 2006, the government expanded the rules established in the Electricity Concessions Law to:ensure the supply of ‘sufficient efficient generation’ in order to reduce the economy’s exposure to pricevolatility and to help ensure that consumers receive more competitive electricity tariffs;

reduce administrative intervention in determining prices for generation by means of market solutions;take the necessary measures to create effective competition in the generation market;

Introduce a mechanism of compensation between the SEIN and the Isolated Systems so that prices
incorporate the benefits of natural gas production while reducing their exposure to the volatility of fuelmarkets.

In this context, the government has enabled the introduction of bidding and incentives for the optimal
supply of electrical energy; the establishment of a spot market; modification of the functions held by theElectric Energy Operation and Dispatch Committee (Comité de Operación Económica del Sistema
Interconectado Nacional - COES), which is now a private, independent operator and planner for theelectricity system; and adjustments to the legal framework related to the formation of transmission prices.
In 2013, there were 38 companies in charge of electricity generation - 63.0% are private and the rest
are state companies. In the same period, there were 8 transmission companies and 21 distribution companies(52.0% private and 48.0% state companies) (OSINERGMIN 2013).
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,
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investments in oil and gas upstream activities are conducted under licence or service contracts granted by
the government.
The Peruvian government guarantees the 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 equals
under the law. There are no restrictions on repatriation of revenues, international transfers of capital, theremittance of dividends, interests and royalties. (E&Y 2014).
The Global Competitiveness Report during the 2013 Peru is ranked as 61 among 144 countries. According
to this ranking, 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 production scale methodology sets a percentage for royalties (starting at 5.0%) over certain a scale ofproduction (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. On the other hand, under the economic
results methodology, the royalty percentage is set by adding a fixed royalty percentage of 5.0% to a variableroyalty percentage, established according to certain economic results ratios (Ernst & Young 2014).
To promote domestic and international investment in the energy sector, Peru has looked forward to shifting
its legal framework. In 1991, the government passed the Foreign Investment Promotion Law, Supreme
Decree No. 662. A second law, concerning private investment in public services and regulatory agencies(Ley Marco de los Organismos Reguladores de la Inversión Privada en los Servicios Públicos, Law
No. 27332), came into effect in 2000 and provided a framework for private investors in telecommunications,energy, transport and sanitary services, specifying how operations in each of these public service sectors
were to be organised. Overall, Peru strives to ensure proper conditions to attract and retain investment.
Foreign investors are given equal treatment to Peruvians, most activities are unrestricted and several schemes
are possible.
ENERGY EFFICIENCYIn 2010 the Peruvian government create the General Direction of Energy Efficiency (DGEE) as part of the
Ministry of Energy and Mines. The mission of the DGEE is to identify, develop, promote, implement andspread the technologies, process, renewable energies and patterns of consumption to let improve of theefficiency and energy sustainability in the country.
The main goals of the DGEE are:

To reduce the energy intensity, by promoting; the best use of energy; the use of renewable resources;
energy savings and generating a culture of energy efficiency, without affecting the social welfare; and

To make compatible the use of energy with the environment preservation.

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. In line with this legislation, and with the 2007
Supreme Decree No. 053–2007–EM, the Peruvian Government, through the President, created significant
initiatives to support energy efficiency through mechanisms. These include 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 the Supreme 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 fluorescent lamps and acquiring
equipment with energy efficiency labels.
In September 2009, the government through MINEM organised a workshop on efficient use of energy
at which the Referential Plan for the Efficient Use of Energy 2009–2018 was approved. This is the main
instrument to achieve the economy’s energy efficiency goals through action plans proposed for each sector(MINEM, 2009). The Referential Plan aims to reduce energy consumption by 15.0% from the 2007 levels
by 2018 through energy efficiency measures. The plan includes an analysis of energy efficiency in Peru,
identifying sector programmes that could be implemented to achieve the proposed targets.
In workshop discussions, the following actions were identified as current priorities:

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

Develop tax benefits for private companies that operate with efficient technologies;

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P E RU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

Get the commitment of the mining and energy sectors to being role models of efficiency.

On May 2010, the Peruvian Government created the General Directorate of Energy Efficiency (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 economy’s energy planning,
and is responsible for developing the National Energy Plan. This plan must to incorporate the electricity
sector development in line with Peruvian development policies and the Energy Policy Framework 20102040 (El Peruano, 2010).
RENEWABLE ENERGY
Peru has established goals to increase renewable energy use and has set out a legislative and policy
programme to support its development. Electricity generation from renewable resources is being expandedfrom an already significant reliance on hydropower generation. The Law on Promotion of Investment for Electricity
Generation with Renewable Energies (Law No. 1002) was enacted in May 2008, and the Regulations for
Generation of Electricity with Renewable Energies (Supreme Decree No. 050–2008–EM) were issued in
October of that year. Among the incentives contained in the law are (El Peruano, 2008a, 2008b):


a five-year target for the share of domestic power consumption to be generated from renewable energy
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, MINEM established open auctions for renewable energy supplies in order to ensurecompetitive conditions for the electricity generators and their customers. The first auction was completed
in March 2010 and added a total renewable energy capacity to the National Interconnected Electric System(SEIN) of 411 MW, awarded across 26 projects using wind, solar, biomass and mini-hydro. A second
auction, open in the second half of 2011, aimed at obtaining 1981 GWh, out of which 681 GWh wererestricted exclusively for hydroelectric projects (OSINERGMIN, 2011).
To promote renewable energy, in 2006, the government passed Law No. 28876, which provides in advancetax 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 that is based on
renewable energy (including hydro), by means of accelerated depreciation of their investments by up to
20.0% per year in order to improve the projects’ feasibility (MINEM, 2010b).
As for biofuels, government objectives were first set in 2003 and there are three regulations that provide
their legal framework: Law No. 28054 (Biofuels Market Promotion); Supreme Decree No. 013–2005 EM(Regulation of the Biofuels Market Promotion); and Supreme Decree No. 021–2007 EM (Regulation of theCommercialisation of Biofuels). These regulations also establish responsibilities among different
government and agencies:

Ministry of Agriculture (MINAG): Promotes the development of fields for biofuels production;

Ministry of Energy and Mines (MINEM): Authorises the commercialisation of biofuels and theirblending with gasoline and diesel;

Ministry of Production: Authorises the operation of biofuel production plants;



OSINERGMIN: Supervises and controls operations during the different stages of the production
chain; andPROINVERSION: Promotes investment in the biofuels sector.

Under this legislation, quality standards for biofuels and procedures to register a fuel blend with MINEM
were established. A schedule for blending biofuels in the conventional fuel supply was set as well. Beginningin 2010, gasoline must include 7.8% bioethanol and from 2011 diesel must contain 5.0% biodiesel (known
as B5).
Production of ethanol for fuel in Peru began in August 2009, with operations in the northern region of
Piura. In 2011, Caña Brava, the only producing company, reached an output of 0.3 million barrels of ethanol.
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A new ethanol project carried out by Maple Ethanol Peru, began operations in late 2011and includes aprocessing capacity of 0.82 million barrels per year. Sugar cane’s high yields and year-round harvest grants
Peru’s ethanol production a competitive advantage over other producers in the region.
As for biodiesel, its production for 2011 was estimated at 0.1 million barrels. In spite of the volume
produced, imports are still necessary in order to meet Peru’s biodiesel demand, especially in the light of thecompulsory fuel blending standards as described above (MINEM, 2011b).
The Reference Plan for the Efficient Use of Energy establishes up to 15.0% in energy savings for the year2018 in the residential, industrial, services, public and transportation sectors.
The potential market for Renewable Energy Generation can reach a total investment potential of more than
10 thousand million dollars until 2040.
Table 4: Generation Potential – Projection 2012-2014
Renewable Energy
SourcePotential Cumulative
Demand (MW)Installed Investment
Costs (Million
USD/MW)

Total Investment
Potential USD/MW

Photovoltaic

540

2.5-3.0

1 350-1 620

Wind

1 800

1.8-2.0

3 240-3 600

Hydropower

2 000

1.5-1.8

3 000-3 600

Biomass

1 800

1.8-2.5

3 240-4 500

Total

6 140

10 830-13 320

Source: (IFC, 2011).

NUCLEAR
Although Peru does not use nuclear energy for electricity generation, a government-run nuclear program
has been in operation since 1975. This program involved constructing a basic infrastructure, humanresources training, and the establishment of the Peruvian Institute of Nuclear Energy (IPEN) as part of
MINEM. Peru has been a member of the International Atomic Energy Agency since the creation of thatinternational body in 1957. The mission of the IPEN is to promote and develop research and nuclear
applications to improve the country competitiveness and the quality of life of its inhabitants.
In late 2009, IPEN presented its Institutional Strategic Plan 2010-2016. The document comprises three main
objectives, one of them regarding the promotion of electricity generation based on nuclear energy (IPEN2009).
CLIMATE CHANGE
As one of the economies most vulnerable to climate change, Peru has looked forward to implementing aneffective and sustainable strategy for adapting to and mitigating its effects.
As part of its environmental strategy policy, in October 2003 the Peruvian Government, by Supreme Decree
No. 086–2003–PCM, approved the National Strategy on Climate Change (NSCC), for the mitigation of an
adaptation to climate change (El Peruano 2003). The main objectives of the NSCC are to reduce climatechange impacts by means of integrated studies of vulnerability and adaptation, and to control both local
pollution and greenhouse gas emissions through the use of renewable energies and energy efficiency
programmes in production sectors.
The NSCC was subsequently updated in 2009, and in May of that year the Climate Change Commission,
which brought together regional, social, academic and private participants, was created.
After the United Nations Climate Change Conference of Parties (COP16) held in Cancun, Mexico in late2010, Peru submitted its Nationally Appropriate Mitigation Action (NAMA) in which it agrees to reduce its
emissions by accomplishing the following objectives (UNFCCC, 2011):


Reduction to zero of net deforestation of natural or primary forests;Modification of the current energy grid, so that renewable energy (non-conventional energy,hydropower and biofuels) represents at least 33.0 per cent of the total energy use by 2020; and150

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Design and implementation of measures, which allow the reduction of emissions caused by theinappropriate management of solid waste.

Peru’s international climate change commitments are the responsibility of MINAM, which is in charge ofthe design and execution of related policies. As of 2011, MINAM had reported progress on several of Peru’s
climate change projects and defined new specific priorities to be tackled. International cooperation andsufficient funding of projects were stressed as specific factors needed to carry out projects successfully(MINAM, 2011). In 2014, Peru will be hosting the COP20 conference and will receive approximately 15000 people representing 194 countries and actors in international organisations, civil society, private sector
and various media as well as presidents and ministers, all in a period of fifteen days. The main goal of the
COP20 is to obtaining a new climate agreement.
NOTA BLE EN E RG Y D EV EL O PM E NT S
In 2014, the Peruvian Government presented the New Energy Plan: 2014–2050. The main goals of theEnergy Plan are as follows:

To provide energy security and universal access to the 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 and GLP and diesel; and

Tried to keep energy prices in real terms.

At the same time, the Plan considers the expansion of gas pipelines to cover the whole coast region.
It is expected that this will increase the consumption of natural gas in Peru in the 2025 to reach almost the
35.0% of the final energy demand.
The plan mentions some social indicators as is summarised as follow:
Electric Frontier: 99.0% of the population with direct access to electricity;Connexions to natural gas grid: 1 800 000 in 2025 versus 164 000 in 2013.

The Government considers the plan its main guide for reaching the long-term goals of efficiency. The
total amount of investments will be at least USD 49 650 million.
Table 5: Investments required according to the New Energy Plan 2014-2025
GDP 4.5%

GDP 6.5%

Generation

6 700

7 300

Transmission

1 700

1 700

Upstream

5 200

6000

Gas pipelines

11 55011 680Petrochemical

5 000

5 000

Upstream

16 00018 000Downstream Refineries

3 500

3 500

49 65053 180Electricity

Gas

Oil
Total *USD Millions
Source: (Plan Energético Nacional 2014-2025).

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P E RUREFERENCESBCRP (Banco Central de Reserva del Perú) (2013), Memoria
http://www.bcrp.gob.pe/publicaciones/memoria-anual/memoria-2013.html

Anual

2013.

——(2014). Series estadísticas. www.bcrp.gob.pe
EDMC (Energy Data and Modelling Center) (2014). APEC Energy Database, Institute of Energy
Economics, Japan. 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. 4 June 1999.
http://www2.osinerg.gob.pe/MarcoLegal/docrev/LEY-27133-CONCORDADO.pdf——(2003). Aprueban la Estrategia Nacional de Cambio Climático, Decreto Supremo No. 086–2003–PCM,
27 October
2003.
http://www2.congreso.gob.pe/Sicr/CenDocBib/cat_uibd.nsf/RepLegPeruana?OpenForm&CAR
PETA=%28CAMBIO_CLIMATICO_Y_BIODIVERSIDAD%29&FIN——(2008a). Decreto Legislativo 1002, 2008. http://www.minem.gob.pe/archivos/legislacion9ozj22z9ap5zz33zDL_de_promocion_de_la_inversion_para_la_generacion_de_electricidad_con_el_uso_de_energia
s_renovables_1002.pdf——(2008b).
DecretoSupremoNo. 050–2008–EM,
2008.
http://www2.osinerg.gob.pe/MarcoLegal/docrev/DS-012-2011-EM-CONCORDADO.pdf——(2009).
DecretoSupremoNo.
057–2009–RE,
http://www.sunat.gob.pe/legislacion/tupa/2009/normas/ds057-2009.pdf

21 August

2009.

——(2010).
DecretoSupremoNo.
026–2010–EM,
28 May2010.
http://www.minem.gob.pe/minem/archivos/file/Electricidad/normatividad/DS%20026-2010em.pdf
Ernst & Young (2014). Global Oil andhttp://www.ey.com/GL/en/Industries/Oil---Gas

Gas

Tax

Guide

2014.

June

2014.

INGEMET. Depósitos de Uranio en el Perú y su potencial económico. August 2007
INEI (Instituto Nacional de Estadística e Informática) (2011a). Evolución de la pobreza monetaria 20092013.
——(2011b). 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
IPEN (Instituto Peruano de Energía Nuclear) (2009).Plan Estratégico Institucional 2010-2016.
www.ipen.gob.pe/site/transparencia/transp_2012/plan_org/pei2010_2016.pdf
International Finance Corporation (IFC). 2011. Assessment of the Peruvian Market for Sustainable
Energy Finance. Executive Summary.
MINAM (Ministerio de Ambiente) (2011).Compromisos internacionales.
http://cambioclimatico.minam.gob.pe
MINEM (Ministerio de Energía y Minas) (2002).Lineamientos de Política de Largo Plazo para el Sector Energía,
www.minem.gob.pe——(2009). Plan Referencial para el Uso Eficiente de la Energía 2009–2018. www.minem.gob.pe——(2010a). Política Energética de Estado Perú 2010–2040. www.minem.gob.pe——(2010b). Perú Sector Eléctrico 2010. Documento Promotor. www.minem.gob.pe——(2011a). Anuario Estadístico de Hidrocarburos 2011. www.minem.gob.pe——(2011b). Balance Nacional de Energía 2011. www.minem.gob.pe——(2011c). Informe Anual de Reservas de Hidrocarburos 2011. www.minem.gob.pe——(2012).’Nueva Matriz Energética Sostenible y su Evaluación Ambiental Estratégica, como Instrumentos dePlanificación’. www.minem.gob.pe152

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P E RU——(2014). Plan Estratégico Nacional 2014-2025
OSINERGMIN (Organismo Supervisor de la Inversión en Energía y Minería) (2011). Gerencia Adjunta
de Regulación Tarifaria – GART. Energías Renovables.
www2.osinerg.gob.pe/EnergiasRenovables/EnergiasRenovables.html
Peru LNG (2011)
http://portal.perulng.com/irj/go/km/docs/documents/PLNG%20Website/index.htm.
Perupetro (La Agencia Nacional de los Hidrocarburos) (2011). Embarques de gas natural para fines deexportación. http://www.perupetro.com.pe
PlusPetrol (2011). Proyecto Camisea. www.pluspetrol.net/camisea.html
Repsol (2011). Refinería La Pampilla. http://www.repsol.com/es_en/
USGS (United States Geological Survey). www.usgs.gov.
United Nations Framework Convention on Climate Change (UNFCCC) (2011). The Cancun Agreements.
http://cancun.unfccc.int/mitigation/
U SEF UL LI N K S
Agencia de Promoción de la Inversión Privada—— http://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
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

153(2010).——APEC E N E RG Y O VE R VI E W 2014

T H E P H I LI P P I N E S

THE PHILIPPINESI N T ROD U C T I ON

The Philippines is an archipelago consisting of 7 107 islands and covers a total land area of 300 000 square
kilometres and with coastline of 36 289 kilometres. It is located in the south-eastern part of Asia andbordered by the Philippine Sea on the east, the South China Sea on the west, the Luzon Strait on the north,and the Celebes Sea on the south. It has three major geographical divisions—Luzon, Visayas and Mindanao
islands. Manila, which is located in Luzon, is the capital of the Philippines and identified by the World Bank
as one of the 120 largest cities in the world. The economy’s total population in 2012 reached 96.7 million, a
1.7% increase from 2011 levels. The economy is the twelfth most populated in world population ranking
and seventh in Asia (WB IBRO-IDA, 2014).
In 2012, the Philippine economy posted a GDP of USD 569.5 billion (USD 2010 Price and 2010 PPP),
registering a 6.8% increase from the previous year and outpacing the growth of its neighbouring countries.
Such impressive growth was due to robust performance of the service and industry sectors, which grew by
7.4% and 6.5%, respectively, as well as to favourable macroeconomic environment. Government spending
also exhibited a huge growth, specifically in public construction, which was up by 32.0% (Navarro and Yap,2013), (PSA-NSCB, 2012). In view of the sturdy growth of the economy, per capita GDP (USD 2010 PPP)
also improved by 5.0% from 2011 level of USD 5 609 (EDMC, 2014).
The economy is also blessed with indigenous energy resources with modest proven reserves of around126.1 million barrels of oil (includes condensate), 87.6 billion cubic meters (3,092 billion cubic feet) of
natural gas and 438.8 million metric tonnes of coal. The Philippine government’s policy is to continue
harnessing domestic energy resources, such as fossil fuels, to reduce dependence on imported energy, as
well as to increase the economy’s energy self-sufficiency level. On the other hand, the economy’s renewableenergy sources contributed a significant share of 28.5% to the total power generation in 2012. Hydro andgeothermal provided a 14.0% share each to the generation mix, while biomass, wind and solar added a
combined share of less than 1.0% (DOE, 2013c).
Table 1: Key Data and Economic Profile, 2012
Key dataa

Energy reservesb

Area (thousand sq. km)

300

Oil (billion barrels)c

126.1

Population (million)a96.7

Gas (billion cubic metres)c87.6

GDP (USD (2010) billion at PPP)b

569.5

Coal (million tonnes)c438.8

GDP (USD (2010) per capita at PPP)b

5 889

Uranium (kilotonnes U)–

Sources: a. (WB, 2014); b. (EDMC, 2014); c. (DOE, 2013).
E N E RG Y S U P P LY A N D D E M A N D

PRIMARY ENERGY SUPPLY
In 2012, the total primary energy supply stood at 42 668 kilotonnes of oil equivalent (ktoe), up by 7.3 fromthe 2011 supply level of 39 756 ktoe (EDMC, 2013). Of the total, 55.0% came from indigenous energy
sources and the remaining were imported. The economy’s energy self-sufficiency level declined from 58.0%
in 2011 due to reduced contributions of natural gas as a result of a maintenance shutdown and from thedecreased percentage share of renewable energy. Natural gas registered a 7.4% share of total primary energy,
lower than its 2011 share of 8.3%, while the share of renewable energy also decelerated from 40.4% to38.0% for the same period. Oil and coal, which are mostly imported, contributed 32.4% and 21.8% shares,
respectively (DOE, 2013b).
FOSSIL ENERGY
To meet the growing energy demand of the economy, its net imports increased by 8.5% from 18 100 ktoe
in 2011 to 19 632 ktoe in 2012. About 70.0% of the total energy imports were oil and oil products, and theremaining was coal (29.0%) and biofuels (1.0%).
The surge on energy imports was due mainly to increased coal demand for power generation. Demandfor imported coal went up by 32.8% in 2012 from its previous year’s level. Domestic coal production likewise154

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improved by 6.8%, of which more than 90.0% of coal production came from Semirara Mining Corporation
as the major coal producer. On the other hand, oil imports grew by 10.7% in the same year to compensate
for decreased share of indigenous fuels (DOE, 2013b).
RENEWABLE ENERGY
The economy’s renewable energy sources contributed substantially to the supply mix portfolio, specificallyfor power generation, providing 38.0% share to total primary energy supply in 2012. Geothermal, whichbeing used primary for power generation, has been a major renewable energy source accounting for about
36.5% share to total indigenous primary energy supply. The Philippines still remains the second-largest
producer of geothermal energy in the world, next to the United States, with a total installed capacity of 1
848 MW. Hydro and biomass resources registered a combined share of 30.6% to the total indigenous energy
supply.
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 potentials. As stipulated in the
National Renewable Energy Program (NREP), the economy intends to triple the 2010 renewable energy
base installed capacity, as an aspirational target, for power generation, as well as its contribution to nonpower application to increase renewable energy share to the primary energy mix by 2030 (DOE, 2013).
ELECTRICITY GENERATIONThe economy’s total electricity generation in 2012 grew by 5.6% from 69 050 GWh in 2011 to 72 921 GWh.
Power generation from coal-fired power plants contributed the largest share at 38.8%, followed by natural
gas-fired at 29%. Hydro and geothermal both exhibited 14.0% shares of the total power generation mix.
Electricity generated from hydro demonstrated an improvement of 5.7% from its 2011 level. For the otherrenewable resources, biomass posted a remarkable increase at 58.6%. Solar registered an increase inelectricity generation by 8.9%, while wind declined by 14.6%. Contribution from oil-based thermal plants
went up by 25.0% providing additional power requirements for the economy, specifically in Luzon andMindanao grids. Self-sufficiency in power generation in 2012 stood at 58.8% (DOE 2013c).
Table 2: Energy Supply and Consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

23 435 Industry sector

5 845 Total

72 921

Net imports and other19 632 Transport sector

8 108

Thermal52 160Total PES

42 668 Other sectors

9 549

Hydro

10 252Coal

9 316 Total FEC

23 502

NuclearOil

13 826

Coal

1 897

Geothermal

Gas

3 159

Oil

11 556

OthersOther

16 367

Gas

1

Electricity and other10 250259

10 048Sources: (EDMC, 2014).

FINAL ENERGY CONSUMPTION
In 2012, the total final energy consumption of the economy reached 23 502 ktoe, posting an increase of
2.4% from 2011 level of 22 961 ktoe. The transport sector remained the most energy-intensive sector
accounting for the largest share of 34.5% of total final energy demand. Its energy consumption also grewby 4.1% as compared to last year’s negative growth. Meanwhile, the industry sector recorded a share of
25.0%, becoming the third biggest energy consumer next to transport and residential sectors. However, thesector’s energy consumption slightly dropped by less than 1.0% coming from a negative growth in 2011.
The other’ sectors energy consumption accounted for an aggregate share of 40.0% in 2012. The residential
sector displayed a declining growth pattern in its energy consumption, which may be attributed to a
reduction in biomass and kerosene demand due to shift in more efficient fuel like LPG (DOE, 2013b).
As for fuel type, petroleum products continued to be the dominant fuel for the economy accounting
for nearly half (49.2%) of total energy demand, and recorded a growth rate of 2.3% from 11 296 ktoe in155

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2011 to 11 556 ktoe in 2012. Electricity and others (biomass) registered an aggregate contribution of 42.7%
share to the total. Electricity demand expanded by 5.5% from last year’s level of 4 824 ktoe, while biomass
consumption reduced by 1.4%. On the other hand, coal consumption showed an increase of 3.21% fromthe previous year’s level, and natural gas consumption remained relatively the same over the same period.
ENERGY INTENSITY ANALYSIS
Table 3: Energy Intensity Analysis, 2012
Energy Intensity (tonnes of oil
equivalent per million USD)

Energy2011

Change (%)

20122011 vs 2012

Primary Energy

74.6

74.9

0.5

Final Energy Demand

43.1

41.3

-4.2

Industry

11.0

10.3

-6.4

Transportation

14.6

14.3

-2.5

Others

17.5

16.8

-4.1

Sources: (EDMC, 2014).

Overall, the GDP growth rate of 6.8% in 2012 (USD 2010 Price and 2010 PPP) resulted in 7.3%
improvement in the economy’s total primary energy supply. This could be translated to an economy-wideprimary energy intensity level of 74.92 tonnes of oil equivalent per USD million GDP (toe/USD million)
with a nil increase of 0.5% from last year.
For final energy demand, intensity level decelerated by 4.0% from 2011 level. Among the sectors, theindustry sector registered the largest reduction in energy intensity at 6.4% from last year’s levels. Such adrop in energy use, despite the increase in production, may be credited to applying more energy-efficienct
production processes and technologies. On the other hand, the transport sector posted a lower intensity at
14.24 toe/USD million, a decrease of 2.5% from its previous year’s level as a number of vehicle owners are
becoming judicious in fuel use and adopting more fuel efficient vehicle due to continuous increase inpetroleum prices.
POLI C Y OV ERVI E W
ENERGY POLICY FRAMEWORKThe Philippine Energy Plan (PEP 2012-2030), which was launched by the Department of Energy (DOE),
is the central policy framework set forth in ERA. The Plan aims to ensure the delivery of secure, sustainable,
sufficient, affordable and environment-friendly energy to all economic sectors. To pursue the goal, thegovernment will accelerate private sector participation, as well as involve other stakeholders (DOE, 2013).
The Plan has the following policies:

Expand energy access;

Promote a low-carbon economy;

Climate-proof the energy sector;

Develop regional energy plans;

Promote investments in the energy sector; and

Identify and implement energy sector reforms.

In support of these policy thrusts, the Plan also set quantifiable targets to be attained by 2030 as
follows:

Triple renewable energy capacity by 2030;

Complete 90.0% household electrification by 2017 and 100.0% local electrification level for sitios (anadministrative-territorial category in the Philippines) by 2015;



Achieve 30.0% of all public utility vehicles running on alternative fuels;

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T H E P H I LI P P I N E SImplement a higher blend of biofuels; andAttain 10.0% energy savings on total energy demand.
ENERGY MARKETSOIL AND GAS
The government has been aggressively pursuing the exploration and development of indigenous oil and gas
resources through the conduct of Philippine Energy Contracting Round (PECR). PECR is a bidding process
started in 2003 to encourage both local and foreign companies to engage in exploration activities for the
economy’s 16 sedimentary basins. These sedimentary basins have a combined potential of 4,777 million
barrels of oil equivalent (Mboe) (or 689.8 Mtoe) of oil and gas reserves (DOE, 2013).
The DOE has been supervising and monitoring 29 existing petroleum service contracts (SCs), which include
the three newly awarded SCs as a result of the PECR4 held in June 2011 (DOE, 2013). Of note, thegovernment received 20 bid proposals for the 15 prospective offered areas under PECR4 (DOE, 2013a).
Investment road shows were even conducted in other APEC economies (i.e. Australia, Singapore and USA)to invite foreign exploration companies to join the energy contracting round.
In 2012, the economy’s existing oil and gas fields yielded a production of 1.64 million barrels (mmb)of oil, 137.77 billion cubic feet (bcf) of natural gas, and 4.75 mmb of condensate. The reduction of oil
production by 28.7% from last year’s level of 2.3 mmb was due to unavailability of Galoc field for threemonths as a result of technical problem on the vessel used of production (DOE, 2013a).
Malampaya is the largest producing gas field in the economy and its primary source for natural gas
with an estimated daily production capacity of 11.7 million cubic metres (399 million cubic feet) in 2012.
Libertad is the other natural gas field with estimated daily capacity of only 0.211 mmcf. The contribution ofnatural gas to total indigenous energy supply in 2012 was at 13.3%. However, production was down by
1.8%, which was attributed to the preventive maintenance of the shallow water platform (SWP) of
Malampaya. This also caused a reduction of 4.6% from electricity generated by natural gas (DOE, 2013b).
COAL
The economy has domestic coal resources, which is endowed with 13 coal basins. These coal basins havean estimated total potential resource of 2.4 billion metric tonnes. Among the basins, Semirara in Antique(Visayas) has the largest coal resource potential at 570 million metric tonnes (MMmt). In-situ reserve isestimated at 438.8 MMmt. The economy’s total coal production in 2012 was recorded at 7.3 MMmt at 10000 BTU/lb, a minimal improvement of 5.8% from 2011 level of 6.9 MMmt. Semirara Mining Corporation
contributed 94.0% to the total coal production. Domestic coal production was around 41.6% of the total
coal requirement (DOE, 2013b).
From the results of the PECR4, 11 new Coal Operating Contracts (COCs) were awarded in 2013
(DOE, 2013). The DOE accepted 57 proposals of the 67 submitted proposals for the 38 prospective coalareas offered under PECR4. As regards the development of small-scale coal areas, the DOE awarded 26
small-scale coal mining permits in different parts of the member economy in 2012. To prevent proliferationof illegal mining and trading activities, the DOE issued Guidelines on the Accreditation of Coal Traders andRegistration of Coal End-Users (DOE, 2013a).
As of 2012, the DOE has supervised and monitored 53 COCs composed of 31 COCs under thedevelopment and production stage, and 22 COCs in the exploration phase.
MARKET REFORMSELECTRICITY
The current administration is keen on pursuing the remaining reforms of the Electric Power Industry
Reform Act (EPIRA) of 2001 to include the effective implementation of the Retail Competition and Open
Access (RCOA). RCOA is seen to improve competition in the generation and supply sector that would leadto competitive tariff for electricity. Public consultations were conducted to gather comments andsuggestions from the industry stakeholders on the general policies and guidelines that will govern theimplementation of RCOA (DOE 2012).
The DOE and the Energy Regulatory Commission (ERC) issued a joint resolution setting the date forthe initial implementation of RCOA on 26 December 2012, which will be on a phase-in and partial
implementation program. It is envisaged that the initial implementation will be for a period of six months
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as transition period to ensure smooth transition to full implementation 26 June 2013. The transition period
will be expended for registration and discussions, trainings and simulations among suppliers, contestablecustomers and other stakeholders. During the transition, distribution utilities will still be allowed to serve
the contestable customers (markets) located within their respective franchise areas. Contestable customers
are those with an average load requirement of one (1) MW in the last 12 months. Further, the contestablecustomers may also enter into supply agreements with suppliers, but will only take effect at the end of thetransition period (DOE, 2013a).
In January 2013, the DOE issued a Department Circular promulgating the Retail Rules for the
Integration of RCOA to the Wholesale Electricity Spot Market (WESM). This is to provide the rules forthe integration of the retail competition in the operations and governance processes of WESM, managementof the transactions of suppliers and contestable customers, as well as the operations of the Central
Registration Body (CRB) (DOE, 2013).
On the privatisation of the remaining generating assets of the National Power Corporation (NPC),
the Power Sector Assets and Liabilities Management Corporation (PSALM) has to privatise a total of 1,913
MW of generating assets composed of power barges, thermal plants, and hydro plants. More than half ofthese generating capacities are located in Mindanao, which are mostly hydro power plants (DOE, 2014).
As of April 2013, the privatisation proceeds already reached USD 21.76 billion with actual collections
amounted to USD 6.37 billion. About 70% of the collection was utilised for prepayments of NPC debts andregular debt service. The sale of sub-transmission assets (STAs) involved 131 sale contracts with 107
interested distribution utilities, mostly Electric Cooperatives (ECs). The STAs covered 6 200 ckt-km oftransmission line, majority of which is comprised of 69 kV lines, and 1 600 MVA of substation capacity. For
the same period, the National Transmission Corporation (TransCo) signed 106 contracts with the 76
DUs/ECs/consortia with a total of PhP 5.75 billion. The assets include 3,900 ckt-kms of sub-transmission
lines, 35 600 sub-transmission structures, 865 MVA of substation capacity. Out of the signed sale contracts,
45 contracts with total sale price of PhP2.3 billion were already approved one contract disapproved by ERC.
The remaining contracts (60 contracts) are still for ERC filing and approval (DOE, 2013d).
To immediately a provide solution to the looming power crisis in Mindanao, the DOE directed thePhilippine Electricity Market Corporation in January 2013 through a Department Circular to develop andimplement an Interim Mindanao Electricity Market (IMEM). The IMEM shall be a mandatory program for
all generating capacities, DUs, and customers with embedded generation to address the deficiency of supply
in the Mindanao grid. It will serve as a venue to efficiently utilise all available capacities in the grid to provide
additional supply capacities (DOE, 2014).
Another measure being implemented in Mindanao grid is the Interruptible Load Program (IPL). In
this program, customers of a DU will be compensated for voluntarily de-loading itself from the grid byoperating its generation facility for its own use during peak demand hours. The DU will then charge andcollect from the customers within its franchise area the corresponding energy ‘freed up’ (in kilowatt-hours)by the ILP customers, which will be used to pay the said ILP customers based on the ERC-approved ILP
rates (DOE, 2013).
By the end of December 2012, the economy’s barangay (a village, district or ward, i.e. the basic politicalunit) electrification level already stood at 99.9% with only six (6) barangays left, all in Mindanao, to beprovided with electricity. For sitio and households, the energisation levels had already reached 72.8% and77.9%, respectively (DOE, 2013a). It has been a challenge for the government to provide access to electricity
in some areas due to geographical landscape of the Philippines. With this, the government has devised amechanism to energise areas isolated from the grid through decentralised RE system like photovoltaic solar
home system (PV-SHS) and the Qualified Third Party (QTP) program. The QTP opens the unviable areasfor private sector investment, which will provide an integrated power generation and distribution service tothe households.
OIL
The DOE is mandated under the Downstream Oil Industry Deregulation Act of 1998 to closely monitor
the various activities of the industry and the price levels to ensure continuous and stable supply, andreasonable price of petroleum products in the economy. As of December 2012, a total of 1,908 players are
not engaged in different activities of the oil industry (e.g., marketing, distribution and storage) after 14 yearsof the implementation of the Act with total accumulated investment of PhP42.6 billion (DOE, 2013a).

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To address the risks from supply-related problems such as geopolitical uncertainties and calamities,
the government has still enforced the Minimum Inventory Requirement (MIR) on oil companies, bulk and
LPG suppliers. For refiners, the MIR is 30 days for total in-country-stocks of crude and finished products.
Meanwhile, bulk marketers and LPG players are required to maintain 15 days and 7 days MIR, respectively.
The DOE likewise conducted regular inspection and sampling of petroleum products for complianceto quantity and quality standards at the refineries, depots/terminals, gasoline stations, and LPG
establishments in the member economy. As a statutory mandate of the DOE, monitoring of oil pricemovements for both international and domestic markets has been consistently undertaken to prevent
unreasonable adjustments and abuses.
An Independent Oil Price Review Committee was established in 2012 for the review of Oil
Deregulation Act with a primary focus on pricing to determine if there is accumulation of excessive profits
and unfair pricing. The final report of the review was submitted to DOE. Some of the major findings were:Fair price is been achieved under the Oil Deregulation Act;

Pump price movements to changes in world oil prices have been symmetrical; andOil companies’ profits are reasonable (DOE, 2013a).

DOWNSTREAM NATURAL GAS
The government has considered the development of natural gas as an important component of fueldiversification and a priority industry of the energy sector. Natural gas is seen as one of the feasible
alternatives to oil-based energy for power generation, transport and industrial uses.
The Malampaya Gas-to-Power Project (MGPP) in 2001 paved the way for the birth of the natural gas
industry in the Philippines, and contributed significantly in the economy’s primary energy supply and power
generation mix reducing energy imports. However, the industry confronted a major challenge, which is
putting in place the necessary infrastructure development to further promote the use of natural gas,
specifically for non-power processes. Several concerns caused the delay of infrastructure development,
among which were supply availability and sustainability and the issue of the anchor market needed to justify
private investments. Despite these challenges, the government has put forward measures and strategies forthe expansion of natural gas industry. Proposals from the private sector to engage into different businessprospects of the gas value chain have been received by the government. The government is also cognisantthat natural gas imports to supplement local production from Malampaya gas field will be necessary to meetthe projected demand from the potential market, if there are no new natural gas discoveries.
The government likewise is aware of the urgency of establishing a clear and comprehensive policy
regarding the regulatory framework as a requisite for the development of the downstream natural gas
industry. In light of this, a Natural Gas Bill has been drafted and filed to both Houses of Congress. The
Department Circular issued by the DOE in 2002 on the ‘Interim Rules and Regulations Governing theTransmission, Distribution and Supply of Natural Gas’ serves as an interim policy governing the natural gas
industry.
The 2002 Master Plan Study for the Development of the Natural Gas Industry in the Philippines has
been updated in March 2012 through the technical assistance of the Japan International Cooperation Agency(JICA). A complementary study was done by the World Bank (WB) for the supply of natural gas in Luzon
and Mindanao, which covered aspects on current and existing LNG transportation, receiving, storage andregasification approaches, and the analysis of a suitable LNG terminal site in the region. A parallel study was
also undertaken by the WB for the ‘Mindanao Natural Gas Market Development Strategy.’ The study preidentified that a power plant project (around 500 MW) will justify the investment for the proposed Floating
Storage Regasification Unit (FSRU) facility in Mindanao (DOE, 2013).
The DOE entered into an agreement with Pilipinas Shell Petroleum Corporation (PSPC) to conduct atechnical feasibility study on a Floating Storage Regasification Unit (FSRU), which will be placed in theprovince of Batangas. For pipeline development, the Philippine National Oil Company (PNOC)
commissioned the Public-Private Partnership (PPP) Center and JICA for the detailed feasibility study of the
105-km Batangas-Manila pipeline (DOE, 2014).
ALTERNATIVE FUELSAs the economy confronts the growing energy demand, coupled with the global issue on climate change,
the government has embarked on implementing policies and programs on alternative fuels for the transport
sector, which is the largest energy-consuming sector. The government recognises the critical role of both

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alternative fuels in reducing the economy’s dependence on the highly volatile oil market and thediversification of energy resources so as to include indigenous and more environment-friendly alternative
fuels. With the passage of the Biofuels Act of 2006 and the developments in other alternative fuels such as
Compressed Natural Gas (CNG), auto-LPG and e-vehicles, the government will ensure sustainability in thedevelopment and utilisation of these alternative forms of energy sources.
In the Biofuels Act, the government mandates the use of 2.0% biodiesel and 10.0 bioethanol blendswith diesel and gasoline, respectively, harnessing domestic feedstock. The DOE has entered into partnershipwith various academic institutions and other stakeholders for the continuous conduct of research anddevelopment on other potential feedstocks for biodiesel and bioethanol, as well as for the proposed increasein biodiesel blend from 2.0% to 5.0%, and testing for the application of higher biodiesel blend to ‘jeepney’
as a common public utility in the Philippines (DOE, 2013).
In support of the campaign to promote the use of cleaner and alternative fuels, the Land
Transportation Franchising and Regulatory Board (LTFRB) through the Department of Transportation andCommunications (DOTC) granted preferential approval of franchise applications for CND-fed buses. In
addition, the exemption of CNG-buses from the Unified Vehicle Volume Reduction Program has been
extended (DOE, 2013a).
For auto-LPG, the LTFRB extended the number of years of franchise granted for taxis that converted
to auto-LPG by two (2) years, which now provided 15 years franchise contract (from the original 13 years
contract) to promote new players in the program. To ensure the safety of the conversion of taxi fleets, theDOE together with the Bureau of Product Standards (BPS) of the Department of Trade and Industry
developed and promulgated the Philippine National Standards for auto-LPG. The Development Bank of
the Philippines (DBP) offers reasonable financing package for the acquisition of auto-LPG vehicles andother related activities as part of its Clean Alternative Transport Fuel Financing Program (DOE, 2013).
Another initiative of the government is the electric vehicle program, which is seen to contribute to
reducing petroleum consumption and achieve lower emission level. Under the Asian Development Bank
(ADB) Loan Assistance Program, 100 000 electric tricycle or e-trike (a motorcycle with an attachedpassenger sidecar—a three-wheeled vehicle—used as local-based public utility vehicle) will be purchased toreplace the two-stroke tricycle. It is estimated that the shift to 100 000 e-trike will result in reduction ofannual petroleum consumption by 89 million liters. A contest was even conducted nationwide for the ‘Best
E-Trike Design’ for the local fabrication of the said e-trike (DOE, 2013a). The program has been promotedwith the local government units (LGUs) nationwide. The e-trike is set to be deployed by 2014.
ENERGY EFFICIENCYEnergy efficiency and conservation program is a crucial component of the economy’s energy plan to temper
the growing demand for energy. The government has been implementing several initiatives and still finding
ways to efficiently manage energy use to support a growing economy and bring down greenhouse gas (GHG)
emission. In achieving the benefits from energy efficiency and conservation program, technology
development and lifestyle change have been aggressively pursued by the government.
With the launching of the National Energy Efficiency and Conservation Program (NEECP) in 2004,
the government in partnership with the stakeholders continuously works on the development andintroduction of new efficient technology, and on the promotion on the changing energy consumption
practices in homes, business and vehicles. To further strengthen the NEECP, the DOE developed a new
branding for its campaign with a theme ‘Bright Now! Do Right, Be Bright’ in 2011, which intends to promote
efficient use of energy, and educate and empower the public to be smart energy users. The promotion of
the branding for the new campaign started in 2012 (DOE, 2013).
The NEECP is comprised of several measures, programs and projects catering to different sectors
and/or entities, which include, among others: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;

Voluntary Agreement Program;

Recognition Award Program;

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Fuel Conservation and Efficiency in Road Transport (FCERT):oFuel Economy Run Program (part of IEC to establish significant data for a vehicle labelling
program in the future);Power Conservation and Demand Management (Power Patrol); and

Other programs/projects with technical assistance from donor institutions such as:o

The Philippine Industrial Energy Efficiency Project (PIEEP), a United Nations Industrial
Development Organisation-Global Environment Facility (UNIDO-GEF) assisted and funded
project. The project aims to: promote and introduce energy management and industrial energy
systems optimisation; building capacity of the stakeholders—enterprises, equipment suppliers,
engineering/energy service companies, financial institutions and government planners to
implement system level efficiency improvement, and integration of energy efficiency into
management systems of industrial enterprises through energy management standards. The PIEEP
is expected to generate energy savings from its five-year project implementation (2012-2016)
estimated at 2 058 GWh and GHG reduction of 1 459 133 tonnes of CO2 (DOE, 2012a);o

The Philippine Energy Efficiency Project (PEEP) is a project funded from the AsianDevelopment Bank (ADB) loan with the primary objective of promoting and implementing
energy efficiency and conservation in residential, public and commercial sectors through theintroduction of energy efficient lighting system such Compact Fluorescent Lamp (CFL). The
project is likewise designed to establish sustainable business models for large-scale
implementation of energy efficiency programs, and a certification process for energy andenvironmentally efficient commercial buildings, among others; andoDevelopment Study on Energy Efficiency and Conservation, a Japan International Cooperation
Agency (JICA) technical assistance project. The project intends to assist the DOE in designing
the Energy Conservation Bill, which would institutionalise energy efficiency and conservation
measures. The sub-components of the projects include the IEC campaign, training andcertification program for energy auditors and energy managers, and a National Energy
Consumption Database and System Application Tool (DOE, 2013).

The Energy Efficiency Standards and Labelling Program covers household appliances and lighting
products such as room air conditioners, refrigerators (with storage volume of five cubic feet to eight cubicfeet), and compact and circular fluorescent lamps including ballasts. In the future, the coverage of the
program will be expanded to include other household electric appliances and industrial equipment, such as
electric fan, washing machine, television and industrial fan and blowers, and even vehicles. As part of the‘Do Right, Be Bright’ campaign in 2012, the DOE in partnership with ADB launched the ‘Watt Out!’ TV
Olympics to display to the public the most energy efficient technologies in the market. It also seeks to show
the appliance’s power consumption and its effect on the monthly electricity bill (DOE, 2013a).
The GEMP mandates all government offices to lower down their monthly consumption of electricity
and petroleum by at least 10.0%, which will reduce the public sector’s electricity bill and fuel expenses. The
program generated accumulated savings from September 2005 to December 2012 of PhP 1.77 billion ofelectricity bill and PhP 276 million of fuel expenses, equivalent to 231.8 GWh and 7.47 million litres ofelectricity and fuels, respectively. In 2012 alone, GEMP obtained savings of 47.63 GWh of electricity and0.64 million litres of fuel amounting to PhP 287 million of electricity bill and PhP 26.5 million of fuelexpenses (DOE EUMB, 2014).
Meanwhile, the Don Emilio Abello Energy Efficiency Award (DEAEEA) is being conferred to private
entities in recognition of their initiatives in implementing energy efficiency and conservation measures. In
December 2012, 43 establishments and 25 energy managers were recognised under the DEAEEA. The
aggregate savings reached 56 million litres of oil equivalent amounting to PhP 2.2 billion, and 90 million
kilograms of CO2 avoidance (DOE EUMB, 2014).
For the PEEP, the project has six components, namely:National Residential Lighting Program—Distribution of 8.6 million compact fluorescent lamps (CFLs);

Retrofit of government office buildings—retrofitting of lighting systems of government buildings
nationwide;

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T H E P H I LI P P I N E SPublic Lighting Retrofit Program—Public lighting retrofits of mercury vapour lamps to more efficient
lighting fixtures;Energy Efficiency Testing and Lamp Waste Management—Expansion of the capacity of the DOE’s
testing laboratory to conduct efficiency testing on a wider range of appliances and the accreditation of
the laboratory to ISO 17025. Procurement of Lamp Waste Management facility and the establishmentof a business model for collection of lamp waste;Efficient Building Initiative—Establishment of an efficient building rating system that include a Rating
Scheme for Green Buildings; and

Communication and Social Mobilisation—Production and distribution of information materials for the
campaigns on ‘Communication for Efficient Lighting’ and ‘Promoting Efficiency in Everyday Life’(APERC, 2012).

The project has already completed the distribution of 8.6 million CFLs to the residential sector in 2012.
The estimated electricity savings from the distribution of CFLs to the residential customers would be 264
GWh annually, including a CO2 avoidance of 143 000 tonnes per year (DOE, 2013).
On the other hand, the JICA Development Study Team completed the 5th and last mission in 2012
with a draft proposed Energy Conservation Bill. Said proposed Bill already gained endorsement from a
Congresswoman and a Senator of the Philippines in both Houses of Congress (DOE, 2013). From the
NEECP various programs and projects, the economy was able to save around 4.35 million tonne of oil
equivalent (Mtoe) of fuel and electricity consumption, half of which (2.65 Mtoe) was realised from theEnergy Labelling Program (DOE, 2013a).
RENEWABLE ENERGY
Pursuant to the passage of the Renewable Energy Act of 2008 and the adoption of the NREP (2012-2030)
in June 2011, the government has continuously and aggressively pursued the development and utilisation ofrenewable energy to increase its contribution to the energy mix. The NREP aims to:Increase the utilisation of indigenous RE resources to help ensure the member economy’s energy
security and independence, as well as minimise the adverse impact of modern energy use;Institutionalise a comprehensive approach to address the challenges and gaps hindering the wider
application of RE technologies in a sustainable manner;



Assist the stakeholders including donor institutions to maximise market penetration of RE resourcesin the energy sector; andOutline the action plan necessary to facilitate and encourage greater participation of private sector.

To fully implement the RE Act, other policy mechanisms have to be formulated and implemented,
which include:

Renewable Portfolio Standards (RPS);Green Energy Option Program; andFeed-in Tariff (FiT);

Net- Metering for Renewable Energy.

The draft Renewable Portfolio Standard (RPS) has already been formulated and being reviewed. The
RPS sets the minimum percentage of generation from eligible RE resources provided by the generators,
distribution utilities and electric suppliers. An initial installation target has been set at 760 MW for the first
three years (2013-2015) of implementation broken down as follows:Solar– 50 MW

Run-of-river hydro – 250 MW

Wind – 200 MWOcean – 10 MWBiomass – 250 MW

The initial Feed-in-Tariff (FiT) was already approved by the ERC in July 2012 covering run-of-riverhydro, biomass, wind and solar. FiT is a guaranteed payments on a fixed rate per kWh on RE generation,but excluding generation for own use. ERC deferred the FiT rate for ocean since further study and analysis
must be undertaken. Following are the FiT rates for RE resources:

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

Wind



BiomassSolar

The National Renewable Energy Board (NREB), which was created by virtue of the RE Act, endorsed
the enabling rules for the Net Metering Program on RE to ERC. The Net Metering Program is a consumerbased incentive scheme wherein the electric power generated by the end-users from eligible onsite REgenerating facility, and delivered to the distribution utility, may be used to offset electric energy provided by
the DU to the end-user during the applicable period (DOE, 2013a).



In 2012, a total of 101 RE service contracts were awarded by the DOE with an aggregate ca pacity of
2 566 MW as follows:

Geothermal – 8Wind – 6Hydro – 53

Solar – 27



Biomass – 7

Of the total, five service contracts are for conversion (with total installed capacity of 1 061 MW) toavail of the incentives under the RE Act. For the period 2010-12, the DOE already awarded 258 service
contracts—215 new service contracts and the remaining for conversion (DOE, 2013).
As of 2012, the total installed power generating capacity from RE on the grid stood at 5 521 MW.
Hydro contributed the biggest share of 3 521 MW (197 MW capacity is on off-grid areas), followed bygeothermal with 1 848 MW. The biomass resource, which is a site-specific generating facility, has a total
installed capacity of 117 MW, while wind has a generating capacity of 33 MW and solar with 1 MW in ongrid capacity (DOE, 2013c). Solar is also being used to provide access to electricity in off-grid areas through
PV-SHS.
NUCLEARAs a policy, the government has been receptive to all available energy resources to ensure that the economy
has a secure, reliable and stable energy supply with due consideration to the environment. As such, nuclear
energy for power generation has still remained as a long-term energy option with its merits on supply security
and environmental considerations, specifically in terms of CO2 emissions. The economy may embrace aclear nuclear energy policy in the future with preconditions on advancement in nuclear technology andimprovements in safety and safeguards standards
After the International Atomic Energy Agency (IAEA) Mission Review in 2008 on the Development ofInfrastructure to Support a Nuclear Power Program in the Philippines and the Feasibility of Rehabilitating the Bataan Nuclear
Power Plant, a Joint Department Order between the DOE and the Department of Science and Technology(DOST) was issued for the creation of an Inter-Agency Core Group on Nuclear Energy was created in 2009
with the primary tasks of developing, managing and formulating policies and strategies on nuclear power
generation, as well as study the 19 infrastructure requirements for a nuclear energy program. The CoreGroup is also envisioned to serve as the interim Nuclear Energy Program Implementing Organisation(NEPIO). The Core Group conducted a series of Information, Education and Communication (IEC) in
major cities nationwide to provide information and educate the people on the benefits of nuclear energy
application in the areas of medicine, research, industry and even in power generation, as well as the
disadvantages. Nuclear regulations on safety, security and safeguards were also discussed. The result of the
public perception survey undertaken during the IEC activities revealed that more than 60.0% of theparticipant-respondents expressed support for a nuclear power program.
For the BNPP, a Memorandum of Understanding (MOU) was signed between the National Power
Corporation (NPC) and Korea Electric Power Corporation (KEPCO) in 2008 for the conduct of a feasibility
study on the possible rehabilitation of the 650 MW BNPP, a Pressurised Water Reactor (PWR). The
KEPCO study concluded that the BNPP rehabilitation is technically feasible at a cost of US$1 billion.
However, further undertakings were debilitated after the Fukushima incident in 2011. Despite thesetback in nuclear initiatives, some sectors have still recommended a nuclear power development programin the member economy and even approached the Congress about a resolution/law supporting the program.
In April 2012, the Mindanao Power Summit (Southern of the Philippines) suggested as one of theirrecommendations the establishment of a nuclear power plant to provide long-term solutions to the region’s
power supply requirement. On the other hand, as a manifestation of interest of some local government
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units, local resolutions were issued allowing the national government to look at the feasibility of hosting a
nuclear power facility in their respective areas (ERIA, 2013).
CLIMATE CHANGE
By virtue of the Philippine Climate Change Act of 2009 (RA 9729), the Climate Change Commission has
been created as a policy-making body attached to the Office of the President with the same status as that ofa national government agency. The Commission is tasked to coordinate, monitor and evaluate programs
and action plans relating to climate change. The President of the Philippine will serve as the Chairman of
the Commission and with three-member commission, one of whom will be the Vice-Chair (CCC). The
President of the Philippines also established a Cabinet Cluster on Climate Change Adaptation and Mitigationand increased the budget to address the impact of climate change (Philippine Country Statement, UNFCCC).
A People’s Survival Fund has been put up as a special fund that will be used for climate change adaptation
programs and projects with an initial fund of PhP 1 billion (CCC).
Mindful of the fact that the energy sector is the largest contributor to GHG emission and its role tomitigating the impact of climate change, the DOE puts a premium on formulating a government plan withsignificant contribution towards low carbon economy—that is, with minimal GHG emissions. The PEP
2012-2030 supports the global initiatives on addressing climate change and responsive to the Philippine
President’s Social Contract with the Filipino people on ‘Integrity of the Environment and Climate Change
Mitigation and Adaption’ with accelerated policies, plans and programs on energy efficiency, renewableenergy and alternative fuels (DOE, 2013).
NOTA BLE EN E RG Y D EV EL O PM E NT S
ENERGY REFORM AGENDA
The 2012-2030 Philippine Energy Plan is anchored on the policy framework specified in the Energy Reform
Agenda with an overall vision of ‘Energy Access for More.’ After its launching in 2012, the DOE started
drafting the regional energy plans to address specific local energy issues and concerns. First to be formulated
is the Mindanao Energy Plan (MEP), which contains policies and programs to provide sustainable and longterm solutions to the region’s power supply problem. The MEP was presented to the Mindanao stakeholders
in a series of consultations to gather additional inputs and comments. A draft of the MEP has already been
completed. Next on the drawing board is the Visayas Energy Plan (VEP) and to be followed by the Luzon
Energy Plan (LEP). As a parallel effort, the DOE in partnership with the local stakeholders is also
formulating the Power Development Plan for the provinces, particularly those in missionary areas or notconnected to the main grid. The Palawan, Mindoro and Bohol (a province island but interconnected to the
Visayas grid) Provincial Power Development Plans are being drafted, which will be for adoption by theProvincial Council/Board.
RENEWABLE ENERGY
In support of the Renewable Energy Act, the RPS has been finalised and being reviewed for endorsementby the DOE, while the FiT was already approved by the ERC in 2012. Likewise, the initial installation target
has been set to 760 MW for the next 3 years of implementation. As for the other mechanisms, the Net
Metering policy was also promulgated and adopted. The ERC issued a resolution titled Resolution Adopting
the Rules on Net-Metering Program for Renewable Energy. Meanwhile, the Philippine Electricity Market
Corporation (PEMC) conducted a study with technical assistance from the World Bank entitled Renewable
Energy Market (REM) Development and Draft Market Design Document. REM serves as a sub-market under the
Wholesale Electricity Spot Market (WESM) for trading of RE certificates corresponding to energy generated
from the eligible RE facilities. Such RE Certificates shall be credited in compliance with any obligation under
the RPS.
A Department Circular was issued by the DOE in May 2013 titled the Guidelines for the Selection Processof Renewable Energy Projects under the FiT System and the Awarding of Certificates for FiT Eligibility. Under the
Circular, the RE developer will have to inform the DOE on the date of successful commissioning of a RE
plant, which will be validated by the DOE. In the event that the validation is successful on the date ofcommissioning, the DOE will issue a Certificate of Endorsement (COE) for FiT Eligibility to the ERC ona first-come-first-serve basis. The DOE will issue the COE until the maximum installation target pertechnology is fully subscribed (DOE, 2013e).

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The National Renewable Energy Program or NREP is the economy’s roadmap for renewable energy
development. Its long-term goal is to increase the RE-based power generation capacity to 15 304 MW by
2030, which is to triple the 2010 RE capacity, as well as expand its contribution for non-power uses. To
attain such a goal, the following targets were clearly established in the program:

Increase geothermal capacity by 75.0%;

Increase hydropower capacity by 160%;



Deliver an additional 277 MW in biomass power capacities;



Attain wind power grid parity with the commissioning of 2 345 MW of additional capacity;

Mainstream an additional 284 MW of solar power capacity and pursue the achievement of a 1 528 MW
aspirational target; andDevelop the first ocean energy facility for the economy.

The DOE has been receiving several applications from the private sector for grid connection, off-gridand own-use RE service contacts. As of 2012, the total service contracts awarded by the DOE alreadyreached 256 with an aggregate estimated potential and installed capacity of around 6 000 MW (includes
existing capacities for conversion) (DOE, 2013).
PENDING ACTIONS
A number of legislative agenda is being pursued by the DOE to further strengthen the economy’s energyplans and programs. Relevant bills have been filed in both Houses of Congress, which are intended to put
in place a regulatory framework policy for specific energy sub-sectors, or improve the exiting framework,and provide or enhance existing incentives to encourage more private investments to come in. Among theenergy bills are:

Energy Efficiency and Conservation Act;

Downstream Natural Gas Industry Development Act;

Liquefied Petroleum Gas (LPG) Industry Regulation and Safety Act;Amendments to the Electric Power Industry Reform Act of 2001 or Republic Act No. 9136;



Amendments to the Petroleum Act of 1949 or Republic Act No. 387; andAmendments to Presidential Decree (PD) 87 or the Oil Exploration and Development Act of 1972.
MARKET REFORMS

In connection with the implementation of the EPIRA is the R.A.10150, otherwise known as ‘An Act
Extending the Implementation of Lifeline Rate’ was signed into law in June 2011. Said Act extended theprovision of subsidised rate given to low-income end-users (or market) who cannot afford to pay at full cost
for another ten years, unless the provision is further extended by law.
Several Department Circulars were issued for the commercial operation of RCOA on 26 June 2013. Someof these Circulars were:Transparency requirements to all generators, distribution utilities and electricity suppliers to submit
quarterly relevant information on contracted capacities and duration, rates, customers and sources ofsupply, among others; andSupplemental policies to empower contestable customers under RCOA with wider option on their
supply contracting by allowing them to directly contract with prospective generators and removal ofearly termination clause in the Retail Supply Contract (RSC).

The government will also be establishing a WESM Reserve Market, which will operate in March 2014,as a trading market for ancillary services in the Luzon and Visayas grids. It is envisioned that the powerindustry will benefit from the market through co-optimisation of energy and reserves, which will achieve
greater competition among energy and reserve providers and lead to competitive energy prices.

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The National Electrification Administration (NEA) Reform Act of 2013 was enacted in May 2013 withthe objectives of:Promoting sustainable development in rural areas through rural electrification;

Empower NEA to pursue electrification program; andEmpower electric cooperatives to cope with the changes on the restructuring brought by EPIRA (DOE,2014).

The Household Electrification Development Plan (HEDP) has been finalised and approved to provide
a holistic national plan and program for the attainment of total electrification of all households in a leastcost, equitable and efficient manner. The government is steadfast in its commitment to achieve its targetsof 100.0% sitio electrification level by 2015 and 90.0% household electrification level by 2017.
CLEAN TECHNOLOGY FUND PROJECTThe DOE is revisiting and enhancing the Energy Efficiency and Conservation Roadmap through the EUSwitch Asia Policy Support Program in the Philippines. The overall objectives of the program are to promotesustainable development in the Philippines, and to support the government in implementing a sustainableconsumption and production policy-related framework. One of the program’s outputs is the implementationof policies and regulation related to clean energy and energy efficiency. The updated EE&C Roadmap
intends to enhance and accelerate the implementation of EE&C programs, as well as provide long-term
policy direction for the economy on EE&C initiatives.
GOOD GOVERNANCE AND TRANSPARENCY INITIATIVES
To support the transparency seal and good governance initiatives of the present administration, the DOE
has pursued data and information transparency and exchanges among the energy stakeholders like contract
applications in energy resources development. The DOE has created significant websites such as
kuryente.org.ph and wattmatters.org.ph to provide the public with vital information on specific energy
concerns. The kuryente website allows electricity consumers access to information on all distribution utilities
in their respective franchise areas on electricity rates broken down by components, system losses, collection
efficiency and liabilities, among others. On the other hand, the wattmatters website has information forenergy consumers, especially residential sector, on energy consumption of household appliances, energy
conservation tips, and on the best and more efficient appliances available on the market. The DOE aiming
to expand these services by developing additional websites on petroleum demand and supply, including
pump prices, and on renewable energy projects.
REF ER EN CE S
APERC (Asia Pacific Energy Research Centre, 2012). Peer Review on Energy Efficiency in thePhilippines: Final Report. 09 November 2012.
http://aperc.ieej.or.jp/file/2013/7/23/PREE_201211_Philippines.pdf
CCC (Climate Change Commission). climate.gov.ph/
EDMC (Energy Data and Modelling Center) (2013). APEC Energy Database, Institute of Energy
Economics, Japan. www.ieej.or.jp/egeda/database/database-top.html
ERIA (Economic Research Institute for ASEAN and East Asia). Study on International Cooperation
Concerning Nuclear Safety Management in East Asia Countries. June 2013.
www.eria.org/RPR-FY2012-28.pdf
DOE (Department of Energy) (2014). 2013 Energy Sector Accomplishment Report.
http://www.doe.gov.ph/doe_files/pdf/Transparency_Seal/Annual%20Report%20%20Energy%20Sector%20Accomplishment%20Report%202013.pdf–––– (2013). 2012-2030 Philippine Energy Plan.
www.doe.gov.ph/doe_files/pdf/01_Energy_Situationer/2012-2030-PEP-ExecutiveSummary_revised.pdf––––(2013a). 2012 Energy Sector Accomplishment Report.
www.doe.gov.ph/doe_files/pdf/Researchers_Reports/2012%20DOE%20Accomplishments.pdf

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T H E P H I LI P P I N E S–––– (2013b). 2012 Philippine Energy Situationer (Demand-Supply Situationer)–––– (2013c). 2012 Philippine Power Statistics. www.doe.gov.ph/electric-power-statistics/philippinepower-statistics–––– (2013d). 22nd EPIRA Implementation Status Report (November 2012-April 2013).
www.doe.gov.ph/doe_files/pdf/01_Energy_Situationer/22nd_EPIRA_Status_Report_Final.pdf–––– (2013e). Department Circular on the Guidelines for the Selection Process of Renewable Energy
Projects under Feed-in-Tariff System and the Award of Certificate for Feed-in-Tariff Eligibility.
www.doe.gov.ph/doe_files/pdf/Issuances/DC/DC2013-05-0009.pdf–––– (2012). 21st EPIRA Implementation Status Report (May 2012-October 2012).
www.doe.gov.ph/doe_files/pdf/01_Energy_Situationer/21st%20EPIRA%20Status%20Report_FI
NAL.pdf–––– (2012a). Philippine Industrial Energy Efficiency Project (PIEEP) Brief
DOE EUMB (Philippines Department of Energy, Energy Utilisation Management Bureau) (2014). Emailcorrespondence dated December 2014.
http://www2.doe.gov.ph/Programs%20and%20Projects/Philippine%20Industrial%20Energy%20E
fficiency%20Project.pdf
Navarro, A. Yap, J. The Philippine economy in 2012 and prospects for 2013. Development ResearchNews, Vol. XXXI No. 1 January–March 2013. http://dirp4.pids.gov.ph/ris/drn/pidsdrn12-1.pdf(PSA-NSCB) Philippine Statistics Authority- National Statistical Coordination Board. Philippine
Economy Post 6.8 percent GDP Growth in Q4 2012.
http://www.nscb.gov.ph/sna/2012/4th2012/highlights.asp
UNFCCC (United Nations Framework Convention on Climate Change). Philippines Country Statement,
UN Climate Change Conference in Doha, Qatar (COP18/CMP8), December 2012.
http://unfccc.int/resource/docs/cop18_cmp8_hl_statements/Statement%20by%20Philippines.pdf
WB (World Bank) IBRO-IDA. World Population Ranking. September 2014.
http://data.worldbank.org/data-catalog/Population-ranking-table
U SEF UL LI N K S
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/167

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THE RUSSIAN FEDERATIONI N T ROD U C T I ON

With a land area of more than 17 million square kilometres, the Russian Federation is the world’s largest
economy. It is the only APEC economy located in both Europe and Asia, bordered by the Arctic and theNorth Pacific oceans. Its territory is characterised by broad plains west of the Urals, vast coniferous forests
in Siberia, tundra along the Arctic seaboard, and uplands and mountains in the southern regions. The RussianFederation has a vast natural resource base that includes major deposits of coal, natural gas, oil and otherminerals. Despite its land area advantage, the economy lacks an optimal climate for agriculture—most of its
area has a continental climate, and is either too cold or too dry. Central heating is common for up to 6 to 8
months of the year, while cooling during the summer is not widely used.
According to EDMC (2014), from 1990 to 2009, the Russian population declined from 148.3 million
to 141.9 million. However, from 2009 to 2012, there was an increase of 1.3 million in total population from
141.9 million to 143.2 million. Shares of urban and rural population remain unchanged, at 74.0% and 26.0%
respectively. Russia’s average population density of only 8.4 people per square kilometre is very low, withthe majority of the population living in the European part of the economy (Rosstat, 2014).
The Russian Federation’s economy continued to develop strongly, achieving 3.4% growth in 2012 andan average growth rate of 4.7% for the period 2000–2012. In 2009, the global economic and financial crisis
affected the Russian economy, with the GDP declining by 7.8% in 2009 from the 2008 level. The recovery
in 2010–12 was driven by soaring world prices for oil and natural gas.
Table 1: Key data and economic profile, 2012
Energy reservesa

Key data
Area (million sq. km)

17.1

Population (million)

143 18GDP (USD (2010) billion at PPP)
GDP (USD (2010) per capita at PPP)

3 145.27
22 030Oil (billion barrels)

93.0

Gas (trillion cubic metres)

31.3

Coal (billion tonnes)

157.0

Uranium (kilotonnes U)b

181.4

Source: a. Proven reserves at the end of 2013 (BP, 2014); b. Reasonably assured resources (NE, 2010). All othersources (EDMC, 2014).

The Russian Federation’s major industries include oil and gas production, petroleum refining, mining,iron and the steel, chemicals, machinery and motor vehicles industries. In particular, Russia maintained its
place in the top three automobile markets in Europe, following Germany and the UK. Vehicle production
in 2012 was almost 2 million units. The energy sector’s output accounts for about 30.0% of Russia’s GDP,
which is more than 50.0% of the tax and custom duty payments, 70.0% of total export, and 30.0% of thetotal investment in the economy, and is important not only to Russia’s economic development but to thesurvival of its population during harsh winters.
In terms of proved reserves, in 2013 the Russian Federation holds 17.6% of the world’s gas, 5.5% of
its oil reserves, 17.6% of its coal reserves, and about 14.0% of its uranium ore reserves (BP, 2014). Even
more resources remain to be discovered, 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 50.0% of the economically-recoverable resources have already been produced. In the Urals andVolga regions, resource depletion is thought to exceed 70.0%. The share of remaining resources that are
more complex to recover is constantly growing. Nearly 80.0% of Russia’s oil production comes 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 proved natural
gas resources in Russia, estimated at 31.3 trillion cubic metres, should be adequate to meet both domestic
market and export demands for the foreseeable future.
The remaining proved reserves of coal in Russia amount to more than 157 billion tonnes, or 17.6% of
the world reserves. At current rates of coal consumption in the economy, these reserves should be sufficientfor 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 277.3 million tonnes 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 (17.0% of the global market) and
30 research reactors in 17 economies worldwide, and the economy provides over 40.0% 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 total
economy’s exports. The Russian Federation holds leading positions in each of the world’s energy markets:
40.0% of uranium enrichment, about 20.0% of natural gas trading, almost 20.0% of reactor construction,
15.0% of spent nuclear fuel conversion, more than 10.0% of crude oil and petroleum products trading, andabout 10.0% of coal trading.
In 2013, the Russian Federation exported 234 million tonnes of crude oil, 205.6 billion m3 of naturalgas (including LNG) and 142.9 million tons of coal.
ENE RG Y S U PPLY AN D DE M A ND
PRIMARY ENERGY SUPPLYThe Russian Federation’s total primary energy supply in 2012 was 756.4 million tonnes of oil equivalent(Mtoe), comprising natural gas (51.2%), crude oil and petroleum products (22.3%), coal (17.8%) and others,
including nuclear and hydro (8.7%).
By destination, more than 90.0% 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 the Russian Federation 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 Northeast
Asia.
The Russian Federation produced 521.3 million tons of crude oil and gas condensate in 2012. The oilheartland province of West Siberia accounted for about two-thirds of the total production. Refiners
consumed 277.2 million tonnes of crude oil as feedstock, producing 258 Mtoe of petroleum products,
including 40.7 million tonnes of gasoline and 70.65 million tonnes of diesel oil, 71.72 Mtoe of fuel oil, 20.99
Mtoe of naphtha.
Oil exports declined from 248.81 Mtoe in 2011 to 241.15 million tonnes in 2012. Petroleum products
export amounted of 105 million tons in 2012, a 2.8 Mtoe increase from 2011 level. There are prospective
onshore oilfields in the Timano–Pechora and East Siberia regions and offshore in the Arctic and Far Eastseas, and on the North Caspian shelf.
Natural gas production decreased from 552.9 Mtoe in 2011 to 540.8 Mtoe in 2012. Net exports ofnatural gas in 2012 accounted for 152.2 Mtoe (157.8 Mtoe in 2011) or 28.1% of production. Nearly all
natural gas exports were destined for Western and Central Europe, including Turkey, with small amounts
piped to the Transcaucasian states. Huge but undeveloped reserves of natural gas are located in remoteregions, where the lack of infrastructure prevents the start-up of upstream operations.
The Russian Federation produced 200.7 Mtoe of coal in 2011. Coal exports reached almost 83.53 Mtoe.
From 2000 to 2012, the proportion of the total coal production volume that was exported increased from
17.1% to 41.0%, despite the fact that the main coal-producing areas (the Kuznetsky and Kansko–Achinsky
basins) are landlocked in the south of Siberia, some 4 000–6 000 kilometres from the nearest coal shipping
terminal for the Atlantic/Pacific markets. Enormous prospective coal deposits have been found in evenless-developed and more remote areas of eastern Siberia, south Yakutia and the Russian Far East.

Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

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Indigenous production

1 331 435 Industry sector

131 434 Total

1 069 300

Net imports and other–564 986 Transport sector

93 630

Thermal725 383

Total PES756 374 Other sectors

223 492

Hydro

165 898

Coal

134 727 Total FEC

448 556

Nuclear177 535

Oil

168 844

Coal

13 251

GeothermalGas

387 119

Oil

117 187

OthersOther

65 684

Gas

128 064

Electricity and other

190 055–
482

Source: (EDMC, 2014).

The Russian Federation produced 1 069 TWh of electricity in 2012, of which 67.8% was from thermal
power plants, 15.5% from hydropower and 16.6% from nuclear energy. Geothermal and others represent
only 0.05% of the total electricity generation. The economic potential of hydropower is estimated at
852 TWh per year, but only 20.0% of this has been developed. The Russian Federation has enormous
technical potential for renewable energy production, such as hydro and biomass in Siberia, wind along its
Arctic and Pacific shores, and geothermal in Kamchatka and the Kuril Islands. However, the use of thispotential is constrained by the huge distances over which the renewable energy would have to be delivered
to consumers.
FINAL ENERGY CONSUMPTION
In 2012, the total final energy consumption in the Russian Federation was 448.6 Mtoe, a decrease of 2.2%
compared with the previous year. By sector, industry accounted for 29.3%, transport for 20.0% and othersectors for 50.7%. By energy source, coal accounted for 2.9%, petroleum products 26.2%, natural gas 28.6%
and electricity and others, including heat, 42.3%. Because of Russia’s extremely cold climate, the mostimportant energy use is for space heating, about one-quarter of the total final energy consumption.
The traditional energy-intensive industrial structure has been one of the major drivers of economic
development. New measures to improve energy efficiency in existing industries, increase the share of lessenergy-intensive services, and improve the efficiency of the heat supply to the residential and commercial
sectors will have a significant impact on energy policy. Estimates suggest that the Russian Federation has ahuge untapped technical potential for energy savings, ranging from one-third to almost half of its total final
energy consumption.
ENERGY INTENSITY ANALYSIS
The growth of Russian GDP of 3.4% in 2012 resulted in 1.0 percent improvement in the economy’s total
primary energy supply. This could be translated to an economy-wide level of 239.8 tonnes of oil equivalent
per USD million GDP.
For final energy demand, energy intensity level decelerated by 5.4% from 2011 level of 150.390 toe/USD
million GDP to 142.2 tonnes of oil equivalent per USD million GDP in 2012.
On a per sector analysis, the industry registered the largest reduction of 1.0% in energy use per USD million
of GDP from a year ago level of 42.1 tonnes of oil equivalent per USD million GDP to 41.7 tonnes of oil
equivalent per USD million GDP. Such a minimum drop in energy use shows the necessity to apply moreenergy-efficienct production processes and technologies in the Russian industry sector.

Table 3: Energy Intensity, 2012

EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

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2012

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Primary Energy

242.1

239.8

-1.0

Final Energy Demand

150.4

142.2

-5.4

Industry

42.1

41.7

-1.0

Transportation

32.3

29.7

-8.0

Others

76.0

70.9

-6.8

Source: (EDMC, 2014).

The transport sector posted a lower intensity at 29.7 tonnes of oil equivalent per USD million GDP, adecrease of 8.0% from its previous year’s level. It can be explained by the fact that new, more efficient
vehicles were introduced into the Russian market during 2012.
The other sectors’ energy intensity also went down by 6.8% from 2011 level, respectively, which could be
attributed to being concious on energy utilisation as contributed by improvements in energy efficieny andavailability of energy efficient technology, especially in the heat sector.

P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORKThe adoption in August 2003 of the Energy Strategy of Russia for the period up to 2020 (IES, 2010) was amilestone in Russia’s energy sector development. The strategy identifies the economy’s long-term energy
policy and the mechanisms for its realisation. A revised version of the strategy was adopted by thegovernment in November 2009—the Energy Strategy of Russia for the period up to 2030 (Energy Strategy2030) (IES, 2010). The new version of the strategy was updated to take into account new realities andpriorities in the energy sector as affected by the global recession. The strategy is a framework within whichmore detailed industry-oriented medium-term and short-term programs can be developed.
In 2014, the Russian government continues to work on the revised version of the Russian energy strategy
and will continue to do so until 2035. But the strategic objective of Russia’s external energy policy is unlikely
to change. That objective will continue to be the use of Russia’s energy potential in a way that will effectively
maximise its integration into the world’s energy markets, strengthen Russia’s position in those markets andmaximise the benefits of energy resources to the economy.
To achieve this, Russia will implement a number of 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 27.0% of Russia’s total energy exports in 2030 will be delivered to
the Asia–Pacific region (IES, 2010).
Russia’s nuclear energy industry remains a priority of Russia’s development despite the Fukushima nuclear
accident that occurred in Japan in 2011. Nuclear energy will comprise a larger share of the power generation
domestically, while the industry sector as a whole will expand abroad. Russia will remain a key player in thepractical implementation of improved nuclear fuel technology. Particularly and in spite of the existing
programmes for renewable energy development outlined in the Energy Strategy 2030, the economic
potential of renewable energy in Russia is low. Fossil fuels in Russia are so abundant that renewables havedifficulty competing.
The Energy Strategy 2030 calls for a 40.0% reduction in the energy intensity of the economy by 2030 (IES,2010). Lowering Russia’s relatively high energy intensity (about 335 tons of oil equivalent per million USD
PPP in 2009) needs to be one of the main objectives of Russian energy policy. Without significant progressin this area some industries may not be globally competitive, thus impeding 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, and making surethere is a sufficient energy transportation infrastructure. State participation in energy sector development
will consist mainly of supporting innovative developments in the energy sector, as well as providing a stable
institutional environment for the effective functioning of the sector (IES, 2010).
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Under the general framework of the Energy Strategy to 2030, medium- and long-term programmes andindustry-wide schemes are being developed. These include the Federal Program for Development of the
Nuclear Industry to 2015, approved in October 2006, and the general scheme of electric energy objects
placement—a scheme relating to electricity network infrastructure and electricity plant locations—to 2020,
approved by the federal government in February 2008 and currently being amended to extend it to the year2030.
On 12 April 2011, at a meeting of the Governmental Commission on the fuel and energy complex anddevelopment of mineral resources and the energy efficiency of the economy, a general scheme for thedevelopment of the oil industry up to 2020 was approved. This provides for the comprehensive
development of all subsectors of the oil sector—exploration and utilisation of associated petroleum gas,
crude oil and petroleum products, crude oil refining, and transportation infrastructure.
The general scheme for the development of the gas industry up to 2030 was reviewed and approved on 11
October 2010 at the meeting ‘About the Master Plan for Gas Industry Development up to 2030’ underPrime Minister Vladimir Putin. The document represents a complex project, which defines a path for
Russian gas industry development in the long term. This strategic document covers all the components of
the industry: exploration, drilling, production, storage and transport of gas supply to consumers ofhydrocarbons, and refined products.
In 2007, the federal government approved the East Gas Programme to develop natural gas fields and build
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 andowner of the economy-wide gas pipeline system, is the coordinator of the programme and is responsible for
conducting long-term sales contracts for natural gas deliveries.
In November 2011, the Ministry of Energy sent to the Russian Government the second phase development
plan for the economy’s gas and petrochemical industry to 2030. The working group for this plan included
relevant government authorities, industry representatives, research and consulting companies, and input
from the people of the Russian Federation. The second phase includes an updated general plan for thedevelopment of key oil–gas investment projects, an updated programme for the positioning 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 the Russian Federation approved a long-term program fordeveloping the coal industry to 2030. This document specifies the basic provisions of the energy strategy to2030 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 on Energy Saving and Energy Efficiency Improvement
to 2020 (FTP) was approved by the government, which is concerned with energy policy formulation. The
draft ‘General Scheme for the Natural Gas Industry Development to 2030’ will be a major development
stimulus for Russia’s energy sector, considering the soaring importance of the gas industry on theinternational stage and the importance 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
for electricity demand by region, maximum loads, generation capacity reserves, power exchange, retirementof old facilities, maintenance, retrofitting, and commissioning of new generation and transmission facilities
with more than 5 MW capacity/110 KV and higher voltage, respectively.
LAWS AND REGULATIONS
The basic laws on specific energy-related industries are either being implemented or developed. This set of
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);

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

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 latter is the logical extension of the Power Industry law, due to the fact that the major source of heat
supply in the Russian Federation is from cogeneration plants (CHP), where electricity is a by-product ofresidential and industrial heat supply. However, while crude oil extraction and refining is an important
industry in Russia, the draft of the oil law is still being developed in light of its international influence andthe growing domestic economic and social 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 withlong-term energy policy. Other major government institutions actively participate in the development andimplementation 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;Ministry of Industry and Trade;Federal Antimonopoly Service;Federal Customs Service; andFederal Tariff Service.

ENERGY SECURITY
The Russian Federation considers issues related to energy security a global phenomenon. Due to theincreasing 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 tocoordinate the actions of energy producers and consumers in emergency and/or crisis situations. To
facilitate international energy security cooperation, the Russian Federation has made a proposal to developa Convention on International Energy Security that would cover all aspects of global energy cooperation,
taking into account the balance of interests of all actors in the international market.
The infrastructure projects, including new oil and gas export trunk lines from the Russian Federation to
its European and Asian markets, provide a solid contribution to improving global energy security. The
development of an international infrastructure for the reliable maintenance of the nuclear fuel cycle, understrict International Atomic Energy Agency (IAEA) supervision, is another Russian contribution to theimprovement of global energy security.
ENERGY MARKETSMARKET LIBERALISATION
One of the main issues in the Russian Federation is the gradual move from state-regulated energy pricing tofree market institutions for natural gas and electricity pricing. Coal and petroleum prices have already been
fully liberalised. The federal government will keep control over tariff setting for natural monopolies—powertransmission lines and pipelines (gas, crude oil, petroleum products transportation systems, and heat supply
for residential and commercial sectors). The Federal Tariff Service is authorised to set the maximum
allowable regional tariffs for natural gas, electricity and centralised heat supply. One of the objectives of theEnergy Strategy of the Russian Federation to 2030 is to complete the full liberalisation of domestic energy
markets, where at least 20.0% of energy should be traded on commodity exchanges.

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In December 2006, the government approved the liberalisation of natural gas and electricity prices totake place simultaneously in 2011, ensuring the smooth development of the natural gas industry and therestructuring of the power industry. The synchronisation of price liberalisation is important for bothindustries, as 70.0% of the thermal power plants’ fuel mix is provided by natural gas, while more than 40.0%
of total domestic natural gas consumption comes from the power industry. However, due to social issues,
the regulated tariff for residential energy supply will remain even after 2014.
The oil market in the Russian Federation has been deregulated since the 1990s, but crude oil andpetroleum trading is not based on commodity exchanges. Most crude oil in the domestic market is tradedon a term basis, in which prices are linked to international benchmarks. Petroleum is traded in irregulartenders, which allows producers to control the market. Regional petroleum storage plays an important rolein establishing fuel markets. The government intends to make up to 25.0% of the compulsory purchases of
the government’s petroleum products supply by means of 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 been extended. Regulated prices willremain for the residential and commercial sectors for some time, as the pace of tariff increases for suchconsumers should be lower than that for industrial users.
OIL AND GAS
The oil and gas industry was privatised in the 1990s. However, the state still has a controlling stake in the
major oil companies, crude oil and petroleum trunk pipelines, and it owns 50.002% of Gazprom’s shares.
The oil sector is heavily controlled by the Russian Government and this control increased after the stateowned Rosneft takeover of TNK-BP. The USD 55 billion merger in 2013 created the world’s largest listed
oil company with a daily output of 4.6 million barrels in oil-equivalent terms (Reuters, 2013). As of 2012,
the oil industry in the Russian Federation consisted of nine large producing companies with more than
90.0% of the crude oil output, and more than 300 small-scale enterprises, along with operators of three
production-sharing agreements. The refining sector consists of 27 large and more than 83 small refineries.
After the merger of the crude oil and petroleum products pipeline companies Transneft andTransnefteprodukt, the state controlled 75.0% of the combined company’s shares. Private oil pipelines doexist in Russia—the most important is the Caspian Pipeline Consortium for crude oil transit from
Kazakhstan to the Black Sea ports—but other private pipelines operate in the European part of RussianFederation and in Siberia.
The federal government remains the key shareholder in the economy’s gas monopoly, Gazprom, whichis the extractor of 84.0% of the natural gas in the Russian Federation and owner of the economy-wide gas
pipeline system. Independent companies produce the other 16.0% and supply about 25.0% of domestic
consumers.
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 the Russian Federation through theirstake in state and private companies, and produce at least 14.0% of the economy’s crude oil and 7.0% of its
natural gas. Foreign investments accounted for USD 52 billion of cumulative investments in the Russianenergy sector from January 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 million tonnes in 2006. In
July 2009, work began on the construction of BTS-2, which will be able to deliver 50 million tonnes to thenew oil export facilities at 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, i.e. other than Gazprom, from
16.0% in 2010 to about 30.0% in 2030. The Nord Stream pipeline is already under construction and should
help to maintain Russia’s traditional European market, but more gas trunk pipelines are needed to tap into
the Asian market, specifically China. New LNG projects in the European Arctic, like those on the Yamal
Penisula, are considered an important means of delivering natural gas to international markets.
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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
100.0% privatised.
As of 2013, 202 coal enterprises operate in the Russian coal industry (84 mines and 118 open-pit mines),
with a total annual production capacity of around 400 million tonnes of coal. 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 be transported over long distances. Coal is
the single largest commodity transported by Russia’s railway network, accounting for almost 30.0% of its
total freight.
ELECTRICITY
The Russian Federation started restructuring the power industry in 2000. Federal laws and federal
government decrees identified the main principles for the future functioning of the power industry undercompetitive conditions. All thermal generation and regional power distribution companies were privatised
before July 2008. From July 2008, the generation and transmission assets in the Russian Federation havebeen separated under binding regulations. Generation assets are consolidated into interregional companiesof two types: seven wholesale thermal power plant generation companies (WGCs) and 14 territorial
generation companies (TGCs). Six thermal WGCs were constructed according to extraterritorial principles,with one state-owned holding company, RusHydro, which controls over 53 hydropower plants. TGCs
manage facilities in neighbouring regions. The initial design of the WGCs provided them with roughly equal
starting conditions in the market, as far as installed capacity, asset value and average equipment areconcerned. Each WGC has power plants sited in different regions of the Russian Federation 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 isin charge of monitoring the long-distance power transportation market, in which the threshold is less than
20.0% of transmission line capacity per company. The wholesale power market infrastructure includes thefollowing organisations:

Non-profit Partnership Administrator of Trading System;



System Operator–Central Dispatch Administration of the Unified Energy System; andFederal Grid Company of the Unified Energy System.

The Non-Commercial Partnership “Administrator of Trading System of the Wholesale Power Market”(NP ATS) was established in November 2001. The main purposes 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, to the wholesale power market,
ensuring the execution and closing of transactions and the fulfilment of mutual obligations. The System
Operator with 100.0% 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 77.7% state control, owns and operates the transmission lines, provides consistency oftechnological 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 48.0% ofelectricity sales, 47.0% of power sales and 5.0% of services sales.
The free electricity trading market (one-day forward) was launched in November 2003 within theframework of the Federal Wholesale Electricity Market (“FOREM”). In September 2006, the regulated
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.

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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 the Russian Federation. Historically, the heat supply industry was subsidised by local
budgets and thus has room for considerable efficiency improvements. The Law on Heat Supply was
introduced in July 2010 to create investment opportunities, minimise energy losses and subsidies, andprovide business incentives. A transparent market for the heat supply will provide additional incentives todevelop combined heat and power facilities as a primary option for generators. The use of registrationequipment will be compulsory for new buildings. The industry’s restructuring will be a cornerstone forenergy conservation activities and provide enormous business opportunities for both domestic andinternational 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 February 2007, the
new Law on Nuclear Industry was adopted. It provided a legal framework for industry restructuring byseparating 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 those materials are still
under state control.
In April 2007, a single, vertically-integrated, state-owned nuclear energy company was established. The
new corporation, AtomEnergoProm (AEP), includes uranium production, engineering, design, reactor
construction, power generation and research facilities. AEP holds a significant share of the world’s enricheduranium and nuclear fuel supply, has 24 GW of existing Russian nuclear energy plants and manages theconstruction of 14 reactors. There are seven reactors under construction in the Russian Federation, 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 16.0%of the world’s market for new nuclear energy plant construction, and is affiliated with Tenex (40.0% shareof the world’s uranium enrichment services market), TVEL (17.0% share of the world’s nuclear fuel market)
and Atomredmetzoloto (9.0% share of the world’s uranium mining).
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 for andslows the performance of air transportation services. Further modernisation of air and rail transport isplanned in connection with Russia’s programs for hosting the 2014 Winter Olympic Games, the 2018
Football World Cup and the 2020 World Expo.
The total length of Russian roads in 2012 was 982 626 kilometres (km), 79.0% of which were paved.
The member economy had only 30 146 km of high-speed divided highways connecting big cities (GKS,2012). Further development of highways will be necessary if big cities are to be connected.
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 lengthof the pipeline system in the economy was 232 981 km in 2010, 167 868 km of which was gas pipeline, 49
240 km was oil pipeline and 15 873 km was oil products pipeline.
FISCAL REGIME AND INVESTMENT
In 2007, dozens of oil and gas fields were decreed to be ‘strategic’ fields. Strategic status makes thehydrocarbon deposits inaccessible to foreign companies unless they establish joint project operations with
Russian companies. Under the current regulations, 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 the176

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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 forthe 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 tomaintain 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 the
Russian Federation. Under the new rules, the duty on oil exports decreased by 7.4% to USD 411.4 per tonne,
and fees for light and heavy petroleum products were set at 66.0% duty on crude oil. For a number of fields
in Eastern Siberia and the North Caspian, there will be a preferential export duty, which, as of October
2011, is set at USD 204.5 per tonne. A reduced duty on crude oil is achieved by changing the formula for
calculating the duty. According to the norms of the ‘60-66’, from now on duty on crude oil will be at 65.0%
and 60.0% of the difference between market price and a standard price of oil at a rate of USD 182.5 per
tonne.
The size of the duty on exports of gasoline is set at 90.0% of the duty on crude oil. Before May 2011,
the duty on exports of gasoline was 60.0% of the duty on oil, but because of the sharp rise in home prices
and gasoline shortages in some regions, it was increased to 90.0%. It is believed that such new fees will allow
oil companies 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 66.0% will makeexports less competitive for dark petroleum products and more profitable for light petroleum products; itwill 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 cargo tariff
regulations for some export routes.
ENERGY EFFICIENCY
The energy intensity of the Russian economy is considerably higher than that of most developed economies.
With the introduction of effective energy efficiency (EE) measures, it is estimated that the energy savings
from improvements in Russia’s energy intensity could exceed 300 Mtoe, including more than 160 Mtoe fromthe energy extraction, transformation and transportation industries alone.
EE has become a critical factor in the government’s energy policy since 2008, when a presidential decree
set a target to reduce by 2020 the energy intensity of Russia’s GDP by 40.0%, compared with 2005.
Improving EE and energy savings has become one of the priority areas of the Energy Strategy that extends
to 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 newfederal law sets a legal framework and targets for the use of energy resources in the Russian Federation bypromoting the rational use of energy resources and alternative fuel resources for electricity and heatgeneration. The law introduces various measures to improve EE and energy conservation across all sectorsof 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 installationof 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 to replacehighly energy-inefficient machinery and equipment, etc.).

In addition to the new federal law, on 27 December 2010 the federal government adopted the State
Program on Energy Saving and Energy Efficiency Improvement to 2020 (FTP). The Program will be carriedout in two stages: from 2011–15, and from 2016–20. The energy intensity of Russia’s economy is expected
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to decline by at least 7.4% by 2015 and 13.5% by 2020. In addition, the program outlines measures to achieve
the federal target of an ‘at least 40.0%’ decrease in the economy’s energy intensity by 2020, compared to2007, through the rational 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
energy-efficiency and energy-saving programmes; the establishment of information dissemination, publicawareness and the promotion of education initiatives; the introduction of financial measures to promote theefficient 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 programmes on energy efficiency improvements. The implementation of these
programmes 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. The Federal Energy Agency 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 theeffective 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 budget sector (piloting energy performance contracting in schools and public buildings);

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. However, a major impediment for businesses to improve their energy efficiency is the absenceof appropriate financial mechanisms.
The regulatory framework described in the FTP on Energy Saving and Energy Efficiency Improvement
to 2020, adopted in January 2011, estimates that the total investments into energy efficiency up to 2020 will
be approximately RUB 9.3 trillion (USD 320 billion), with 8.0% coming from governments and 92.0% fromprivate investments. The economic effect of such investments up to 2030 is expected to exceed
RUB 26.5 trillion (over USD 880 billion). Governments at different levels will provide more than
USD 10 billion in guarantees on loans for businesses involved in activities to improve energy efficiency ineither the industrial, residential or commercial sectors.
RENEWABLE ENERGY
The technical potential for renewable energy in the Russian Federation is estimated at 4 400 Mtoe per year,
or almost eight times more than Russia’s current total final energy consumption. However, the economic
potential is much smaller (about 240 Mtoe/year, less than 1.0% of the total electricity production). In 2010,
the renewable energy capacity totalled 2 200 MW; of this, less than 25 MW was hydro.
The government’s policy goals and mechanisms to promote renewable energy were introduced in
January 2009 through the federal government’s order, The Basic Directions of a State Policy of Renewable Energy
Utilisation to 2020. Renewable energy is expected to provide 2.5% of the electricity in the Russian Federationin 2015 and 4.5% in 2020. The major mechanisms to increase the share of renewables are feed-in tariffs andsubsidies for grid connection. The government is expected to develop regulations for feed-in tariffs and gridconnection subsidies, for the compulsory share of renewable energy in the wholesale market to be purchasedby electricity consumers, and for bringing together renewable energy generators, transmission lines andguarantor suppliers of energy.
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 renewable energy generators should not exceed 25 MW,
and that owners should not be under bankruptcy proceedings. The ruling paves the way for financial
mechanisms for renewable energy.

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NUCLEARThe Russian Federation holds important stakes in the international nuclear fuel market. All of the Russian,Commonwealth Independent States and Eastern European nuclear reactors are supplied by Tenex—thestate company responsible for the nuclear fuel cycle business. In addition, Tenex meets 40.0% of the UnitedStates’, 23.0% of Western Europe’s, and 16.0% of the Asia–Pacific region’s nuclear fuel requirements.
In the Global Nuclear Infrastructure Initiative, announced by the Russian Federation in early 2006, theRussian Federation proposed to host several 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 importantroles will be uranium enrichment, reprocessing and the storage of used nuclear fuel, along withstandardisation, 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 the Russian Federation 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 thoseeconomies interested in nuclear energy development and ready to comply with the IAEA’s non-proliferation
regulations. The existing enrichment plant in Angarsk will be used to serve the IUEC.
In February 2007, the IUEC was certified by the IAEA for international operations. A programme for
the IUEC’s expansion at Angarsk to 2015 was developed. The programme includes three phases:Use part of the existing capacity in cooperation with Kazatomprom and 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.

The Russian Federation also announced that guaranteed reserves of low-enriched uranium
hexafluoride—the equivalent to two 1 000 MW reactor loads—would be created at the IUEC as a fuel bankavailable under the IAEA’s control. The first phase of the capacity enhancement was scheduled for 2011,
when 1 million separation work units were expected to be commissioned, with a target of 5 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 the Russian Federation a stock of low-enriched uranium, 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 arrives from the IAEA.
One major concern for world energy development is nuclear safety, which has become a key agenda
item after the Fukushima accident in Japan. The Russian Federation 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, thelaws on environmental protection and on 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 2020–2025, fast neutron
reactors will play an increasing role in Russia. The improved design will lead to an extended operating lifeof up to 60 years, a shorter construction period of up to 46 months and operating costs at less than RUB 1
per 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 have been 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.

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CLIMATE CHANGE
In November 2004, the Russian Federation ratified the Kyoto Protocol. That decision confirmed Russia’s
strong commitment to addressing climate change and to working with the international community on
dealing with this global problem. Ratification by the Russian Federation satisfied the ‘55.0%’ clause andbrought the Kyoto Protocol into force, effective from 16 February 2005.
The Russian Federation is considered to be the world’s largest potential host for ‘joint implementation’projects under the Kyoto Protocol. In May 2007, procedures for the approval and verification of Russiabased joint implementation greenhouse gas (GHG) reduction projects were adopted. Responsibilities wereassigned for setting 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, the Russian Federation pledged to reduce its GHG
emissions by 25.0% from 1990 levels by 2020, a figure comparable to the targets of the European Union
member states, and by 50.0% from 1990 levels by 2050. These emission reductions are contingent on these
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 reducegreenhouse gas emissions caused by human activities.
In December 2012, the Russian Federation refused to endorse extended pollution limits under the Kyoto
Protocol at the United Nation’s climate change conference in Doha, since the biggest polluters—US, China
and India—have not joined it.
NOTA BLE EN E RG Y D EV EL O PM E NT S
PROGRAM ON ENERGY SAVING AND ENERGY EFFICIENCY IMPROVEMENT
TO 2020
The main objective of the State Program on Energy Saving and Energy Efficiency Improvement to 2020 isto reduce the energy intensity of the gross domestic product of the Russian Federation by 13.5%. This is
expected to combine with other factors to provide an overall reduction of 40.0% in the energy intensity of
the GDP in the period 2007–2020. Other expected results of the programme are savings of 330 bcm ofnatural gas over the life of the program, energy savings of 630 billion kWh, heat savings of 1 550 million
Gkal and petroleum product savings of 17 million tonnes.
The program also aims for a significant reduction in energy costs and to ensure the competitiveness andfinancial stability of the Russian economy, the provision of high quality energy services at affordable prices
and the lowering of greenhouse gas emissions, thereby strengthening the health of the population. The
funding of the program is split between RUB 70 billion from the federal budget, RUB 625 billion frombudgets of the regions of the Russian Federation and RUB 8.8 trillion from extra budgetary sources.
Gazprom has adopted the FTP on Energy Saving and Energy Efficiency Improvement to 2020, whichshould lead to a 1.2% annual decline in energy consumption by this giant energy company to 2020.
Gazprom’s current energy demand for natural gas extraction, processing and transportation is close to 10.0%of the total economy’s extracted energy. The major share of improvements will come from measures related
to its pipeline operations (estimations are up to 85.0%).
POWER MARKET DEVELOPMENT
The Ministry of Energy presented concepts for a programme of power sector modernisation for the period
up to 2020. The central theme of the modernisation is to introduce new technologies, both domestic andimported, 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 in the amount of 38 billion cubic meters of gas per year.
As part of the APEC summit in Beijing in November 2014, a number of documents related to the RussianChinese cooperation in the energy sector were signed in the presence of 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 schedule180

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of 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 thecoal production to Russia’s eastern regions to supply in Asian markets, which now total 80.0% of the world’s
consumption.
NUCLEAR AND RENEWABLE ENERGY DEVELOPMENT
Russia will join the International Renewable Energy Agency (IRENA). Accession to IRENA will give theRussian Federation 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 a standards,
as well as influence the renewable energy sector’s development worldwide.
ENERGY SECURITY IMPROVEMENTS
The Ministry of Energy approved a joint statement of the Russian Federation and the International Energy
Agency, agreeing on regular bilateral consultations. Those consultations will strengthen their collaborationin an effort to maximise the contribution of the energy sector in reconstruction and economic development,enhance energy security in the world, and reduce the environmental impact of energy production andconsumption.
REF ER EN CE S
BP (2014). Statistical Review of World Energy 2012. www.bp.com/statisticalreview
EDMC (Energy Data and Modelling Center) (2014). APEC Energy Database. Institute of Energy
Economics, Japan. www.ieej.or.jp/egeda/database/database-top.html
Gazprom (2014). Russia and China sign Framework Agreement on gas supplies via western route,
http://www.gazprom.com/press/news/2014/november/article205898/
GKS (Federal State Statistics Service) (2014). Russia in figures 2011,
http://www.gks.ru/wps/wcm/connect/rosstat_main/rosstat/en/main/
NEA (Nuclear Energy Agency) (2010). Uranium 2009: Resources, Production and Demand (Red Book 2009).
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
ME (Ministry of Energy) (2014). Actual problems and directions of Russian fuel & energy complex development.
www.minenergo.gov.ru
Reuters http://www.reuters.com/article/2013/03/21/us-rosneft-tnkbp-deal-idUSBRE92K0IZ20130321
U SEF UL LI N K S
OFFICIAL BODIES OF THE RUSSIAN FEDERATION
Structure of the Government of the Russian Federation— 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/

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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— http://www.russian-customs.org/
Federal Tariff Service—www.fstrf.ru/
ENERGY-RELATED NON-PROFIT AND STATE-OWNED BUSINESSINSTITUTIONSAtomEnergoProm—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 THE RUSSIAN FEDERATION
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 a Southeast Asian economy located south of the Malaysia Peninsula between the Strait of Malacca
and the South China Sea. The economy’s total land area was 715.1 square kilometres in 2012 when its population
was about 5.3 million of whom around 1.5 million were non-residents (SingStat 2014).
Singapore is one of the most highly industrialised and urbanised economies in Southeast Asia with a highly
developed and vibrant free-market economy, notwithstanding its small land area and population and lack of
domestic energy and mineral resources. Added to its strategic geographical position, the contributing factors
include its significant role in international cargo and fuel shipping and thus its shipping ports’ intense activity, its
growing role as a regional petroleum hub and supplier of equipment for the oil and gas industry, its emerging
leadership in the biotechnology industry, and its growing involvement in high tech and solar energy.
In 2012, its gross domestic product (GDP) of USD 388.7 billion and per capita of USD 73 157 (both at2010 price and PPP) registered increases by 2.5% and 0.02%, respectively, from those of 2011. Services
producing industries, goods producing industries and ownership of dwellings accounted for 64.9%, 25.1%, and4.1% of its GDP, respectively. The first sector’s largest sub-sector was manufacturing with a share of 19.2%
while that of the second one was wholesale and retail trade having a share of 17.6% (SingStat, 2014).
The value of Singapore’s exports in 2012 was USD 510.3 billion of which the share of domestic exports(USD 285.2 billion) was 55.9% leaving the rest for re-exports (USD 225.2 billion). The export items’ shares of
the total exports were as follows: machinery and equipment (45.2%), mineral fuels and lubricants (25.7%),
chemicals and chemical products (13.2%), miscellaneous manufactures (7.8%), manufactured goods (3.8%),
miscellaneous (1.5%), beverages and tobacco (0.9%), crude materials (0.6%), and animal and vegetable oils
(0.1%) (SingStat, 2014).
Table 1: Key data and economic profile, 2012
Key data

Energy reserves

Area (sq. km)

714.3

Oil (billion barrels)–

Population (million)

5.31

Gas (billion cubic metres)–

GDP (USD (2010) billion at PPP)

388.72

Coal (million tonnes)–

GDP (USD (2010) per capita at PPP)

73 172

Uranium (kilotonnes U)–

Source: (EDMC, 2014).
E N E RG Y S U P P LY A N D D E M A N D

PRIMARY ENERGY SUPPLY
Singapore relies almost entirely on energy imports to meet its domestic energy needs. Its total primary energy
supply (TPES) in 2012 was 25 184 kilotonnes of oil equivalent (ktoe). Natural gas supply grew by 38.6% between
2011 and 2012 to 9 157 ktoe, which was the largest rate of growth since 2003 when the economy experienced amajor increase of 45.5% in its gas supply to 4 039 ktoe from 2 776 ktoe in the previous year. Oil supply increased
by 9.1% to 15 117 ktoe from 13 862 ktoe in 2011. For the first time, the economy imported a small amount ofcoal (25 ktoe) equal to 0.1% of its TPES in 2012.
In 2012, the economy’s total imports of energy, including petroleum products, was 157 455 ktoe, which
included supplies to meet its energy requirements as well as those to feed its oil refineries whose bulk of theirrefined products are exported (EGEDA, 2014). Of these imports and their produced refined products, 53.5%
were exported amounting to 84 311 ktoe leaving the shares of 26.7% and 4.3% for marine bunkering (41 998
ktoe) and aviation bunkering (6 847 ktoe), respectively (EGEDA, 2014).
Singapore generated 46 915 gigawatt-hours (GWh) of electricity in 2012, a 2.0% increase over its 2011
generation (45 999 GWh) (EDMC, 2014). Its peak demand for electricity was 6 639 megawatts (MW) in that183

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year compared with 6 570 MW in 2011 (EMA, 2014). As evident in its 2012 performance, the economy’s power
generation is mainly based on thermal power plants (43 207 GWh) with a relatively significant contribution of
the waste-to-energy generators (3 708 GWh) accounted for 7.9% of the economy’s generation in 2012; gridconnected photovoltaic installations make a very small contribution to the economy’s power generation. The
thermals power plants experienced slight decrease in their power generation of -4.76 over the previous year while
the waste-to-energy generators registered an impressive growth of 485.8% (EDMC, 2014).
In 2012, the licensed power generation capacity of thermal power plants was 10 119.6 MW. This was amajor increase of 9.5% over the previous year (9 239.4 MW). Of the total mentioned capacity, the share of the
combined cycle gas turbine power plants was 7 081.8 MW and those of others were as follows: steam turbine
plants (2 061.0 MW), open cycle gas turbine plants (180.0 MW) and waste-to-energy plants (256.8 MW) (EMA,2014).
Singapore had residential and non-residential grid-connected solar photovoltaic systems installations in2012 with a total capacity of 9.8 megawatt peak (MwP) consisting of 0.7 MwP of residential and 9.1 MwP of
non-residential capacity (EMA, 2014).
In 2012 natural gas dominated the economy’s fuel mix for power generation at 84.3%, followed bypetroleum products at 13.0% and other fuels, mainly waste, at 2.7% (EMA, 2014).
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Indigenous production

886 Industry sector

Net imports and otherPower generation (GWh)

8 595 Total

46 91573 143 Transport sector

1 773

Thermal

43 207

Total PES

25 184 Other sectors

2 137

Hydro

–

Coal

25 Total FEC

12 505

Nuclear–Geothermal–

Oil

15 117

Coal

0

Gas

9 157

Oil

7 588

Other

886

Gas

1 256

Electricity and other

3 661

Others

3 708

Source: (EDMC, 2014).

FINAL ENERGY CONSUMPTION
The economy’s total final energy consumption (FEC) was 12 505 ktoe in 2012, an increase of 0.5% from 2011.
Oil (7 588 ktoe) accounted for about 60.7% of such consumption leaving the rest for electricity (29.3%; 3 661
ktoe), and natural gas (1 256 ktoe; 10.0%). The energy consumption share by sector was 68.7% (8 595 ktoe) for
industry, 17.1% for other sectors (2 137 ktoe), and 14.2% for transport (1 773 ktoe) (EDMC, 2014).

ENERGY INTENSITY ANALYSIS
Singapore has taken major steps to contribute to APEC’s objective of a 45.0% intensity reduction by 2035 (2005
as base year) as set by the APEC leaders in 2011. Yet, the economy’s efforts to reduce its energy intensity began
prior to the latter as, in 2009, it set for itself an ambitious 35% target reduction by 2035 when APEC’s target
was 25% by 2030 (APEC, 2014). The latter was declared in the Sustainable Singapore Blueprint launched in 2009by Singapore’s Inter-Ministerial Committee on Sustainable Development (IMCSD) as a national strategy for its
sustainable development (MEWR, 2014).
The economy enhanced its efforts to meet APEC’s more ambitious target of 2011 through various
measures. As a recent example, it enacted the Energy Conservation Act 2013 (ECA). The ECA seeks a range
of inter-related energy issues, including improving energy conservation, efficiency and intensity while reducing
CO2 emissions. It aims to help Singapore achieve its intensity reduction target by seeking to improve the energy
performance of the economy’s companies (EMA, 2012).
Singapore reduced energy intensity in major relevant sectors in 2012 (Table 3). Its final energy demand in2012 reflects a significant energy intensity reduction of 2.0% over the preceding year. This achievement is clearly
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evident in its two major sectors accounting for its bulk of economic activities and thus GDP, namely industry
and others, registering energy intensity reductions of 1.1% and 14.7%, respectively, compared to 2011. A
significant increase in its transportation sector’s energy intensity in 2012 (13.6%) was not large enough to affectits overall energy intensity reduction achievement demonstrated in its final energy demand. The large increaseof its primary energy’s energy intensity (19.3%) is mainly due to the economies’ role as a major regional petroleum
hub, as it imports a large amount of crude oil for its refineries and petrochemical industries whose bulk of theirproducts are exported.
Table 3: Energy Intensity Analysis, 2012
EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

54.3

64.8

19.3

Final Energy Demand

32.8

32.2

-2.0

Industry

22.4

22.1

-1.1

Transportation

4.0

4.6

13.6

Others

6.5

5.5

-14.7

Source: (EDMC, 2014).
P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORKIn 2010, the Economic Strategies Committee’s (ESC) Subcommittee on Ensuring Energy Resilience andSustainable Growth released a report recommending the following 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 and renewables to further diversify
its energy mix.

Strategy 2: Enhance Infrastructure and Systems. Singapore continues to improve the liberalisation of
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 has helped
make its energy markets more efficient, open new areas for economic development and strengthen energy
security. Singapore is currently conducting an Intelligent Energy System (IES) pilot that is testing andevaluating smart grid technologies and related applications that will enable consumers to manage theirelectricity 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 cost savings
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 these barriers andpromote more efficient energy use among consumers, the Government administers several 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 thegrowth 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 inter-agency
collaborations on energy research, development, and demonstration (RD&D) such as the Energy National
Innovation Challenge (NIC) and the Energy Innovation Program Office (EIPO), and also through privatepublic partnership initiatives to enhance manpower capabilities for the power utilities sector.

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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 the economy isable to adapt to the rising cost of energy and to a carbon-constrained world.

ENERGY SECURITY
Singapore has taken steps to enhance its energy security within the framework of its geographical realities limiting
its options by excluding all types of renewables excluding solar energy as feasible and/or viable ones. Singapore
has sought to increase the share of gas of its energy requirements and diversify its sources and thus their suppliers
and supply routes as detailed below. It has also undertaken major projects for building underground and floatingstorage facilities for its required hydrocarbons.
Natural gas has now become the major fuel for electricity generation in Singapore. Four offshore natural gas
pipelines supply Singapore’s piped natural gas needs. The first gas pipeline, located in the northern part of themain island, was commissioned in 1991 and supplies the economy with 4.2 million cubic metres per day (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 million cubic metres
per day (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 million cubic metres per day (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 the licensed gas owns and manages the gas pipeline network for conveying natural gas andtown gas. It provides open and non-discriminatory access to the gas pipeline network. SP PowerGrid Ltd
conveys gas and manage the gas pipeline network. SP PowerGrid Ltd is licensed by EMA as the gas transport
agent.
With gas representing a large share of electricity production, the diversification of its supply has become an
important issue. Following a feasibility study, the Singapore Government, in 2006, announced a plan 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, a subsidiary of Singapore Power, was appointed the developer of the
LNG terminal in 2007. However, due to the difficulty of proceeding with the project on a commercial basis, theSingapore Government announced its decision to take over the development and ownership of the Singapore
LNG terminal in June 2009. With this development, the Energy Market Authority (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 and construction of Singapore’s first LNG
terminal.
On 7 May 2013 Singapore completed and commenced commercial operations of a terminal, with an initial
capacity of 3.5 million tonnes per annum (Mtpa), located at an approximately 40-hectare site on the southwestern part of Jurong Island. This capacity increased to 6 Mtpa in January 2014 when the third LNG tank, thefourth Open Rack Vaporiser and two High Pressure Booster Pumps were completed and brought into service.
As well, the Secondary Berth and the Gas Engine Generator achieved Mechanical Completion at that time
(SLNG, 2014).
The terminal’s capacity will further rise to 11 Mtpa when the fourth tank and additional regasification facilities
are constructed. Its development and that of additional regasification facilities is now underway and to becompleted by 2018. The LNG terminal is designed to have the scalability to provide new services such as LNG
trucking, industrial gas manufacturing and LPG import and export in the future (SLNG, 2014a).
Beside the LNG terminal, Singapore initiated a project to build a floating storage facility for oil and petrochemical
products to enhance its energy security. The initiative, known as the Very Large Floating Structure (VLFS),
comprises two rectangular modules, each with 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 with the utilities 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 scheduled for completion in 2014 (EMA, 2011a).
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Finally, Singapore has embarked on a project to build Southeast Asia’s first underground liquid hydrocarbon
storage facility called the ‘Jurong Rock Caverns,’ which is located at a depth of 130 meter under the Banyan
Basin on Jurong Island. 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 was completed in
September 2014 (SGC, 2014a).
ENERGY TECHNOLOGY/R&D
Singapore has actively sought to promote energy research and development (R&D) which is motivated by two
considerations: 1) developing capabilities to support the clean energy sector as a key growth area, and grow a
viable industry that will create jobs; and 2) meeting Singapore’s energy challenges and its sustainable development
objectives. To this end, the National Research Foundation (NRF) has allocated SGD 170 million in 2007 andanother SGD 195 million in 2011 to the Energy Innovation Program Office (EIPO), formerly known as the
Clean Energy Program Office.
The Energy Innovation Research Program (EIRP), co-led by EDB and EMA, is a competitive R&D grant callinitiative under EIPO that aims to strengthen Singapore’s R&D capabilities and address our energy-related
challenges. Since 2012, 10 grant calls have been launched in areas such as solar, green buildings, power
generation, energy storage, smart grids and gas, and over $70 million awarded to various Singapore-based
institutes of higher learning, research institutes, and the industry.
Under EIPO, the government has supported the establishment of Research Centres for Clean Energy. For
example, the Solar Energy Research Institute of Singapore (‘SERIS’) was established in 2008 to conduct industryoriented R&D in solar energy technologies, focusing on materials, components, processes and systems for solar
photovoltaic (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 the most viable renewable energy in Singapore, given the location in the tropical sunbelt. A key
player in this field is the SERIS (Solar Energy Research Institute of Singapore), which conducts world-classindustry-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 market, but that of Asia. Moreover, Singapore also houses a range of
key wind technology players, such as, Keppel and Vestas (EDB, 2014).

ENERGY MARKETSELECTRICITY
Singapore commenced the restructuring of its energy sector in 1995 by corporatising its electricity and gas
industries as vertically integrated companies. Notable milestones since mid-1995 have included corporatisationand industry structural reforms, the creation of an institutional regulatory framework, and market rules for thecontestable parts of electricity generation and retail, separate from the natural monopoly of electricity
transmission at the ownership level. The Singapore Electricity Pool was established in 1998 to facilitate thetrading of electricity between generation and retail companies in a competitive environment.
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Singapore’s government undertook further reforms in 2000. It separated the natural monopoly or noncontestable part of the electricity market (that is, the electricity transmission and distribution grid) from thecompetitive or contestable parts (that is, power generation and retail) of Singapore Power Ltd. The electricity
grid—PowerGrid Ltd (now known as SP Power Assets Ltd) and Power Supply Ltd (now known as SP ServicesLtd)—remained under Singapore Power Ltd; the power generation companies Senoko Power Ltd andPowerSeraya Ltd would compete with one another and with other power generation companies in Singapore.
The government also established an independent power system operator and liberalised the electricity retailmarket.
In April 2001 the government formed EMA to regulate the electricity and gas industries and to promotecompetition in these industries. In 2003, the National Electricity Market of Singapore (NEMS) commenced
operations. In the NEMS, generation companies compete to sell electricity at half-hourly intervals to thewholesale electricity market. The liberalisation of the retail market has been implemented in phases, with plansto open up the market to full retail contestability.
The final phase of retail market liberalisation (full retail contestability) is currently under review (EMA,
2014b). This phase covers the remaining non-contestable consumers, mainly small businesses and household
consumers—about 1.3 million in number—that represent 25.0% of total electricity sales. EMA is continuing tostudy how best to introduce retail competition to leverage smart meter technology.
In June 2007, Temasek Holdings (Temasek) confirmed its plan to divest all three of its wholly-owned Singapore
power generation companies—PowerSeraya Ltd, Senoko Power Ltd and Tuas Power—over the following 12–
18 months. The sale of PowerSeraya Ltd in December 2008 concluded Temasek’s divestment of its three power
generation companies. It marked the completion of the transition to a fully competitive power generation market
in Singapore, a process that began with the restructuring of Temasek’s generating assets into three independent
operating companies in 1995.
GAS
Singapore started restructuring its gas industry after passing the Gas Act (Act 11 of 2001) in 2001. The Gas Act
sets the legal basis for the separation of the contestable part of the gas industry, namely, gas retail and gas imports,from the monopolistic part, i.e. gas transportation. A gas grid company owns the gas transmission anddistribution network, which provide market players with open and non-discriminatory access to the network.
PowerGas Ltd divested its contestable businesses of gas import, production and retail in January 2002. The
manufactured gas production and gas retail business undertaken by City Gas Ltd and the natural gas importbusiness undertaken by Gas Supply Ltd were transferred to Temasek Holdings. With this divestment, PowerGas
Ltd became a gas transporter. Under the new gas industry framework, the transportation of natural gas would
be regulated.
The economy’s newly restructured gas market became operational with the Gas Network Code (GNC) coming
into effect from 15 September 2008. The GNC was developed and enacted by the EMA in consultation withindustry players. The GNC’s rules govern the activities of gas transportation, providing open and nondiscriminatory access to Singapore’s onshore gas pipeline network. The GNC outlines the common terms andconditions between the gas transporter (PowerGas Ltd) and those industry players who engage the transporterto transport gas through the pipeline network. To ensure the gas transporter is not in commercial conflict with
common interests, PowerGas Ltd is banned from participating in those parts of the electricity and gas businesses
open to competition, such as gas import, trading and retailing businesses. No other gas industry participant willbe allowed to transport gas (EMA, 2008).
On 15 September 2008, Sembcorp Gas, 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 exit of Sembcorp Gas from the gas transportation
business affirms PowerGas Ltd as the gas transporter monopoly.
The restructuring of the gas market is largely to support the liberalisation of the electricity industry byproviding a competitive source of natural gas for electricity generation. The 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 introduction of LNG to Singapore’s gas market in May 2013 when the economy’s LNG terminal
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became operational has since made a major contribution to the diversification of its gas market and increasing
its security (EMA, 2014c).
TRANSPORT
Singapore promotes the use of public transport in the interests of fuel efficiency and conservation. Towards thisend, it has innovative policies to discourage car ownership and usage, such as a vehicle quota system andelectronic road pricing. Since 2001, the Singaporean government has offered a green vehicle rebate to encourage
the take-up of green vehicles such as hybrid, compressed natural gas and electric cars. In January 2006, the rebate
was increased from 20.0% of the open market value to 40.0% of the open market value, to offset the additional
registration fee.
An inter-agency Electric Vehicle Taskforce (EVTF), co-led by EMA and LTA, launched the EV Test-bed
from June 2011 to December 2013 to determine feasibility of EVs in Singapore. Findings from the test-bed haveshown that EVs are technically feasible in Singapore, but are still limited by issues such as high EV costs.
In December 2014 the EDB and 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

ENERGY CONSERVATIONOn 9 April 2012, the Parliament passed the Energy Conservation Act 2012 (ECA) to be jointly administered by
the Ministry of the Environment and Water Resources and the Ministry of Transport (GBS, 2014).
The ECA, which came into force in 2013, requires large users of energy to implement energy management
initiatives. Companies which consume more than 15 GWh or 1.29 ktoe of energy annually will be required toappoint an energy manager to monitor and report their energy use and greenhouse gas emissions, and to submit
plans for energy efficiency improvement to the relevant agencies.
The Act will also consolidate 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.

ENERGY EFFICIENCY
Singapore promotes energy efficiency for a variety of reasons, including curbing unnecessary consumption offossil energy for environmental, financial and health considerations, as well as improving competitiveness of its
industries. Thus, Singapore's key strategies in mitigating greenhouse gas emissions, for example, are to switch toless carbon-intensive fuels and to improve its energy efficiency. The economy adopted measures to improve its
energy efficiency and to reduce the energy use of various sectors of its economy. The government establishedthe Energy Efficiency Program Office (E2PO), a multi-agency committee led by the National Environment
Agency (NEA) and the Energy Market Authority (EMA), to implement energy efficiency. Together, the EMA,
the E2PO, and the NEA actively promoting energy efficiency in the industry, households and public sectors
through legislation, incentives and providing information (NEA, 2014).
The E2PO promotes and facilitates the adoption of energy efficiency in Singapore under the following five
strategic goals (E2PO, 2014):

Promote energy efficiency through regulation and standards, incentives and open information.



Develop human and institutional capabilities by developing local knowledge base and expertise in energy
management and collaborating with Institutes of Higher Learning (IHLs).



Promote emerging energy efficient technologies and innovation through supporting the researchdevelopment and demonstration of new energy efficient technologies, innovations 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 Summit(EAS).


Benchmark Singapore's energy efficiency initiatives against other countries and international framework.
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The energy efficiency efforts are targeted at various sectors, such as power generation, industry, transport,
buildings and households.

POWER GENERATION
The implementation of a competitive electricity market has enabled greater efficiency to be achieved in the power
generation sector. Singapore’s overall power generation efficiency improved from 39.0% to 44.0% over the
2001–12 period. This efficiency improvement was driven mainly by a move in the power generation mix fromoil-based thermal plants to combined cycle gas turbines. The E2PO expects further improvements in Singapore’s
generating efficiency in the future, and it is promoting cogeneration and tri-generation in the economy.
INDUSTRY
Energy efficiency measures for industry include:

The Energy Efficiency Improvement Assistance Scheme (EASe): EASe encourages and helps
companies identify potential energy efficiency improvement opportunities. Under the EASe, up to 50.0%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 Economic Development Board administers the Investment Allowance Tax
Scheme, which is a capital allowance 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 80.0% 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 programprovides 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 80.0% 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 ISO50001 at the organisational level and provides aplatform 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 berecognised through the EENP Award.

TRANSPORT
Singapore’s land transport strategies are characterised by integrating transport and land-use planning, promoting
the greater use of public transport and applying intelligent transport systems to manage road use. In addition,
the Singaporean government has pioneered innovative policies such as a vehicle quota system and electronicroad pricing to reduce congestion, a green vehicle rebate to encourage more fuel-efficient vehicles, and trials ofgreen technologies such as diesel hybrid buses and electric vehicles.


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Carbon Emissions-Based Vehicle Scheme (CEVS): The CEVS was introduced in January 2013 toimprove the take-up of green vehicles, with cars enjoying rebates for having low carbon emissions, while
those with high carbon emissions have to pay a surcharge. Replacing the green vehicle rebate (GVR), theresults of CEVS has been encouraging with more than 50.0% of the new cars registered in 2013 received
CEVS rebates while about 10.0% paid the surcharge. The CEVS will be extended till July 2015 to observe
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Fuel Economy Labelling Scheme (FELS): From 2009, passenger cars and light goods vehicles that are
sold in Singapore must be affixed with the 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 Mark for
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 and construction of new
RTS lines. The framework has three key pillars—i.e. the effective use of energy, water conservation, andenvironmental protection and sustainable development—and covers various aspects of an RTS line (rollingstock, 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 bringing down 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, program are progressively being rolled out to designand 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 are allowed 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 their journeyhassle-free by bus, MRT or LRT. The purpose of this scheme is to allow motorists to switch to the moreenergy efficient public transport for part of their journeys in a convenient way.

BUILDINGS
Sustainable development remains a key priority for Singapore. Energy efficiency is one of the main
considerations for achieving a sustainably-built environment. To realise this vision, the Building andConstruction Authority (BCA) and the National Environmental Agency (NEA) set out to accelerate the adoptionof environmentally-friendly green building technologies and building design practices, and to encourage energy
efficiency in buildings. Energy efficiency initiatives include:

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 aprogram and grant, is available to professionals who wish to build their careers as energy managers in thebuilding 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. In April 2008, the Building
Control (Environmental Sustainability) Regulations 2008 took effect, requiring new buildings and existingones undergoing major retrofitting with a gross floor area greater than 2 000 square metres to achieve theminimum 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.

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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 (GMIS-NB) for aperiod of three years. The scheme offered cash incentives to developers, building owners, project architects
and engineers who made efforts 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
set-aside for the Green Mark Incentive Scheme for Existing Buildings (GMIS-EB) on 29 April 2009 for aperiod of five years. The GMIS-EB provides a ‘cash incentive for an upgrading and retrofitting’ schemethat co-funds up to 35.0% (capped at SGD 1.5 million) of the costs of energy-efficient equipment installed
to improve the 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
co-funds 50.0% of the cost for conducting this health check; the remaining 50.0% 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 it 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 projectto achieve an optimal design for green buildings. The developments must aim to exceed the Green Mark
Platinum standards, demonstrating energy savings of at least 40.0% better than the current base code orequivalent.



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 from 1 October 2011 for a period of two years.

Higher Green Mark Standards for Land Sales Conditions at Strategic Growth Areas: To achieve
higher Green Mark standards (i.e. Green Mark Platinum or Green Mark Gold Plus) for projects developedon government sales sites, the higher Green Mark standards will be set as part of the land sales conditions
for all new developments in selected new strategic growth areas. This will ensure these land sales projects
are truly green, high quality and distinctive. The aim is to accelerate the adoption of environmentally friendly
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 withan air-conditioned area of greater than 5 000 square metres must attain the Green Mark Platinum rating,while existing public sector buildings with an air-conditioned area of greater than 10 000 square metresmust attain the Green Mark GoldPlus rating by 2020.

HOUSEHOLDSHouseholds account for about a sixth of the electricity consumed in Singapore. Households are encouraged topurchase energy-efficient appliances and adopt energy-efficient habits. Programs for households include:

10.0% Energy Challenge: To increase public awareness of ways to be more energy efficient, the 10.0%
Energy Challenge was launched in April 2008. Households are taught simple energy saving habits to reduce
their energy use by 10.0% 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 twomost energy 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 that are sold in Singapore must be affixed withan Energy Label.

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In addition, MEPS were introduced in September 2011 for household air-conditioners and refrigerators.
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 moreenergy-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 is pursuing growth opportunities in clean and renewable energy, mainly solar, while continuing its useof waste for power generation, as part of its strategy to meet its energy policy objectives. Several renewableenergy initiatives are underway to deal with the economy’s energy challenges.
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 generate 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 3 508 ktoe of electricity in 2014
(EDMC, 2014).
In terms of solar power, Singapore has embarked on R&D and test-bedding initiatives to help companies
and researchers advance the development of solar technologies. Singapore’s test- bedding efforts seek to improvethe understanding of the best practices for optimising the performance of solar PV systems in tropical, urbanised
environments.
The Housing Development Board (HDB) has test-bedded solar PV systems at two existing public housing
precincts in Serangoon and Wellington, generating 220kWh of electricity per day for each precinct in the process.
As of the second quarter of 2014, there were 468 grid-connected PV installations with the total capacity of 19
MwP of which the share of residential and non-residential ones were 164 (1.6 MwP) and 304 (17.4 MwP),
respectively (EMA, 2014). 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.
The Economic Development Board (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
as an alternative to rooftop-based installations.
The ‘Handbook for Photovoltaic (PV) Systems’ has been published by EMA and BCA to facilitate theimplementation of solar PV systems in Singapore. The handbook provides information on licensing, market andtechnical requirements, and building and structural issues relating to solar installations.
In November 2010, the Finnish oil refining and marketing company Neste Oil opened its 800 000 tonnes
per year renewable diesel refinery in Singapore, currently the world’s largest of its kind 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
50.0% compared to fossil-based diesel (Neste Oil 2012).

SUSTAINABLE DEVELOPMENT
On 27 April 2009 Singapore’s Inter-Ministerial Committee on Sustainable Development (IMCSD) unveiled its
Sustainable Development (SD) Blueprint by the. The SD Blueprint contains strategies and initiatives forachieving both economic growth and a good living environment for Singapore over the next 20 years.
It details new targets and initiatives to improve resource efficiency and to enhance Singapore’s urban
environment. Being more efficient in the use of resources such as energy, water and land will contribute toenhance 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 to live, even as Singapore
continues to grow and develop. Targets have been set to measure the progress in these areas. The blueprint has
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a 20-year timeframe, with identified key goals for 2030. The blueprint’s goal for the energy sector is to reduceenergy intensity (consumption per dollar of GDP) by 35.0% from the 2005 levels by 2030, with an intermediategoal of 20.0% from the 2005 levels by 2020.
As part of its sustainable development objective, Singapore has taken steps to increase the share of solar of
its electricity generation as the only viable type of renewable for the specific situation of Singapore by facilitating
its growth. Among others, EMA has taken measures towards this end, including setting a policy of proactively
enhancing the required market and regulatory framework to facilitate the deployment of solar units (EMA,
2014a).

NUCLEAR
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 highly urbanised city-state with no rural hinterland, accounting for less than 0.2% of the
global emissions. It has taken serious measures to decrease its carbon footprint, and has made major progress in
reducing its CO2 emissions although for geographical reasons, its options for renewables are mainly limited tosolar energy, apart from waste. Thus, the economy has limited access to emission-free or low-emission energy
sources as hydro, wind, tidal and geothermal energy are not an option given its lack of hydro resources, its low
wind speeds and mean tidal range and economic non-viability of geothermal (EMA, 2014a). Nuclear energy is
not an option either, as discussed earlier. As a result, it is an alternative-energy disadvantaged economy, and its
options for non-fossil and renewable energy are mainly limited to solar. However, as a responsible global citizen,
Singapore continues to play its part in addressing climate change by reducing emissions. Hence, in 2009,
Singapore pledged in the context of the United Nations Framework Convention on Climate Change negotiations
to reduce emissions by 16.0% 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 and international 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 7.0%-11.0% reduction in emissions from BAU levels. Whileseeking to increase the share of solar of its power generation energy mix currently very small (19 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 respective energy mix. Singapore has switched from fuel oil to natural
gas as the main energy source for such generation as its produces the least carbon emissions per unit of electricity
generated amongst fossil fuel-fired power plants. By increasing the share of natural gas used in electricity
generation from only 19.0% in 2000 to about 80.0% in 2014, Singapore has substantially reduced its emissions
growth over the last ten years (NEA, 2014). Singapore’s efforts have resulted in improving its average Operating
Margin Grid Emission Factor from 0.49 kg CO2/kWh in 2012 to 0.45 kg CO2/kWh in 2013.
N OTA B L E E N E RG Y D E V E L O P M E N T S

ENERGY STORAGE PROGRAM
In Oct 2014, EMA announced a SGD 25 million Energy Storage Program to support the development andintegration of large scale, cost-effective Energy Storage Systems (ESS) for Singapore's power system. In
Singapore, ESS could be used to reduce demand during peak periods; as reserves for frequency regulation; andto support the deployment of intermittent generation sources like solar energy.

SEMBCORP-EMA ENERGY TECHNOLOGY PARTNERSHIPEMA has partnered Sembcorp in a SGD 10 million initiative to encourage the translation and commercialisationof energy research into technologies and solutions to address Singapore’s energy needs. Through thispartnership, researchers and companies have the opportunity to develop new technologies that could potentially
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be test-bedded at Sembcorp's facilities, and leverage on Sembcorp's strong business networks forcommercialisation. A joint R&D grant call is scheduled for launch by mid-2015.

PULAU UBIN MICRO-GRID TEST-BED
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 and launched by
Minister S. Iswaran on 10 Oct 2013 to supply electricity to end-users at the Pulau Ubin jetty area. Under Phase2, the micro-grid will offer companies and research organisations a platform to develop and pilot innovative,
close-to-market energy technologies for Singapore (in areas such as energy analytics, energy storage and gridasset 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 used in
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(2014a).

NEW GENERATION CAPACITY
Singapore’s major electricity-generating companies are Senoko Energy, YTL Power Seraya, Tuas Power
Generation, SembCorp Cogen, Keppel Merliamu Cogen and PacificLight Power (SGC, 2014). PacificLightPower started operations in June 2014 and is Singapore’s first fully LNG operated power plant. This state-ofthe-art 800MW plant was built at a cost of $1.2 billion.
Keppel has entered into an agreement with Singapore’s National Environment Agency (NEA) to provide
additional incineration capacity to the Senoko Waste-to-Energy (WTE) plant. Thus, the plant will undergo
upgrading, currently planned to take place between the third quarter of 2015 and the third quarter 2016, toincrease by up to 10.0% 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 the Tembusu
sector of Jurong Island in 2013. Being in operation since 2007, its total generation capacity has now increased to
1 300 MW. It supports the needs of its surrounding industries with electricity, steam supply and demineralised
water requirements (Keppel, 2014).
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 longterm 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 while that of the first phase is of 400 MW with a 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 Public Utilities Board (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 second and largest seawater reverse osmosis desalination plant (Hyflux, 2012).
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Keppel Seghers won the 25-year construct and operate contract for Singapore’s fifth incinerator, whichbegan commercial operations in October 2009. The plant can generate up to 22 MW of power for Singapore’s
grid. It is the first incineration plant to be built and operated by the private sector. It is also smaller than its
predecessors, with a capacity of 800 tonnes per day of solid waste. Previously all of Singapore’s incinerators havebeen constructed and operated by the National Environmental Agency (NEA). The plant was built under the
NEA’s Public Private Partnership (PPP) initiative through a DBOO contract. With the operation of thisincinerator, Singapore’s waste incineration capacity is 3.28 million tonnes a year (Keppel Seghers, 2010).
In addition, EMA is exploring the import of 600 MW of electricity from other economies (EMA, 2012b).
With this, Singapore would be able to further diversify its energy mix by tapping into new energy options thatwould have been unavailable or economically unfeasible in Singapore, thereby reducing the demand for valuable
land to build power plants.
REFERENCES

Asia Pacific Economic Cooperation (APEC) (2014). Energy. http://www.apec.org/About-Us/AboutAPEC/Fact-Sheets/Energy.aspx.
Energy Efficiency Programme Office (E2PO) (2014). Energy Efficient Singapore: An E2PO Initiative.
http://www.e2singapore.gov.sg/
Economic Development Board (EDB) (2014). Alternative Energy.
http://www.edb.gov.sg/content/edb/en/industries/industries/alternative-energy.html.
EDB (2014a). Singapore, Official Opening of New S$2 Billion Tembusu Multi-Utilities Complex. 27 February
2013. http://www.edb.gov.sg/content/edb/en/news-and-events/news/2013-news/official-opening-ofnew-2billion-tembusu-multi-utilities-complex.html.
EDMC (Energy Data and Modelling Centre) (2014). APEC Energy Statistics 2012, Energy Working Group
November 2014. Institute of Energy Economics, Japan (IEEJ), Tokyo, Japan.
http://www.ieej.or.jp/egeda/database/php/newbalance2/balance.php.
EMA (Energy Market Authority) (2008). Gas Network Code.
https://www.ema.gov.sg/Gas_Network_Code.aspx——(2012a). A New Act Comes into Play.
http://www.ema.gov.sg/cmsmedia/Newsletter/2012/07/insighton-newact.html/.
——(2012b). Annual Report 2011 – 2012. http://www.ema.gov.sg/Publications_Annual_Reports.aspx.
——(2014). Singapore Energy Statistics 2014.
http://www.ema.gov.sg/cmsmedia/Publications_and_Statistics/Publications/EMA_SES%202014.pdf——(2014a). Renewable Energy: Overview. http://www.ema.gov.sg/Renewable_Energy.aspx—— (2014b). Liberalisation of Retail Electricity Market.
https://www.ema.gov.sg/Electricity_Market_Liberalisation.aspx.
——(2014c). Gas Policies and Regulations. http://www.ema.gov.sg/Gas_Policies_and_Regulations.aspx/.
——(2014d). Electricity Grid Emissions Factors and Upstream Fugitive Methane Emission Factor - See more
at: http://www.ema.gov.sg/statistic.aspx?sta_sid=20140729MPY03nTHx2a1#sthash.egwPqhgp.dpuf/.
——(2014e). Electric Vehicle Test-Bed. https://www.ema.gov.sg/Electric_Vehicles_Test_Bed.aspx
ESC (Economic Strategies Committee) (2010). Economic Strategies Committee Key
Recommandations. www.ecdl.org/media/Singapore%20Economic%20Committe_2010.pdf
GBS (Green Business Singapore) (2014). Singapore’s Energy Conservation Act – What it Means for
Companies. http://www.greenbusiness.sg/2014/03/27/singapores-energy-conservation-act-what-itmeans-for-companies/
Jurong Township Council (JTC) 2014. News Release: Prime Minister Lee Opens Jurong Rock Caverns.
http://www.jtc.gov.sg/Pages/20140902-(PR).aspx
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Keppel Seghers (2010). www.keppelseghers.com/en/.
Keppel Energy (2011). www.keppelenergy.com/.
—— (2014). Keppel Merlimau Cogen. http://www.kepinfra.com/en/content.aspx?sid=4259
Keppel Infrastructure Trust (KIT) (2014a). Upgrading Of Senoko Waste-To-Energy Plant, 26 September 2014.
http://www.kepinfratrust.com/news_item.aspx?sid=4716
Hyflux (2012). www.hyflux.com/.
MEWR (Ministry of the Environment and Water Resources) (2014). Inter-Ministerial Committee on
Sustainable Development. http://app.mewr.gov.sg/web/Contents/contents.aspx?ContId=1592
MTI (Ministry of Trade and Industry). Inter-Ministerial Committee on Sustainable Development)(2012). News Room: Second Minister S Iswaran's reply to Parliament Question on Nuclear Energy Prefeasibility Study in Singapore. 15 October 2012. http://www.mti.gov.sg/NewsRoom/Pages/SecondMinister-S-Iswaran's-reply-to-Parliament-Questions-on-nuclear-energy-pre-feasibility-study-inSingapore.aspx/.
—— (2007). Energy for Growth: National Energy Policy Report.
www.mti.gov.sg/ResearchRoom/Pages/National%20Energy%20Policy%20Report.aspx/.
NEA (National Environment Agency) (2013). Insights of NEA.
http://www.nea.gov.sg/data/htm/sr12/toether-we-stand/sustainability-in-our-policies-n-publicinitiatives.html—— (2014). Climate Change. http://www.nea.gov.sg/energy-waste/climate-change.
Neste Oil (2012). Neste Oil celebrates the grand opening of its ISCC-certified renewable diesel plant in
Singapore. http://www.nesteoil.com/default.asp?path=1,41,540,1259,1260,16746,17030.
Sembcorp. (2014). Energy: Power Generation. http://www.sembcorp.com/en/business-utilities-energy.aspx/.
Senoko Energy (2012). www.senokoenergy.com/.
SingStat (Singapore Department of Statistics) (2014). Yearbook of Statistics Singapore 2014.
http://www.singstat.gov.sg/publications/publications-and-papers/reference/yearbook-of-statistics-singapore
SGC (Singaporean-German Chamber of Commerce) (2014a). Singapore Infrastructure Projects.
http://www.sgc.org.sg/fileadmin/ahk_singapur/DEinternational/IR/diffIR/Infrastructure_Projects_Sin
gapore_2014_May.pdf——(2014b). Singapore Electricity Market.
http://www.sgc.org.sg/fileadmin/ahk_singapur/DEinternational/IR/diffIR/Electricity_market_in_Singa
pore_2014.pdf
SLNG (Singapore LNG Corporation) (2014). Terminal Development. http://www.slng.com.sg/ourdevelopments-current.html——(2014a). Future Development. http://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— http://www.mof.gov.sg/Resources/EconomicStrategies-Committee-ESC-Recommendations
Land Transport Authority—www.lta.gov.sg
Ministry of the Environment and Water Resources—www.mewr.gov.sg
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Ministry of National Development— http://app.mnd.gov.sg/
Singapore LNG Corporation—www.slngcorp.com
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, mainly comprised of Taiwan, Penghu, Kinmen and Matsu, is a chain of islands stretchingfrom the bottom of Japan in the north to the top of the Philippines in the south. With an area of around36.2 thousand square kilometres, and located just 160 kilometres off the south-eastern coast of China,
Chinese Taipei represents a natural gateway to East Asia. Although only one-quarter of the land is arable,
the subtropical climate permits the multi-cropping of rice and the growing of fruit and vegetables all year
round.
In 2012, Chinese Taipei’s gross domestic product (GDP) was USD 784.7 billion, and its per capita
income was USD 33 656 (USD 2010 at PPP). GDP increased at an average growth rate of 3.7% from 200012. Chinese Taipei’s rapid economic development over the past decade has substantially changed theeconomic structure of the economy, shifting the emphasis from industrial production to the services sector.
In 2012, the services sector contributed 61.6% of GDP, followed by the industrial sector (37.0%) and theagriculture sector (1.3%) (BOE, 2013). Chinese Taipei is one of the most densely populated areas in theworld, but its rate of population growth has been relatively sedate. The economy’s population of 23.3 million
grew at a rate of 0.4% in 2012 compared with 2011. This was higher than the average annual population
growth rate of 0.4% between 2000-12 (EDMC, 2014).
Chinese Taipei has very limited domestic energy resources and relies on imports for most of its energy
requirements. There are no coal reserves in Chinese Taipei, but the economy has oil and gas reserves ofaround 2.4 million barrels and 6.23 billion cubic metres respectively (EIA, 2014). In 2012, installed electricity
generation capacity totalled 41.67 gigawatts (GW) (EIA, 2014).
Table 1: Key data and economic profile, 2012
Energy reservesb

Key data
Area (sq. km)a

36192.8

Oil (million barrels)2.
6.2

Population (million)

23.3

Gas (billion cubic metres)

GDP (USD (2010) billion at PPP)

784.7

Coal (million tonnes)–

GDP (USD (2010) per capita at PPP)

33 656

Uranium (kilotonnes U)–

Source: (EDMC, 2014); a. (DGB, 2013); b. (EIA, 2014).

ENERGY SUPPLY AND DE MAND

PRIMARY ENERGY SUPPLY
Traditionally, a lack of domestic energy and mineral resources has forced Chinese Taipei to import nearly
all of its energy requirements, with imports accounting for 97.8% of its primary energy supply in 2012 (BOE,
2012a). The dependent nature of its energy supply systems has resulted in fragile energy security for the
economy. Improving self-reliance with respect to energy supply is thus an important goal for energy security.
In addition, Chinese Taipei’s energy supply structure is highly dependent on fossil fuels such as coal, oil andnatural gas. Its primary energy supply grew at an average rate of 4.1% between 1992 and 2012.
This growth has mainly been concentrated in fossil fuels such as coal, oil and gas, which have increased
from 86.5% of the primary energy supply in 1985 to more than 89.8% in 2012 (BOE, 2012b). In 2012,
Chinese Taipei’s total primary energy supply was 10 7457 kilotonnes of oil equivalent (ktoe), a decline of
0.2% from the previous year. By fuel, oil contributed the largest share (38.8%), followed by coal (33.5%),
natural gas (15.3%) and other fuels (12.4%) (EDMC, 2014).
In 2012, Chinese Taipei imported almost its entire crude oil requirements. The Middle East represents
its major supplier, accounting for 80.8% of the total oil imports of a million tonnes of crude oil in 2012. To
prevent supply disruption, the Petroleum Administration Act 2001 requires Chinese Taipei’s refiners tomaintain stocks of more than 60 days of sales volumes. Chinese Taipei also imported almost its entire coalrequirement. Australia and Indonesia are its major suppliers, accounting for 81.6% of the total coal imports
in 2012. In 2012, Chinese Taipei imported 64.6 million tonnes of coal. Most coal (72.8%) was used for
power generation (BOE, 2012a; BOE, 2012b).

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Since Chinese Taipei’s natural gas resources are also very limited, its demand is met almost entirely byimports of liquefied natural gas (LNG). Indonesia, Qatar and Malaysia are its major suppliers, accounting
for 83.9% of the total natural gas imports in 2012. LNG imports in 2012 amounted to 12.5 million tonnes,
a 4.2% increase from 2011 (BOE, 2014).
Table 2: Energy supply and consumption, 2012
Primary Energy Supply (ktoe)

Final Energy Consumption (ktoe)

Power Generation (GWh)

Indigenous Production

13 610Industry sector

22 262Total

Net Imports and Other

96 365

Transport sector

11 789Thermal

194 686

Total PES

107 457

Other sectors

31 972

Hydro

8 609

Coal

35 993

Total FEC

66 022

Nuclear40 462

Oil

41 740

Coal

6 921

Other

6 633

Gas

16 397

Oil

37 201Others13 327Gas

2 661

Electricity and other19 240250 390

Sources: (EDMC, 2014).

In 2012, electricity generation in Chinese Taipei reached 250 390 gigawatt-hours (GWh). Of the total
electricity production, Taiwan Power Company’s (TPC) hydro power comprised 3.37%, thermal power
49.2% (coal shared 27.0%, oil 2.3%, LNG 20.0%), nuclear power 16.1%, wind power 0.3%, cogeneration
14.9%, and independent power producers (IPP) 16.1%. In terms of the generating capacity, TPC dominates
Chinese Taipei’s electric power sector with 66.6% and IPPs account for 17.0% of the total capacity. IPPs
are required to sign power purchase agreements with TPC, which distributes power to consumers. To
expand foreign participation, in January 2002 the government permitted foreign investors to own up to
100.0% of an IPP. Currently, two 1 350 MW Advanced Boiling Water Reactor (ABWR) units in the fourth
nuclear energy project are under construction to boost electricity generation (EDMC, 2012; BOE, 2012b).

FINAL ENERGY CONSUMPTION
Final energy consumption in Chinese Taipei was 66 023 ktoe in 2012, 0.3% higher than in 2011. The industry
sector consumed 33.7% of the total energy used, followed by the transport sector (17.9%). The other sectors,
including residential and services consumed 48.4% of the total energy used. By energy source, petroleum
products accounted for 56.4% of total final energy consumption, followed by electricity (29.1%), coal(10.5%) and gas (4.0%).
In 2012, energy used in the industry and transport sectors decreased by 1.4% and 2.0% due to the global
economic recession, while energy consumption in other sectors increased by 2.4% (EDMC, 2012).

ENERGY INTENSITY ANALYSIS
Table 3: Energy Intensity Analysis
Change (%)

Energy Intensity (toe/million USD)
Energy2011

2012

2011 vs 2012

Primary Energy

139.18136.94-1.6

Final Energy Demand

85.13

84.14

-1.2

Industry

29.18

28.37

-2.8

Transportation

15.55

15.02

-3.4

Others

40.40

40.74

0.9

Source: (EDMC, 2014).

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P OL I C Y OV E RV I E W

ENERGY POLICY FRAMEWORKThe Bureau of Energy is responsible for formulating and implementing Chinese Taipei’s energy policy. It isalso charged with enforcing the Energy Management Law 1981 and the electricity laws; regulating natural
gas utilities and petroleum and liquefied petroleum gas (LPG) filling stations; regulating the importation,
exportation, production and sale of petroleum products; maintaining an energy database; evaluating energy
demand and supply; promoting energy conservation; implementing research and development programs;
and promoting international energy cooperation.
The Bureau of Energy released the Framework of Taiwan’s Sustainable Energy Policy in June 2008 (BOE2008). The framework includes:
Policy objectives—to create a win-win-win solution in energy, the environment and the economy, andto 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—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 each task
to measure its performance and to facilitate implementation;



Targets for energy conservation—reduce energy intensity 20.0% by 2015 (based on 2005), with afurther reduction of 50.0% by 2025 through technology breakthroughs and proper administrative
measures;

CO2 emissions could drop back to the 2008 level between 2016-20, and be further reduced to the 2000
level in 2025; andA secure energy supply system to meet economic development goals.

Chinese Taipei established the year 2010 as the ‘Year for Energy Conservation and Carbon Reduction.’
In order to push forward the Framework of Taiwan’s Sustainable Energy Policy, Chinese Taipei has set up
a Committee of Energy Conservation and Carbon Reduction in the Executive Yuan (the executive branchof government) as the highest authority for and monitor of the State Energy Conservation and Carbon
Reduction Projects. The committee is chaired by the Vice Premier of the Executive Yuan with members
from each ministry. The State Energy Conservation and Carbon Reduction Projects cover 10 major fields
and 35 landmark projects to emphasise and implement key energy policies.
In response to the nuclear disaster in Fukushima, Japan in 2011, on 3 November 2011 Chinese Taipei
released a New Energy Policy to ‘Ensure Nuclear Security, Steadily Reduce Nuclear Dependence, Create a
Low-carbon Green Energy Environment & Gradually Move Towards a Nuclear-free Homeland’. The major
strategies concerning nuclear power are (BOE, 2011):
Conduct a comprehensive safety examination of nuclear power plants to ensure nuclear safety;

Steadily reduce nuclear energy dependence by actively reducing electricity demand and peak loads, andpromote alternative energy sources to ensure a stable power supply;No extension to the life spans of existing plants, with the decommissioning plan launched as planned;Ensure the security of the 4th 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 4th
Nuclear Power Plant have steadily operated before 2016.

In April 2012, the Bureau of Energy also released an Energy Industry Technology White Paper. The white
paper sets up a roadmap for the development of the energy industry. It addresses the important policies andstrategies established in the Framework of Taiwan’s Sustainable Energy Policy 2008, the conclusions of the2009 National Energy Congress and action plans for the promotion of the green energy industry (BOE
2012c, BOE 2009).
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Reducing its excessive dependence on conventional energy imports is crucial to enhancing the safety
and stability of Chinese Taipei’s energy supply. In order to secure the energy supply and meet demand in
the future, in October 2012 Chinese Taipei released the ‘Guideline on Energy Development’ (BOE 2012d).
It readdresses issues of security, efficiency and clean policies for the future energy supply and demand in
Chinese Taipei. Apart from diversifying the sources and methods of acquiring energy and enhancing therate of its own energy production, Chinese Taipei is promoting energy development and proliferation via
new technologies. High costs and the stability of supply are the two problems that remain to be solved
through the development of new energy technologies. The development of accessible and affordable clean
energy domestically has become a major challenge for technological research and will require newtechnology breakthroughs.
ENERGY SECURITY
As Chinese Taipei is almost completely dependent on fossil fuel imports, the government has been working
to secure supply. To stabilise the oil supply, private oil stockpiling is expected to satisfy the Petroleum
Administration Act’ 2001’s requirement that refiners and importers maintain 60 days of sales volumes(calculated from the average domestic sales and private consumption over the preceding 12 months). Using
the Petroleum Fund to finance the storage of oil, the government is also responsible for stockpiling 30 daysof oil demand. Under the Act, the LPG stockpile should be more than 25 days of supply (BOE, 2012a).
For many years, the Chinese Petroleum Corporation (CPC) has engaged in cooperative exploration
with governments and large international oil companies under the name of the Overseas Petroleum andInvestment Corporation (OPIC), in operations throughout the Americas, the Asia–Pacific region and Africa.
Following the rising cost of oil in recent years, 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, CPC has engaged in international cooperationin exploration and development in the hope of discovering new reserves of oil and natural gas. As of theend of 2013, CPC had engaged with international oil companies in cooperative exploration in 25 fields
spread over ten economies. Within Chinese Taipei, in 2013 CPC completed geological survey of 48 square
kilometres and three-dimensional seismic surveys covering 156.8 square kilometres in western Chinese
Taipei, repaired one well and drilled a new one. There are currently 41 producing oil and gas wells in the
Tiezhenshan, Qingcaohu, Jinshui, Chuhuangkeng and Guantian fields, yielding 500 million cubic meters ofnatural gas and 10 000 kiloliters of condensate annually.
In its future strategic deployment, CPC will seek to leverage its situation in overseas exploration andproduction 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, 2014a).

ENERGY MARKETSELECTRICITY MARKETSThe Chinese Taipei Government aims to have a total electricity supply that provides a reserve capacity of
15.0% (BOE 2012a), based on peak demand. During the 1990s, some of the TPC’s new power plants wereunable to meet their construction schedules because of environmental issues and complex government
approval processes. This kept the total electricity supply below the required reserve capacity between 1990
and 2004. Reserve capacity was only about 50.0% between 1990 and 1995. In 1995, to stabilise the power
supply, Chinese Taipei’s electricity market was opened to the IPPs when the reserve capacity fell below
16.0%. Electricity produced by IPPs is sold to TPC through TPC’s transmission lines. TPC provided 66.6%
of power generation capacity in 2012, with 17.0% from IPPs and 16.4% from cogeneration plants.
In order to enhance the stability of the electricity supply, TPC continues to improve its transmission
and distribution system. In 2012, the substation and transmission facilities that underwent retrofitting were
121 units of transformers, 308 transmission towers, 88.347 ckt-km of overhead transmission lines, 149.652
ckt-km of ground lines, and 47.613 ckt-km of overhead transmission lines that were changed to undergroundcables. In terms of the distribution system, the number of newly expanded feeders reached 500. At the endof 2012, the total number of feeders being automated reached 19 657(45.0% of the total coverage). These
improvements are expected to greatly reduce the duration of forced power outages. The SAIDI (System
Average Interruption Duration Index) was 19.1 minutes/customer-year and the SAIFI (System Average
Interruption Frequency Index) was 0.298 freq./customer-year in 2012. Despite the increase in power supply
from the south to the north, the line loss was controlled at a high standard of 4.4% (TPC, 2012, 2013).

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To comply with the schedule for privatising 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. The implementation strategy of liberalisation included:The generator sector, which will be able to set up and sell power to consumers directly;An independent system operator (ISO), which is in charge of dispatching power will be set up; andTransmission and distribution, which will not be operated by the public or private sectors.

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 state-owned CPC. Chinese Taipei also welcomesthe participation of foreign investors in bidding in the IPP electricity market.

ENERGY EFFICIENCYIn 2012, the total energy consumption classified by sector are as follows: the energy and industrial sectors
consumed 45.3%; transportation sector, 11.9%; agriculture, forestry and fishery sectors, 0.9%; services
sector, 11.0%; residential sector, 10.9%; non-energy uses, 20.1%. The government considers it important toimprove 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 anenergy development and utilisation evaluation mechanism to foster gradual improvements in energy
efficiency in newly constructed or expanded factory plants via advanced management mechanisms (BOE
2012a, 2012b).
Major activities and achievements of Chinese Taipei as the economy sought to reduce its energy
intensity and reach government targets included (BOE, 2012a):Carried out energy audits of the major energy users and helped them to set up internal energy auditing
systems and reported the results to the government. A total of 4 685 high-energy users (3 261
manufacturers and 1 424 non-manufacturers) were audited by the government in 2012. The audits
showed energy savings of 55 million litres of oil equivalent (MLOE) for the 3 261 manufacturers and3.37 MLOE for the others.



Established an energy service team and provided energy technology services to help energy users
diagnose their energy systems and improve their energy efficiency. A total of 1 114 companies werevisited in 2012, which potential energy savings of 18 MLOE, with 9.1 MLOE being achieved.



Since 2001, promoted the voluntary accreditation of high energy-efficient products and an energy
labelling system. A total of 38 product categories were included in the energy labelling system, with 373
manufacturers and 6 639 brands gaining accreditation by the end of December 2012. In addition, morethan 130 million labels were issued in 2012.



Since July 2010, enforced a mandatory multi-level energy efficiency labelling mechanism. Four productcategories were included in this first stage—air conditioning units, refrigerators, vehicles andmotorcycles. Humidifiers were included from March 2011 and fluorescent lamps in July 2011. The
programme was scheduled to be expanded to gas stoves and instantaneous gas water heaters in
December 2012. There were 6 727 air conditioner models, 1 019 refrigerator models, 209 dehumidifiermodels and 1 585 CFL models for which mandatory energy label applications were completed in 2012.



Chinese Taipei began to employ LED signalised traffic lights to replace existing incandescent traffics
light from 2005. By the September 2011, all the traffic lights (about 696 700 sets of traffic lights acrossChinese Taipei) had been replaced by the LED type. It is estimated that the energy saving from thismove amounts to 247 million kWh per year. Another application of LED streetlights was also
promoted by Chinese Taipei to replace existing mercury vapour streetlights from 2008. Fifty thousand
streetlights were replaced by December 2012 with a further 234 000 across all counties replaced by theend of 2013.



Two rounds of the Energy Efficient Appliance Rebate Programme have provided residents with arebate of TWD 2 000 on each purchase of an energy-efficient appliance in 2012. It covers air
conditioners and refrigerators with energy rating labelling grades of 1 or 2, energy conservation-labelledclothes washers, and TVs and monitors above 32 inches. The total budget is about USD 45 million.

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Through the rebate program, the economy expects to save 387 million kWh per year, promote sales
totalling TWD 36.6 billion, and maintain or create more than 200 jobs.
Promoted energy service companies (ESCOs) by supporting the operations of the Taiwan Associationof Energy Service Companies and the Taiwan ESCO Business Association. An office to promote the
ESCO industry was established in 2006. A total of 87 projects were conducted under the Energy Saving
Performance Contract (ESPC) mechanism by the end of 2011, with an average energy savings of up to
53.2% compared with the pre-improvement performance. Since 2010, Chinese Taipei has also
expanded subsidies to cover the development of a low-carbon community.

Continued to focus on technology research and development (R&D) programs. The major programs
and achievements included (BOE 2012a):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 toenable more flexible management of energy-efficient living environments and efficiency in theindustrial manufacturing process. By 2012, this system was already employed in 1 245 convenience
stores in Chinese Taipei and is ready for export or technology transfer to other economies. There
are a total of 91 manufacturers involved in this area, with revenue at TWD 140 billion in 2012.
o Air conditioning and refrigeration technology: This technology development involves the gradualintegration of the capacities of different industries. It includes upstream magnetic materials and IC(integrated circuit) chips, middle stream motors, compressors, and inverter controllers, anddownstream heat pumps, air conditioning and refrigeration products. R&D efforts have focusedon patent ideas, prototype designs, manufacturing capabilities, and systems testing and analysis. The
programme gradually established industry capabilities in inverter-fed technology and products, andimproved the energy efficiency of air conditioning and refrigeration systems in Chinese Taipei. The
major achievements in 2012 were:Completion of the prototype testing of an inverter centrifugal chiller with a capacity of 500RT(refrigeration tonne) using environmental refrigerant R-134a, achieving a target of COP(coefficient of performance) larger than 6.2 and integrated part load value (IPLV) COP larger
than 9.7. Completion of the prototype testing of a centrifugal compressor water chiller with acapacity 80RT using magnetic bearings, achieving a target of COP equal to 5.3 and IPLV COP
equal to 8.5.

Development of the first prototype of a CO2 heat pump (employing its own CO2 compressor)
with COP = 4.25 at rated conditions and COP = 3.76 at winter condition.

Establishment of manufacturing capability and a key-components supply chain for inverterfed air conditioning units (both single and multi-unit systems). The domestic parts for thisunit comprise more than 90.0% of the total. The improvements mean that the new system
exceeds Chinese Taipei’s 2011 energy standards. This technology can also be deployed in DC
inverter-fed cranes.

Combustion and heat recovery technology: The key R&D effort here is to develop industrial energysaving technologies and products to reduce energy consumption by and the environmental impact of theindustry sector. It will also help the domestic industry to increase its global market competitiveness. The
major achievements in 2012 were:o Development of oxygen-rich combustion technology and its use in heavy-oil combustion systems.
This can reduce NOx gases to lower than 200 parts per million and increase efficiency more than
10.0% due to the lower exhaust temperature.
o Completion of reliability testing for an inverter-fed air-fuel control system. The system can reduce
the electricity consumption of a combustion system by up to 80.0%, compared with a traditional
control system.



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Advanced lighting technology: The new generation of lighting systems emphasises energy savings,
environmental protection and user-friendliness. To respond to global developments in advanced solidstate lighting and to keep pace with domestic industrial development to exceed the current lighting
limit, the R&D effort focuses on developing long-life LED lighting products and modules in a variety
of styles. The objective is to replace traditional lighting systems, with their high levels of environmental
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o Development of a smart lighting control system with a digital addressable lighting interface (DALI)
mechanism. This offers a graphical user interface to allow effective and user-friendly operation of
the lighting control system.
o Establishment of LED testing and verification laboratories, including three National Voluntary
Laboratory Accreditation Program (NVLAP) international accreditation laboratories, six EnergyStar accreditation laboratories, and 10 Taiwan Accreditation Foundation (TAF) accreditationlaboratories. There were a total of 60 Chinese National Standards (CNS) by the end of 2012, of
which two are harmonised with international IEC standards. The standards cover LED chips,
components, modules, systems and lighting fixtures.

RENEWABLE ENERGY
The main three green energy industries for renewable energy in Chinese Taipei are photovoltaic 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 renewable energy industries in 2012
included solar, wind and bioenergy as detailed below (BOE, 2012a, 2012b).
PHOTOVOLTAIC (PV) SYSTEMS
After the Renewable Energy Development Act was passed in 2009, a feed-in tariff mechanism replaced thesubsidies formerly used to promote renewable energy. The new mechanism has attracted more private sector
investment to install PV systems. At the end of 2012, the total installed capacity was 222.4 MW withelectricity generated reaching 173.1 GWh.
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 2012, there
were about 257 companies with total revenue of about TWD132.2 billion. To increase the value andcompetitiveness of its PV industry in the global market, the government has provided partial subsidies forthe application of a building integrated photovoltaic (BIPV) demonstration system.
WIND POWER SYSTEMSThe development of a wind power industry is mainly for the domestic market. TPC and private wind-energy
developers continued to develop onshore wind turbine systems. By the end of 2012, Chinese Taipei had
installed 290 sets of wind turbines economy-wide, with a total installed capacity of 571 MW, and an annual
output of 1.414 billion kWh of electricity. This is sufficient to supply electricity for one year to 357 000
households. For offshore wind energy, a demonstration incentive program was announced in July 2012. By
the end of December 2012, Chinese Taipei had selected three companies to receive subsidies to build
demonstrative offshore wind farms with a generating capacity of 300 MW by 2020. The output value of thewind farms when completed in 2020 will be TWD 48 billion.
BIOENERGY
The bioenergy industry includes bio-diesel, bio-methane, and bio-heat and the power industries. Chinese
Taipei has mandated an added 2.0% of biodiesel in its diesel for transportation vehicles from June of 2010.
By the end of 2012, the consumption of biodiesel was 100 thousand kilolitres and 11 companies wereapproved as qualified biodiesel manufacturers with a production of about 84 thousand kilolitres. The
biodiesel industry mainly uses waste cooking oil as its raw material (BOE, 2012a). Chinese Taipei also has ademonstration project for adding 3.0% of methane to gasoline for transportation vehicles in major cities.
There were a total of 14 gasoline stations that can provide bio-methane in 2012.
In addition to the application of biodiesel in the transportation sector, Chinese Taipei has a total of 822
MW of power generation capacity employing bioenergy or waste as the input fuel with a total electricity
generation of 349 million kWh in 2012.
RESEARCH AND DEVELOPMENT PROGRAMSThe Chinese Taipei Government will continue to focus on technology R&D programs. The major programs
and achievements in 2012 were (BOE, 2012a):
The application of solar heating
Solar heating R&D priorities included continuous sputtering process performance, the small-scale
development of solar thermal power generation systems, the design of large-scale solar hot water systems

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and optimisation, structural safety and anti-wind damage technology for solar water heating systems. The
major achievements in 2012 were:

A solar heat collection system with GPS and solar orbit-tracing mechanisms. Heat collection efficiency
can reach more than 85.0% for power generation with a capacity of 300 W.

The development of evaluation technology for large-scale solar hot water system designs.

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. An internationalverification technology for PV modules and facilities was also set up in 2012. The major achievements in2012 were:

New high-efficiency hetero-junction solar cells were developed through the integration of interface
processing technology, a p-type amorphous silicon layer to enhance conductivity and optimisation of
the transparent conductive layer to improve solar cell efficiency to 19.0% and modules to 16.9%.



A new generation of thin-film solar modules, 150 µm thick, was developed that can achieve 18.9%
efficiency.

A prototype of dye-sensitised solar modules with glass substrate was developed with an efficiency of
8.5%, and one with a flexible substrate was also developed with an efficiency of 5.4%.



A copper indium gallium selenide (CIGS) was developed using vacuum technology and slurry print
production technology. The conversion efficiency of the CIGS using vacuum technology can reach
16.0%, while the module efficiency with flexible stainless steel sheets can reach 14.2%.

Bioenergy
This R&D focus involved the development of key energy technologies, including microalgae oil production
and biomass pyrolysis.
Wind power
This R&D focus included the development of offshore wind power engineering technology and equipment,
and the establishment of a comprehensive systems analysis and integration design capacity. Chinese Taipei
also focuses on the requirements for product differentiation and energy security to develop specific projects
for enhancing the global competitiveness of the local wind power industry. The major achievements in 2012were:

Based on typhoon data from the APEC region and following the IEC specification to specify design
loading conditions and parameters, a 5 MW wind power system simulation model was set up.

Evaluations conducted on the potential for off-shore wind power systems along the Taiwan Strait
revealed that the potential for a depth below 50 m is around 57 GW, while the potential for actual
development is about 7.4 GW.

Fuel cell and hydrogen applications
To promote hydrogen and distributed power generation technologies, the first priority of R&D was thedevelopment of fuel cell applications using hydrogen, supported by advanced production and storage
technologies for hydrogen. The major achievements in 2012 were:Continue the life testing for a 3 kW fuel cell cogeneration system. The overall system efficiency is 78.0%
with power generation at 32.0% and heat recovery at 43.9%. Cumulative testing time reached 8,087
hours as of the end of 2012.

Continue to put efforts into system integration for the application of fuel cells and enhancing
capabilities for the development of key components, including the membrane electrode assembly, a gas
diffusion layer/electrode, recombinant, etc. There were a total of 51 manufacturers with total revenueof about TWD 1 136 million in 2012.

NUCLEARTo diversify the economy’s electricity generation mix, the government encourages the development of
nuclear energy. At the end of 2010, there were three nuclear power plants with six units and a total installedcapacity of 5 144 MW. The Fourth Nuclear Power Project is adopting two 1350 MW Advanced Boiling
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Water Reactor (ABWR) units. GE-Hitachi Nuclear Energy Americas LLC supplies the two units (AEC2013). However, in April, Chinese Taipei announced that unit one would be mothballed once safety checks
were complete, and construction of unit two would be halted. TPC has submitted plans to the MOEA andAtomic Energy Council (AEC) for sealing unit one, meaning that equipment will be put into a protectedcondition which will allow future use, after the completion of safety checks. A referendum on the future of
the plant would be held, but no date has been set (WNS, 2014).

CLIMATE CHANGE
GREENHOUSE GAS EMISSIONS
Chinese Taipei produces CO2 emissions that account for about 1.0% 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 seek carbon reduction plans that are cost-effective. 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 the energy users and the public. By the end of 2011, the Service Team
had acted on 2 860 calls for assistance in the field, organised 198 training workshops and seminars, andanswered 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.
The potential cumulative carbon emissions reductions were estimated to be 37.5 million ton/CO2e
with 17.8 million tonnes/CO2e verified by the end of 2012.
Emissions from fossil fuel combustion are the major source of greenhouse gas (GHG) emissions in
Chinese Taipei. The economy emitted 248.7 million tonnes of CO2 in 2012, down 1.9% over 2011. This isa reflection of efforts by Chinese Taipei toward energy conservation and carbon reduction over the past
couple of years. It also shows that the average growth rate of CO 2 emissions has slowed significantly in thepast decade. CO2 emissions grew 1.2% annually after the year 2000, slower than the economic growth rate
(3.1% annually), and the economy’s CO2 intensity has steadily declined since 2003. It appears that the rates
of CO2 emissions and economic growth have started to decouple in the economy over the past three years(2008–10). To reduce the environmental impact of its development, Chinese Taipei must seek the mostadvantageous development objectives for the economy from among the various policies on environmental
protection, industrial development and energy supply (BOE, 2012a).
PROMOTION OF LOW-CARBON ENERGY TECHNOLOGY AND INDUSTRY
Chinese Taipei has a developing green energy industry. However, if it is to respond to future developments
and competition, it will need to gain full access to key and innovative technologies. Faced with fierce
competition globally, the economy is strengthening its R&D and innovation capabilities so that it can masterniche technologies and enhance the economy’s competitiveness. Chinese Taipei has been ranked sixth by
the International Institute for Management Development in the area of creating competitive advantages in
the green technology industry.
The development of emerging industries such as the green energy industry depends on the economy
changing its focus from export processing, which was its previous focus, to an industrial model that involves
the aggressive development of key technologies. This latter focus 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 of manufacturing key components into one that utilises vertical system
integration. This will enhance the international competitiveness of the economy’s green energy industry andhelp to promote the philosophy that value creation is worth more than production output.
To create an energy-efficient society and low-carbon economy, in 2009 Chinese Taipei selected sevengreen energy industries in which it sees development potential. These are based on its existing IT industry
and human resources. Of those seven green energy industries, the PV and LED lighting industries are
regarded as the pillar. Other promising industries include the wind power, biomass, hydrogen and fuel cell,

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Energy Information Communication Technology (EICT) and electric vehicle industries. The total revenue
from these green energy industries was TWD 373.1 billion in 2012 with a growth of 133.0% compared with
2008. The cumulative new investment from 2009 to 2012 was TWD 237.7 billion, with the creation of new
employment opportunities for 65 100 people from 2008 to the end of 2011.
N OTA B L E E N E RG Y D E V E L O P M E N T SMILLION SOLAR ROOFTOP PROGRAM
In responding to public concerns about nuclear safety after the Fukushima earthquake, Chinese Taipei
comprehensively reviewed the possibility of expanding the development of renewable energy from mid2011. Bureau of Energy established the promotion office of ‘Million Rooftop PVs Program’ on March 28,
2012 to administer the promotion businesses. The Million Rooftop PVs Promotion office administers two
main missions, foster PV-friendly environment in Taiwan and assist governments and industries inpromoting PV installed capacity of 6 200 MW by 2030 (BOE, 2014b).
The establishment of the promotion office is for the integration of related resources for harnessing
renewable energy and providing professional assistance to resolve barriers which hindering the installationof renewable energy generation systems. The promotion office will provide total solutions for local
renewable energy businesses, city and county governments, and system installation contractors in theutilisation of renewable energy.
In 2013, 392MW accumulated PV capacity had been established, and PV installation target will berevised to reach 602MW by 2014, 842MW by 2015, 2 120 MW by 2020, 4 100MW by 2025, and 6 200MW
by 2030.

THOUSAND WIND TURBINES PROGRAM
Chinese Taipei has an estimated wind potential of more than 15 GW. To accelerate the development ofwind industry, Chinese Taipei plans to shift the focus of wind energy from onshore to offshore, and set up
more than 1 000 wind turbines by 2030. The accumulated capacity of wind will thus reach 4 200 MW (BOE,
2014c).
For onshore wind energy, superior wind farms will first be developed before harvesting secondary windfarms. As for offshore wind energy, a demonstration incentive scheme was announced to encourage
developers to set up three pioneering offshore wind farms in shallow water area (depth below 20 m) by
2015. The capacity of each wind farm is 100-200 MW, and Chinese Taipei will provide TWD 250 million
for the expense of wind farm development, as well as 50.0% equipment subsidy for the first 2 turbines ofeach wind farm. With experiences gained from the development of the pioneering wind farms, the next stepis to exploit deepwater area (depth above 20 m) in mass production scale. By 2020, 450 onshore windturbines of 1,200 MW are scheduled, and by 2030, 600 offshore wind turbines of 3 000 MW. The total
accumulated capacity adds up to 4 200 MW, which makes up 33.0% of the renewable energy promotion
target.
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––––(2011). Steadily Reduce Nuclear Dependency, Gradually Move Towards a Nuclear-Free Homeland,
http://web3.moeaboe.gov.tw/ECW/english/content/Content.aspx?menu_id=969––––(2012a). 2012 Annual Report.
http://web3.moeaboe.gov.tw/ECW/populace/content/ContentLink.aspx?menu_id=137––––(2012b). Energy Statistics Handbook 2012.
http://web3.moeaboe.gov.tw/ECW/english/content/SubMenu.aspx?menu_id=1537––––(2012c). 2012 Energy Industry Technology White Paper.
http://web3.moeaboe.gov.tw/ECW/populace/content/SubMenu.aspx?menu_id=62&sub_menu_id=148––––(2012d). Guideline on Energy Development (Chinese Version)
http://web3.moeaboe.gov.tw/ECW/populace/news/News.aspx?kind=2&menu_id=56&news_id=2565
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C H I N E S E T AI P E I––––(2013). Long Term Load Forecasting and Power Development Plan (Chinese Version)
http://web3.moeaboe.gov.tw/ECW/populace/content/Content.aspx?menu_id=65––––(2014a). Monthly Energy Statistic (Chinese Version)
http://web3.moeaboe.gov.tw/ECW/populace/web_book/WebReports.aspx?book=M_CH&menu_id=142––––(2014b). Million Solar Rooftop Program
http://web3.moeaboe.gov.tw/ECW/english/content/SubMenu.aspx?menu_id=1832––––(2014c). Thousand Wind Turbines Program
http://web3.moeaboe.gov.tw/ECW/english/content/SubMenu.aspx?menu_id=1833
CPC (Chinese Petroleum Corporation) (2014). CPC 2014 Annual Report.
http://en.cpc.com.tw/annual_reports.aspx
DGB (2013). Directorate-General of Budget (Accounting and Statistics, Executive Yuan). 2013
Statistical Yearbook of the Republic of China.
http://ebook.dgbas.gov.tw/public/Data/41029151636JHS9PT6X.pdf
EDMC (Energy Data and Modelling Center) (2012). APEC energy database. Institute of Energy
Economics, Japan. www.ieej.or.jp/egeda/database
EIA (Energy Information Administration) (2014). International Energy Statistics.
http://www.eia.gov/countries/country-data.cfm?fips=TW
TPC (Taiwan Power Company) (2012). TPC 2012 Annual Report.
http://www.taipower.com.tw/UpFile/AboutUsFile/2012_tpc.pdf–––– (2013). TPC 2013 Sustainability Report.
http://www.taipower.com.tw/UpFile/_userfiles/file/2013CSR-all_pdf.pdf
WNA (World Nuclear Association) (2014) Nuclear Power in Chinese Taipei.
http://world-nuclear.org/info/Country-Profiles/Others/Nuclear-Power-in-Taiwan/
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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T H AI L AN D

THAILANDI N T ROD U C T I ON

Thailand is a Southeast Asian economy with an area of 513 115 square kilometres and a population of about
66.8 million in 2012. Thailand shares borders with Malaysia to the south and with Myanmar, the Lao People’s
Democratic Republic and Cambodia to the north and east. In 2012, Thailand’s GDP reached
USD 899.7 billion (USD 2010 at PPP), a 7.7% increase from USD 835.6 billion in 2011. In the same period,
GDP per capita increased 7.3%, from USD 12 552 (USD 2010 at PPP) to USD 13 472 (USD 2010 at PPP).
At the end of 2012 Thailand had proved reserves of 427 million barrels of oil, 285 billion cubic metres ofnatural gas and 1 239 million tonnes of coal. Notwithstanding its resources, Thailand is highly dependenton energy imports, particularly oil, with more than 85.0% of its oil supply coming from imported stock in2012 (DEDE, 2014).
Table 1: Key data and economic profile, 2012
Key dataa

Energy reservesb

Area (thousand sq. km)

513.1

Oil (million barrels)

427

Population (million)

66.8

Gas (billion cubic metres)

284.9

GDP (USD (2010) billion at PPP)

899.7

Coal (million tonnes)

1 239

GDP (USD (2010) per capita at PPP)

13 472

Uranium (kilotonnes U)-

Source: a. (EDMC, 2014); b. Proved reserves (BP, 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 2012 was 111 011 kilotonnes of oil equivalent (ktoe), which represented
an increase of 3.7% from 2011. Oil accounted for 41.0% of the total primary supply, while gas, coal andothers accounted for roughly 41.0%, 8.0% and 10.0%, respectively. As most of Thailand’s proved coalreserves are lignite coal with lower calorific values, imported stock is needed to meet energy demand forboth electricity generation and the industry sector. In 2012, coal supply was 8 308 ktoe, down 1.8% fromthe previous year.
Natural gas supply in 2012 was 45,658 ktoe, a 0.4% decrease from 45,990 ktoe in 2011. Although natural
gas is mostly used for power generation in Thailand, its use is also promoted in the transport sector, as areplacement for conventional petroleum products such as fuel oil, diesel and gasoline. As world oil prices
have increased in recent years, more industries have switched from oil to natural gas and Thailand has
followed suit, increasing its reliance on imported natural gas, both in the form of piped gas and liquid naturalgas (LNG). The Thai Government has an ambitious plan to diversify the economy’s energy sources. Under
the Third Revision of Thailand Power Development Plan (PDP 2010), approved in 2010, renewable energy,
nuclear power and coal (with clean coal technology) will be the main sources of energy diversification by
2030. The Ministry of Energy is preparing a new version of the Power Development Plan, which provides
a more diversified energy mix by increasing the shares of coal and imported electricity.
However, following the damage to Japan’s Fukushima Daiichi nuclear plant after the earthquake andtsunami of March 2011, the Thai Government has faced serious opposition to nuclear power plants fromits citizens, and thus construction of these plants is pending.
In 2012, total electricity generation was 171,268 GWh. Thermal generation, mostly from natural gas
and coal, accounted for nearly all of the power generation (85.0%), with hydropower and others accounted
for the remainder. In addition to its domestic capacity, Thailand purchased power from the Lao People’s
Democratic Republic and Malaysia.

Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

210

Final energy consumption (ktoe)

Power generation (GWh)APEC E N E RG Y O VE R VI E W 2014

T H AI L AN D

Indigenous production

62 284 Industry sector

18 875 Total

171 268

Net imports and other54 119 Transport sector

22 552

Thermal

144 931

Total PES

111 011 Other sectors

32 949

Hydro

8 641

Coal

8 308 Total FEC

74 376

Nuclear–Oil

45 829

Coal

6 643

Geothermal

1Gas

45 658

Oil

47 158OthersOther

11 215Gas

6 703

Electricity and other13 871

17 695

Source: (EDMC, 2014).

FINAL ENERGY CONSUMPTION
Thailand’s total final energy consumption in 2012 was 74 376 ktoe, an increase of 16.5% from the previous
year. The transport sector was the largest energy-consuming sector, accounting for 22 552 ktoe, or 30.0%of the total final energy consumption. The second largest consumer of energy was the industry sector, which
consumed 18 825 ktoe in 2012, an increase of 4.5% from 2011. By fuel type, oil accounted for a 63.0% share(47 158 ktoe) of the total energy consumption in 2011, followed by electricity and others (19.0%), coal
(9.0%) and gas (9.0%).
Oil demand increased significantly by 26.0% from 37,400 ktoe in 2011 to 47 158 ktoe in 2012. Natural
gas consumption increased by 4.5%. Coal consumption decreased by 9.0% from 7 267 ktoe in 2011 to 6
643 ktoe in 2012. Domestic electricity and other energy demand in 2012 increased by 8.7% from 12 759
ktoe in 2011 to 13 871 ktoe in 2012. The growth in demand was mainly due to increased consumption in
the residential and commercial sectors.
ENERGY INTENSITY ANALYSIS
Thailand’s energy intensity of primary energy in 2012 was 123.4 tonnes of oil equivalent per million USD,
which decreased by 3.7% from 128.4 tonnes of oil equivalent per million USD in 2011. The energy intensityof final energy demand increased 8.2% from 76.40 tonnes of oil equivalent per million USD in 2011 to 82.7
tonnes of oil equivalent per million USD in 2012. The energy intensity of both the industry sector andtransport sector decreased by 3.0%, while the energy intensity of other sector, which mainly includes
commercial and residential sector, increased largely by 26.6%.
Table 3: Energy Intensity Analysis
Energy Intensity (tonnes of oil
equivalent per million USD)

Energy2011

Change (%)

20122011 vs 2012

Primary Energy

128.1

123.4

-3.7

Final Energy Demand

76.4

82.7

8.2

Industry

21.6

21.0

-3.0

Transportation

25.9

25.1

-3.0

Others

28.9

36.6

26.6

Source: EDMC (2014).
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 will ensure the economy
has sufficient energy to meet its needs. The Ministry is responsible for:
211

establishing energy security;

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T H AI L AN D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 theenvironment and mitigating climate change.
Organisations also responsible for energy include the following:

Office of the Minister—responsible for coordination with the Cabinet, the parliament and the generalpublic;

Office of the Permanent Secretary—establishes strategies, translates policies of the ministry into actionplans, and coordinates international energy cooperation;



Department of Alternative Energy Development and Efficiency (DEDE)—promotes the efficient useof 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 generation enterprise;Petroleum Authority of Thailand (PTT) Exploration and Production (E&P) Public Company Limited
and the Bangchak Petroleum Public Company Limited—two autonomous public companies;Energy Fund Administration Institute—a public organisation; andEnergy Regulatory Commission (ERC) and the Nuclear Power Program Development Office—two
independent organisations.
The government’s energy policy seeks to:build an energy self-sufficient society;achieve a balance between food and energy security;build a knowledge-based society;

promote Thailand’s role in the international arena; andenhance economic links with other economies in the region to harmoniously cooperate in energy andother sectors.

The current government, led by Prime Minister Prayuth Chan-o-cha, stated to the National Legislative
Assembly of Thailand on 12 September 2014 that energy price structure will be reformed to reflect actual
costs and taxes for different types of fuels and different groups of consumers. This reformation of energy
price structure would lead to energy efficiency, consumer awareness and behaviour changes. On the supply
side, the government will proceed with new surveys and exploration for oil and gas both onshore andoffshore. Also, the construction of new power plants using fossil fuels and all renewable energy by stateown enterprise and private sector will be continuously pursued through open consultation with the public,transparency and fairness, and accounting for environmental concerns. The development of energy
resources together with neighbouring countries is also one of the prioritised policies.
There are four pillars of energy policy in Thailand, which are discussed in more detail below. They are:energy security;renewable energy;energy efficiency; and212

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T H AI L AN D

energy price regulation.

At the present, Thailand’s energy policy is driven by three energy policy plans namely, the Power
Development Plan (PDP), the Energy Efficiency Development Plan (EEDP), and the Renewable andAlternative Energy Development Plan (AEDP).
ENERGY SECURITY
The government’s energy security policy will intensify energy development for greater self-reliance, with aview to achieve 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 of energy
resources;

developing an appropriate energy mix to reduce risks to supply, price volatility and production costs;



encouraging electricity production from potential renewable energy sources, particularly from smallscale or very small-scale electricity generating projects; and

investigating other alternative energy for electricity generation.

ALTERNATIVE ENERGY
The government’s alternative and renewable energy policy is to encourage the production and use ofalternative energy, particularly biofuel such as gasohol—a mix of ethanol into gasoline in different
percentages: E10, E20 and E85—biodiesel, biomass, solid waste and animal manure, to enhance energy
security, reduce pollution and benefit farmers. It will do this by encouraging the production and use ofrenewable energy at the community level using appropriate incentive measures, and by promoting researchand development in all forms of alternative energy.
Six strategies to achieve the policy under the current 10-year Renewable and Alternative Energy
Development Plan (AEDP) 2012–2021 are:

Promoting the community to collaborate in broadening the production and consumption of renewableenergy;

Adjusting the incentive measure on investment from the private sector to be appropriate to thesituation;

Amending the laws and regulations that do not benefit renewable energy development;

Improving the infrastructure as system of transmission lines, power distribution lines, including thedevelopment of a Smart Grid System;



Public relations and building up comprehensive knowledge for the people; andPromoting research work as a mechanism to develop an integrated renewable energy industry.
FISCAL REGIME AND INVESTMENT

ENERGY PRICESThe government’s energy price policy is to supervise and maintain energy prices at appropriate, stable andaffordable levels. It will do this by:setting an appropriate fuel price structure that supports the development of energy crops and that bestreflects 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 of service
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 to reflect the actual production costs. Theenergy cost for Thai people must not be higher than that in neighbouring economies. The government is
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supervising 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.
For LPG and NGV, prices will reflect the resolutions of the NEPC and Cabinet, which will not place aburden on consumers.
INVESTMENT
The Government is keen to encourage competition and investment in energy businesses by creating afavourable environment for investment, transparent competition and internationally-accepted energyrelated standards. It will do this by designating an agency, the Investor Relation Office, to be responsiblefor investment 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
Thailand 20-Year Energy Efficiency Development Plan (EEDP) was launched in 2011 with a target to
reduce energy intensity, that is, EI (energy consumption/GDP) by 25.0% in 2030, compared with that in2010, or equivalent to a reduction of the final energy consumption by 23.5% in 2030 or 38 200 ktoe. The
EEDP sets the targets of energy reduction for major economic sectors including transportation, industry,
commercial and residential sectors with six strategic packages and 16 specific measures as follows:

The application of a number of combined measures, i.e. mandatory measures via rules, regulations andstandards, and promotional and supportive measures via incentive provision;

The introduction of 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 behaviourof 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 to 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;The use of professionals and Energy Services Companies (ESCO) as an important tool to provide
consultancy and to implement energy conservation measures in which the use of more advanced
technology is involved; andIncrease in self-reliance in indigenously developed technology to reduce technological costs and toincrease access to energy-efficiency technology, including promotion of highly energy-efficient productmanufacturing processes.

To implement the plan, there are 16 specific measures under five strategic approaches, which will be
introduced. The strategic approaches and measures are as follows:
MANDATORY REQUIREMENTS VIA RULES, REGULATIONS AND STANDARDSEnforcement of the Energy Conservation Promotion Act B.E. 2535 (1992), which would put in effectan energy management system based on energy consumption reporting and verification imposed on
designated buildings and factories;

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

Enforcement of the Minimum Energy Performance Standards (MEPS) for equipment/appliances,buildings and vehicles to prevent the distribution and use of low energy-efficient products;



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

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ENERGY CONSERVATION PROMOTION AND SUPPORT

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



Support and incentive provision to encourage voluntary energy-efficiency labelling for highly energyefficient 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 theDSM (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 be verified or
accurately assessed for SMEs, as per the project proposals submitted under the Standard Offer Program(SOP) scheme, which requires no bidding;Support for 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
Public relations and provision of knowledge about energy conservation to the general public, via
the teaching/learning process in educational institutions, fostering youth awareness and otherpublic awareness activities, such as eco-driving;Putting forth the concepts and promoting 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 will leadto a reduction of GHG emissions and efficient use of energy;

Determination of energy prices to reflect the actual costs and application of tax measures as animportant tool to promote energy conservation with a view to fostering public awareness andchanging their energy consumption behaviour.

PROMOTION OF TECHNOLOGY DEVELOPMENT AND INNOVATIONPromote research and development to improve energy efficiency and reduce technological costs,
particularly those related to equipment/appliances with large markets and manufacturing bases inThailand, including the production process, materials as well as buildings and housing that are energy
efficient;Promote demonstrations of energy-efficiency technologies that have been technically proven but havenot been commercialised in the domestic market, including support for 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 be
responsible for energy management and operation, verification and monitoring, consultancy andengineering services provision and the planning, supervision and promotion of the implementation ofenergy conservation measures;Support the development of the institutional capability of agencies/organisations in both the public
and private sectors, responsible for the planning, supervision and promotion of the implementation ofenergy conservation measures.

Furthermore, the Energy Efficiency Action Plan (EEAP) has been developed under the strategic
framework of the EEDP. The EEAP has been approved by the National Energy Policy Committee (NEPC)
and was endorsed by the cabinet in early 2013. There are 67 major measures/projects under the plan. Mostof measures are sector-wide. The rest are sector-specific measures that include 18 measures for the transport
sector and five measures for each of industry sector, large commercial building sector, and small commercial
building and residential sector. 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, 3 630 ktoe from the large
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commercial building sector, and 3 635 ktoe from the small commercial building and residential sector.
Moreover, the EPPO has completely developed a 10-Year R&D master plan for energy efficiency to guideresearch and development directions in line with the EEDP and EEAP.
RENEWABLE ENERGYThe Ministry of Energy, by the DEDE is very keen to develop alternative and renewable energy to secureenergy resources and provide affordable energy to all Thais. There were several revisions of the renewable
and alternative development plan during the last decade. The 10-Year Renewable and Alternative Energy
Development Plan 2012–2021 (AEDP), formerly the 15-Year Renewable Energy Development Plan 2008–
2022 (REDP), sets a target to increase the share of renewable and alternative energy up to 25.0% of totalenergy consumption by 2021 (DEDE, 2011). The plan states the Thai government will encourage the useof indigenous resources including renewable and alternative energy (particularly for power and heatgeneration), and supports the use of transport biofuels such as ethanol-blended gasoline (gasohol) andbiodiesel. The plan also strongly promotes community-scale alternative energy use, by encouraging the
production and use of renewable energy at the local level, through appropriate incentives for farmers. It also
rigorously and continuously promotes research and development 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 successfully self-workable measures, such as the Revolving Fund that provides low interest rates, will beterminated.
The 2021 targets of the AEDP have been clearly allocated based on technologies related to power
generation, heat generation and biofuels for transportation. The breakdown of those targets is as follows:
RENEWABLE ENERGY FOR POWER GENERATION
Solar power 3 000 MW
Power generation from solar will focus more on small system projects at the house and community level,
including Solar PV Rooftop, for 1,000 MW within 10 years. To achieve the target, a Feed-in Tariff (FiT)
system for the Solar PV Rooftop has been recently introduced. The Fit rate for residential units with lessthan 10kWp capacity is set at THB6.96/unit, while that of the small business buildings with less than 250
kWp capacity is set at THB6.55/unit. The Fit rate for medium- and large-scale business buildings/factories
with less than 1,000 MWp is fixed at THB6.16/unit, while those with a capacity larger than 1MWp has yet
to be determined. The subsidy period is set for 25 years.
Wind energy 1 800 MW
To do this, installing wind turbines in remote areas and non-electrified islands will be promoted. Promotionof private investment and development of the appropriated type of wind turbine for Thailand are crucial toachieving the target. There is also a need to enact amendments to regulations and acts regarding some issues
such as land utilisation in restricted areas.
Small hydropower 324 MW
Support to construct hydropower plant projects at the community level and support the local administrative
organisations so that they can collaborate as project owners and be capable of further self-management andmaintenance.
Biomass 4 800 MW
The development will focus on promoting communities to collaborate in broaden production andconsumption of renewable energy, the so-called Distributed Green Generation (DGG). The state utilities,i.e., EGAT and PEA (Provincial Electricity Authority) are to extend transmission and distribution lines tosupport the development of biomass power plant projects, especially in areas with a high potential for feedstocks.
Biogas 3 600 MW
The target of 3 000 MW will be power generation from Napier Grass, the latest energy crop being promotedby the Thai government. DEDE has granted THB 350 million from its research budget for producing biogas
from Napier Grass.
Municipal Solid Waste (MSW) 400 MW

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The development will focus on promoting the production of energy from MSW in small communities
including schools, temples and local organisations. There is also a need to enact amendments to laws andregulations that will allow government enterprise to co-invest with the private sector.
New energy 3 MW
The two types of new energy that will be promoted in Thailand by 2021 are power from geothermal energy(1 MW) and power from wave and tidal current (2 MW).
RENEWABLE ENERGY FOR HEAT GENERATION
Solar thermal 100 ktoe
This target will be achieved by promoting the installation of solar heating/cooling in government buildings,
solar hot water for households, solar drying system for SMEs, and development of a compulsory mechanism
such as a building energy code that will require large buildings to install solar hot/cool water system.
Biomass 8 500 ktoe
This target will be achieved by promoting the production system of biomass pellets and the co-generation
system of combined heat and power for broaden use.
Biogas 1 000 ktoe
Municipal Solid Waste (MSW) 200 ktoe
BIOFUELS FOR TRANSPORTATION
Ethanol 9.0 million litre/day
This target will be achieved by increasing the national average production of cassava and sugarcane, as wellas promoting other alternative crops, such as sweet sorghum, etc. For example, on the demand side,preparations will be made to terminate the use of 91 benzene and promote E20, and E85, along withintroducing ED95 (95.0% Ethanol blended with 5.0% additives for modified diesel engines).
Biodiesel 7.2 million litre/day
This target will be achieved by increasing the yield from crude palm oil plantations, mandating B7 andintroducing B10 and B20 for fleet trucks and fishery boats.
New fuels for future diesel substitution 3.0 million litre/day
This target will be achieved by introducing other alternative feedstock, such as Jatropha and seaweed-algae,
in addition to new technologies, such as Bio-hydrogenated diesel (BHD), Biomass to liquid (BTL), etc.
Compressed biogas (CBG) 1 200 ton/day.
NUCLEAR
Nuclear power is one of the selected energy resources in the Thailand 20-Year Power Development Plan
(PDP2010), which aims to ensure sufficient energy supply and diversify the power energy mix. The Second
Revision PDP 2010 has postponed the scheduled commercial operation date (SCOD) of the first unit of
the nuclear power project by three years from 2020 to 2023, after the Fukushima Daiichi Nuclear Power
Plant disaster caused by the earthquake and tsunami in March 2011. Currently, the Third Revision PDP
2010 has again shifted the SCOD of the first unit to 2026 and scheduled the second unit to begin operationsin 2027. By 2030, the last year of the plan, nuclear power will comprise 5.0% of the total generation capacity.
CLIMATE CHANGE
Thailand has a strong policy for protecting the environment from the impact of energy production andconsumption, especially the impact of the transport sector. The government’s environmental protection
policy is to encourage energy procurement and consumption and to attach importance to the environment,along with public participation. It does this by setting relevant standards and promoting Clean Development
Mechanism (CDM) projects to reduce social and environmental impact as well as greenhouse gas emissions.
The strategies employed include the following targets and actions, which are designed to achieve the policies:217

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MONITOR THE ENVIRONMENTAL IMPACT OF ENERGY PRODUCTION,CONVERSION AND USE.
Set a target and develop a plan to boost the management of greenhouse gas (GHG) emission rates in theenergy sector, with the aim of reducing Thailand’s CO 2 emissions by at least 1 million tonnes per year. The
actions proposed are:

Select pilot power plants and conduct a study on the reduction of GHG emissions from one natural
gas-fired thermal power plant, one coal-fired thermal power plant and one combined cycle power plant;and

Devise a plan to reduce GHG emissions in the energy industry, e.g. determine the baseline and develop
a clear response plan.

PROMOTE THE CDM IN THE ENERGY SECTOR TO REDUCE GREENHOUSE GASEMISSIONS.
The objective is to enable Thailand to submit energy projects for certification under the CDM, at a total of
1 million tonnes of CO2 per year, and enhance the economy’s role as a leading exporter of carbon credits in
Asia. The following actions are proposed:Promote the wider use of flare gas, e.g. as a substitute for LPG in the production process of community
products or as fuel in community-scale power generation;

Manage energy production to keep the level of flare gas at the minimum, or prepare to announce a
Zero Flare policy, particularly for onshore petroleum sites;

Promote study and research into carbon capture and storage (CCS) technology to compress and store
carbon dioxide underground;Conduct a feasibility study on the application of CCS technology in Thailand and develop a pilot project
for an operational trial.

CONTROLING AND MONITORING VOLATILE ORGANIC COMPOUND (VOC)EMISSIONS FROM PETROCHEMICAL AND REFINING INDUSTRIES TO MINIMISEENVIRONMENTAL IMPACT.
This measure strives to control the emissions of all factories to meet standards in force and to create lowcost ‘appropriate technology’ innovations that are environmentally friendly and easy to operate and that canbe maintained at a rate of at least five innovations per year, with support from the Energy Conservation
Promotion Fund. In order to achieve this objective, it will be necessary to further expand implementation of
the policy on vapour recovery units from four provinces to an additional seven provinces in areas where alarge number of oil reserve depots are located; and also to enforce the schedule for EURO 4 standards from
1 January 2012.
NOTA BLE DE V ELO P ME NT S
Thailand is undertaking an on-going process to revise the three major energy policy plans:Power Development Plan (PDP);Energy Efficiency Development Plan (EEDP); and

Renewable and Alternative Energy Development Plan (AEDP).

The three plans will be revised under the same time period, from 2015 to 2036. The plans will be more
consolidated, and the energy saving and renewable energy targets will be integrated in the PDP. The
target for energy efficiency will be a 30.0% reduction of energy intensity by 2036, compared to the 2010
level. This new target is still in line with APEC’s target of energy efficiency. The tentative target for the
new long-term AEDP is to increase the share of renewable energy to 20.0% of power generation by
2036. The integration of these three plans would offer a more comprehensive approach to energy
planning for Thailand.

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T H AI L AN DREF ER EN CE S
BP (2014). Statistical Review of World Energy 2014. www.bp.com/statisticalreview
DEDE (Department of Alternative Energy Development and Efficiency) (2011). The Renewable andAlternative Energy Development Plan for 25 Percent in 10 Years (AEDP 2012–2021),
www.dede.go.th/dede/images/stories/dede_aedp_2012_2021.pdf——(2014a). Thailand Energy Situation 2012. Ministry of Energy. http://www.dede.go.th/dede/––––(2014b). The Direction of Thailand’s Energy: Renewable Energy Development. The proceeding forthe public hearing on 29th August 2014.
EDMC (Energy Data and Modelling Center) (2014). Apec Energy Database. Institute of Energy
Economics, Japan. www.ieej.or.jp/egeda/database/database-top.html
EPPO (Energy Policy and Planning Office) (2012). Summary of Thailand Power Development Plan 20122030 (PDP2010: Revision 3). Ministry of Energy. www.eppo.go.th.
–––– (2014). The Progress of the Energy Efficiency Development Plan. The proceedings for the highlevel executives meeting on 28th October 2014.
The Royal Thai Government (2014). Statement of the Cabinet to the National Legislative Assembly of
Thailand. The Office of Prime Minister.
http://www.mof.go.th/home/Press_release/News2014/history_61.pdf
U SEF UL LI N K S
Department of Alternative Energy Development and Efficiency (DEDE)—
http://www.dede.go.th/dede/Electricity Generating Authority of Thailand (EGAT)—www.egat.co.th/en
Energy Policy and Planning Office (EPPO)—www.eppo.go.th
Ministry of Energy (MoEN)— http://www.energy.go.th/
Prime Minister’s Office—www.opm.go.th219

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U N I T E D S T AT E S

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 11.7 trillion (USD 2010 at PPP)in 2012 (EDMC, 2014). In 2012, the US spans 9.8 million square kilometres and had a population of almost
314 million people. The economy’s population has continued to slow down from the 2000 rate of 0.9% to0.7% in 2012 (EDMC, 2014).
The US enjoyed a long economic expansion from 1990 through to 2000 with a growth of 3.5% in realterms, and then started to slow down to a rate of 1.8% from 2000-2012. In 2012, the economy bounced
back with a 2.8% increase in its GDP (EDMC, 2014).
The US is the largest producer and consumer of energy in the world. It is also rich in energy resources.
In 2012, the US had 44.2 billion barrels of proven oil reserves, 9.3 trillion cubic metres of natural gas reservesand 237 billion tonnes of coal reserves (BP, 2014).
Table 1: Key data and economic profile, 2012
Key dataa

Energy reservesb

Area (million sq. km)

9.8

Oil (billion barrels)

44.2

Population (million)314

Gas (billion cubic metres)

9 300

GDP (USD (2010) billion at PPP)
GDP (USD (2010) per capita at PPP)

15 658

Coal (million tonnes)

49 886

Uranium (kilotonnes of U)c

237 295
472

Source: a. (EDMC, 2014); b. (BP, 2014); c. (NEA, 2012) recoverable at a production cost of less than 260 USD per kg.
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 2012 was 2 141 million tonnes of oil equivalent (Mtoe). In
terms of fuel type, more than one-third of supply came from crude oil and petroleum products, 26.0% fromnatural gas, 20.0% coal and the rest from other fuels such as nuclear, hydro, geothermal and other fuels.
Almost 20.0% of the economy’s primary energy requirements in 2012 were from net imports(EDMC, 2014).
The economy’s total primary energy output in 2012 declined by 2.3% percent compared to the 2011
level of 2 191 Mtoe. The decline was brought mainly by the 11.2% decrease of coal production as well asother fuels and oil production by 2.4% and 1.9%, respectively. A substantial reduction in the net imports ofthe economy was likewise recorded in 2012 with an almost 20.0% reduction from the previous year. The
economy has showed constant reduction in import dependency since 2000 with an average of 4.0% decline
over last twelve years. This decline was brought by the increasing crude oil production from North Dakota
and Onshore Texas. Much of the increase in crude oil production is coming from shale and other tight (verylow permeability) formations (EIA, 2013a). The US maintained its position in 2012 as the third-largest crude
oil producer in the world, including natural gas liquids and condensates, with production averaging 8.9
million barrels per day (BP, 2014). Increased production from smaller-volume producing states, such as
Oklahoma, New Mexico, Wyoming, Colorado and Utah, is also contributing to the rise in domestic crude
oil production (EIA, 2013a).
The US primary natural gas supply totalled 596 Mtoe in 2012. While the US natural gas supply has
grown modestly from 1990 to 2000 with an annual growth rate of 0.7%, the primary natural gas supply
including net imports in 2012 surge by 4.7% from the 2011 levels (EDMC, 2014).. In recent years, rapid
production of cheap unconventional gas reserves from tight geological formations has resulted in anabundant supply and low wellhead prices. Relatively low natural gas prices and the substitution of gas forcoal by power producers has resulted in lowering emissions.

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Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)
Indigenous production
Net imports and otherFinal energy consumption (ktoe)

1 806 939 Industry sector
374 880 Transport sector

Power generation (GWh)

246 625 Total

3 946 987

597 390

Thermal

2 656 884

Total PES

2 141 286 Other sectors

587 151Hydro

278 511

Coal

425 057 Total FEC

1 431 166

Nuclear801 129

Oil

771 265

Coal

20 118

Geothermal

210 463Gas

595 704

Oil

746 074

OthersOther

349 260

Gas

296 580

Electricity and other368 393

3 946 987

Source: (EDMC, 2014).

The US held about 4.7% of the world’s natural gas reserves in 2012 (BP, 2014). It transports gas throughan extensive pipeline network with more than 492 384 kilometres of transmission pipeline and 6.1 billion
cubic metres per day of transmission capacity (EIA, 2007). Underground gas storage capacity in the US hasgrown only slightly since the mid-1970s, and the total end-of-year storage volume stood at approximately
59.0% of maximum working gas volume in 2014 (EIA, 2014e).
From 2006, the introduction of horizontal drilling in combination with hydraulic fracturing has enabled
the economic extraction of unconventional gas, largely from shale formations. In particular, US shale gas
production has increased rapidly from about 2.0% of production in 2006 to 39.0% of production in 2012
(EIA, 2013c). Further increases in shale gas production are anticipated, with total production expected toincrease around threefold from 2010 to 2035 and to account for almost half of US gas production. The sizeof unconventional gas reserves, which include shale gas, tight gas and coalbed methane, is still uncertain;
however, the Energy Information Administration (EIA) estimates that technically recoverable
unconventional gas reserves may exceed 33 trillion cubic metres or over 50.0% of total reserves. Interest inliquefied natural gas (LNG) exports has grown with the abundant supplies, and relatively low price comparedto other LNG supplies. Proposals to construct new LNG exporting facilities are facing environmental andregulatory review, although several proposals have now received approval.
The primary energy supply of coal in the US totalled 428 Mtoe in 2012 (EDMC, 2014). The 2012
primary coal production declined considerably by 11.2% over the previous year’s level of 479 Mtoe. US coalreserves are concentrated east of the Mississippi River in Appalachia and in several key western states (EIA,
2012a, 2012c). The U.S. coal production in 2012 fell almost everywhere; specifically, Central Appalachia
decreased significantly by 16.0%, followed by a 9.0% production decline in the Powder River Basins, thetwo key sources for thermal coal of the economy (EIA, 2013a).
In 2012, the US was the fourth largest coal exporter in the world, behind Indonesia, Australia andRussia (EIA, 2013b). In 2012 coal exports were 126.7 million short tonnes or an increase of over 17.0%
from 2011. Coal imports have steadily declined from 38.8 million short tonnes in 2007 to 10.3 million shorttonnes in 2012 (EIA, 2013b). Europe is the largest importer of US coal, accounting for around 50.0% of
net exports (EIA, 2012c).
In 2013, the US produced 4.1 million gigawatt-hours of electricity; of that total, 67.5% came from fossil
fuel plants, 19.4% from nuclear power, and the 13.1% shared by renewable energy and other sources (EIA,2015).
The US generates more nuclear power than any other economy, currently four new nuclear reactors arebeing constructed, and construction of one has been reactivated(NRC, 2013). The Three Mile Island
accident in 1979 raised concerns about nuclear power plant safety, while ad hoc regulatory responses tothose concerns made some new plants very expensive; both factors deterred further expansion. In 2007,
work began again on the partially built Watts Bar 2, where construction had ceased in 1985; commercial
operation of this reactor is expected to begin between 2015 and 2016 (TVA, 2014). In 2013, the averageutilisation rate of the 100 operable commercial nuclear units (down from a peak of 112 units in 1990) roseto over 90.0%, where it has largely remained since (EIA, 2014f). Many nuclear plants have applied to the
Nuclear Regulatory Commission (NRC) for 20-year extensions of their operating licences, to 60 years. Inlate 2014, the NRC had approved licence extensions for 76 nuclear reactor units and had applications foranother 19 extensions under review, while the remaining 5 units had informed the agency of their intention
to seek extensions between 2015 and 2021 (NRC, 2014).

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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 in Vermont andWisconsin cited stiff economic conditions as the reason for their closing, and the other two plants in
California and Florida closed due to structural damage and safety concerns. However, in late 2014, 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 234 Mtoe, or 11.4% of total
primary energy supply, according to the EIA. Production from non-hydro (or new and renewable) sources
increased 8.7% from the previous year, an annual growth rate of 8.4% since 2005 (EIA, 2015a, 2015b).
By consumption of renewable energy type, biomass as a whole represented 49.6% of the total,hydroelectric power 27.5%, geothermal 2.4%, wind 17.2% and solar/photovoltaic 3.3%. There has been aparticularly rapid expansion of wind power, which between 2000 and 2013 recorded a 29.2% average annual
growth rate (EIA, 2015). Government incentives, including subsidies and renewable energy mandates as
discussed below, in addition to cost reductions relative to fossil-fuelled alternatives, spurred the growth ofrenewable energy production.

FINAL ENERGY CONSUMPTION
In 2012, total final energy consumption in the US was 1 431 Mtoe, a decrease of 3.6% from the previous
year. The transport and other sectors accounted more than 40.0% each of the total demand while theremaining share was consumed by the industry sector at 17.0%. In terms of fuel, petroleum accounted morethan 50.0% of the final consumption while electricity and natural gas 26.0 % and 21.0%, respectively and amodest amount from coal (1.0 %) (EDMC, 2014).

ENERGY INTENSITY ANALYSISThe energy intensity of the USA for 2012 has considerably improved across all sectors. Primary intensity in2012 improved by 4.9% from the last year’s primary intensity of 143.85 tonnes of oil equivalent per USD.
Similarly, the final energy demand has decreased in the last year’s energy demand level, which prompted theintensity to decline by 6.2%. Significant improvement in the final energy intensity was mainly due to thedrop in the ‘other’ sector’s intensity by 9.9% in 2012 (Table 3).
Table 3: Energy Intensity Analysis
EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

Change (%)

20122011 vs 2012

Primary Energy

143.9

136.8

-4.9

Final Energy Demand

97.5

91.4

-6.2

Industry

17.2

15.8

-8.2

Transportation

38.7

38.2

-1.4

Others

41.6

37.5

-9.9

Source: (EDMC 2014).
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) are under the auspices of the Department of Energy (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 theeconomy. The Department of Transportation (DOT) also plays an important role as the regulator of vehicle

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fuel economy. 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 of 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 set the rules for energy markets. Since the1970s, several major legislative packages have been introduced to define 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 the FERC greater authority over natural
gas markets (DOE, n.d.). 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, a new comprehensive Energy Policy Act of 2005 (EPAct 2005) 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 2007). 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 are described 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:efficiency in the transportation sector, where more than 70.0% 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 electricvehicles.

In order to improve energy security in the transportation sector EPA and DOT’s National Highway
Transportation Safety Administration (NHTSA) jointly developed vehicle greenhouse gas (GHG) emissions
standards and fuel economy standards to 23.2 kilometres per litre (54.5 miles per gallon) for passenger cars,
light-duty trucks and medium-duty passenger vehicles manufactured in 2025 (MY 2025) (EPA & NHTSA,
2012b)The 2005 EPAct promoted enhanced domestic production of oil by removing some regulatory barriers
and offering 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 from
regulation under the Safe Drinking Water Act of 1974, which cleared an obstacle to the exploitation of tightsand and shale hydrocarbon resources. In this act, Congress also made a clear statement that developmentof unconventional oil resources should be encouraged in order to reduce US dependence on foreign oil
imports (DOE, 2005).
Biofuels represent another avenue for improving US energy security, which has received strong policy
support. Development of vehicles powered by alternative fuels and biofuel production were promoted by
the 2005 EPAct, but in 2007 EISA brought biofuels to the forefront of US energy security policy. EISA
mandated a fivefold increase from previous biofuel use targets by 2022, requiring fuel producers to use aminimum of 136 billion litres (36 billion gallons), up from 42 billion litres (11.1 billion gallons) in 2009. This
included the increase to 79 billion litres (21 billion gallons) in 2022 from 2.3 billion litres (0.6 billion gallons)in 2009 of advanced biofuels, i.e. renewable fuel, other than ethanol derived from corn starch, that has
lifecycle greenhouse gas emissions that are at least 50.0% less than baseline lifecycle GHG emissions. EISA
also stipulates that the production of advanced biofuels is to be encouraged by a grant programme. Most of
the new biofuel is to be produced domestically, and the target includes provisions to reduce the required
volumes if costs are judged too high or supplies are inadequate (CRS, 2007b). Since this law was passed, US
consumption of oil has, in fact, been reduced in recent years causing the biofuel blend ratio in gasoline torise unexpectedly. The current blend ratio is fast approaching 10.0%. Many auto manufactures have said
their warranties will not cover any damage from biofuel blending above this ratio. In response, refineries arepurchasing 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.
The Recovery Act sought to advance the commercialisation of electric vehicles by investing in facilities
that manufacture batteries and other electric vehicle components. The government invested more than
USD 2 billion in nearly 50 different electric vehicle and component manufacturing projects (DOE, 2010a).
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U N I T E D S T AT E SElectric vehicles offer energy security benefits by shifting transportation energy demand from oil toelectricity. The total hybrid-electric vehicle (HEV) sales during 2014 were 452 172 (425 612 cars and 26 560
light trucks), down 8.7% from 2013 sales, but from 2000 electric vehicle sales have gone steadily up (DOE,
2015c).
Coal-fired power plants provide just under half of US electricity. Coal is a domestically abundantresource and thus provides energy security benefits. However, coal’s high CO 2 emissions present a challenge
for US climate policy, which is discussed below.

ENERGY MARKETSIn 2010, US consumers spent an estimated USD 1.2 trillion on energy purchases (EIA, 2012a). The
government plays many roles in this large market, including as an owner of resources, regulator of industry,and supporter of research and development.

UPSTREAM DEVELOPMENTThe Department of Interior’s Bureau of Land Management (BLM) administers over 2.8 million square
kilometres of mineral estate, of which about 180 000 square kilometres is currently leased for oil and gas
development (BLM, 2010). The Bureau of Ocean Energy Management, Regulation and Enforcement(BOEMRE), another office of the Department of Interior, leases another 174 000 square kilometres ofoffshore 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 mineral rights, it is not the sole owner of suchrights. States and individuals also own and lease surface lands and underground mineral rights for energy
extraction (BLM, 2009).
State and federal governments share regulation of upstream development. In some cases, the division
between state and federal responsibility is clear. For example, state oil and gas commissions prevent thewaste of resources and protect public safety in state territory (IOGCC, n.d.). In the federal offshore territory,
offices of the Department of Interior exercise similar responsibilities. But such clear divisions are not always
the case. For example, 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 minimum, upstream activities comply with such federal laws as the Clean Air Act of 1970 and the
Clean Water Act of 1972. In such cases where state and federal regulatory responsibilities overlap,
coordinating the activities of state and federal agencies is an important task (EPA, 2012a).

ELECTRICITY AND GAS MARKETSThe federal government regulates the interstate transmission of electricity and gas, as well as wholesale salesof electricity, under the Federal Energy Regulatory Commission (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 to transmission lines and thereby allowing wholesale customers to meettheir 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. Regionaltransmission organisations and independent system operators administer transmission networks and operate
wholesale markets across a large part of the US and Canada. In other regions, bilateral contracting between
consumer and supplier 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. Most retail customers are served by regulated,investor-owned utilities (69.0%), but public power systems (14.0%) and cooperatives (12.0%) also serve
millions of customers (DOJ et al., 2007). 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 to regulate distribution networks as natural monopolies. Fifteen states now allow
some customers a choice of electric service provider, but efforts to deregulate retail electricity markets
slowed when, in 2000 and 2001, California’s newly deregulated retail market proved vulnerable to abuse,leading some customers’ bills to quickly triple and forcing some distribution utilities into bankruptcy (EIA,
2010a; DOJ et al., 2007).
Natural gas markets are similar to electricity markets, with competitive wholesale markets supplying
federally regulated transmission pipelines and delivering into state regulated distribution networks. The

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Federal Energy Regulatory Commission once set natural gas prices, but wellhead prices were fully
deregulated in 1993.
Now FERC’s pricing activities for natural gas are limited to determining pipeline rates for gas
transmission. DOT’s Pipeline and Hazardous Materials Safety Administration regulates gas transmission
pipelines to ensure they are operated safely. Pricing and the safety of natural gas distribution networks are
regulated by state agencies (FERC, n.d.; EIA, 2009a).

RESEARCH AND DEVELOPMENT
The scope of energy-related research and development (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, energy R&D spending more thantripled. New support for fossil energy, renewable energy, and efficiency absorbed much of the increase.
Though the amount of spending then declined sharply during the 1980s, the broader scope was preserved(Dooley, 2008).
DOE is the lead agency for research and development activities. The DOE funds 21 laboratories andtechnology centres, as well as research conducted at universities across the US. Currently supported researchranges from particle physics to pilot projects for carbon capture and sequestration (DOE, 2010b). Total
government spending for energy-related research and development remained relatively stable at around
USD 3 billion a year (in USD 2005 terms) from the 1990s until 2009 with 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, theRecovery Act was a one-time economic stimulus and R&D spending may soon return to previous levels.
Some US business leaders have argued that to confront the energy challenges that the US faces, thegovernment should more than triple spending on clean energy research and development (AEIC, n.d.)
FISCAL REGIME AND INVESTMENT
US fiscal policy is quite complex, particularly as it relates to the energy sector. This section provides a limited
introduction to the taxation of energy commodities and to the multitude of fiscal incentives that shapeenergy-related investments. Energy producing businesses are taxed like other US corporations, at a
maximum statutory federal rate of 35.0%, while state rates range from 0.0% to 10.0%. However, tax rules
result in 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 are described here.
Royalty payments on the production of oil, gas and coal are paid to the owner of mineral resources,
which is often the government. The US Office of Natural Resources Revenue collected USD 11.9 billion inroyalty payments in 2012 (ONRR, 2012). Downstream, sales of some important energy commodities, suchas gasoline and diesel, are taxed by state and federal governments. The federal tax on gasoline is about
USD 0.049 per litre (18.4 cents per gallon) and on diesel is USD 0.064 per litre (24.4 cents per gallon). 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 go to funding energy efficiency programmes.
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 andproduction tax credits. Investment tax credits allow taxpayers investing in certain qualified energy facilities
to reduce their tax burden by some fraction of the amount invested. Production tax credits similarly reducea 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 investment tax credits 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, 2012). Some of these incentives are described in the following sections onenergy efficiency and renewable energy.
ENERGY EFFICIENCY
Incentives to promote energy efficiency exist at federal, state and local levels. Federal tax credits and loans
support residential efficiency improvements. Taxpayers could claim a tax credit for up to 30.0% of the costof a residential efficiency measure through the end of 2010. Homeowners can also obtain loans from the225

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federal government to finance energy-efficiency measures in new or existing homes (DSIRE, 2012). Muchof the Recovery Act allocation for energy efficiency was distributed through state energy programmes thatprovide 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 programmesthat provide incentives and technical assistance to reduce demand for electricity and natural gas(DSIRE, 2012; US House, 1992).
RENEWABLE ENERGY
In 2013, US cumulative wind energy capacity reached 61 107 megawatts (MW) or approximately 5.3% of
total US electricity generating capacity. The total 2013 wind energy installations were 1 087 MW, and from2007 to 2011 wind installations accounted for roughly 35.0% of all new US electricity generating capacity(AWEA, 2012). Another significant change under the Recovery Act is that new NRE facilities may selecteither the PTC, a 30.0% business energy investment tax credit (ITC) or, for a limited 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, but they are eligible for the ITC. A related
individual tax credit of 30.0% is available for residential solar electric system expenditures without cap, as
are similar tax credits for residential small wind and geothermal systems. Several federal loan and loan
guarantee programmes also exist to encourage the development of renewable energy and other advancedenergy facilities (DSIRE, 2012).
Many state and local governments have in place 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-nine states, District of Columbia, Guam, Puerto Rico, Virgin Islands and N. Mariana Islands
had enacted RPS legislation, with varying degrees of stringency, by the end of 2014.
Other measures have also been introduced to support NRE development, such as generation disclosurerules, mandatory utility green power options, green power purchasing policies and the use of public benefit
funds (DSIRE, 2014).
NUCLEARThe US government has enhanced its support for the nuclear industry through various means, including
legislative and financial ones. For example, the Energy Policy Act 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 apublic–private project to design and construct a pilot Next Generation Nuclear Plant. The Act also
continued support for nuclear energy research and development, and established a loan guarantee
programme intended to improve access to 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 constructionof innovative nuclear energy and front-end nuclear projects in the United States that reduce, avoid, orsequester greenhouse gas emissions’ (DOE, 2014a). In February 2014, DOE issued USD 6.5 billion in loan
guarantees to support the construction of 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 have held responsibility for the development
and promotion of nuclear energy, and the Nuclear Regulatory Commission (NRC) has provided theregulatory oversight of the industry. The federal government is also required to provide a site for thepermanent disposal of high-level radioactive waste, with disposal costs to be paid by nuclear operators.
However, a suitable site remains to be found (NRC, 2011b). The partially completed waste depository facility
in Yucca Mountain, Nevada was recently abandoned and there remains no viable long term storage option
for nuclear waste. The US government maintains the financial burden of storing spent fuel and currently
compensate utilities for storing their nuclear waste on-site. However, the U.S. Court of Appeals for theDistrict of Columbia Circuit’s ruling in June 2012 banned the NRC from issuing new reactor licenses orrenewals until it sufficiently assessed the risk of storing spent radioactive 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).
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The United States has the world’s largest nuclear energy sector consisting of 100 operating reactors
generating 789 017 million kW of electricity in 2013 and 528 639 million kW of electricity between January
and August 2014 (EIA, 2014b), as well as five under-construction reactors. The NRC has the authority toissue 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 already undergone lifetime extension
or need to go through this process in this decade or the next one. After about two years of deliberation asrequested 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 in compliance with thementioned court ruling. Consequently, it may now legally resume issuing license renewals and also new
operating licenses. In fact, the NRC resumed its issuance activity in October 2014 when it renewed theoperating licenses for Limerick Generating Station Units 1 and 2 located in northwest 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 74 of the 100 operating American reactors enabling themto operate for a total period of 60 years. Currently, the NRC is reviewing license renewal applications for “anadditional 17 reactors while expecting to receive seven more applications in the next few years” (EIA, 2014c).
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, 2014c). In
August 2014, the NRC determined that the “existing license renewal regulations were sufficient to support
the SLR process” backed by the May 2014 findings of the NRC's Advisory Committee on Reactor Safeguards(EIA, 2014c).
The March 2011 accident at Japan’s Fukushima Daiichi Nuclear Power Plant prompted thestrengthening of the American safety regulations and thus operating standards of the nuclear power plants
to avoid similar accidents in the United States. Towards this end, the NRC and the US nuclear industry havebeen working together. 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, 2014d). One of the subsequent major activities was the NRC’s
comprehensive review of its own processes and regulations leading to its Near-Term Task Force’s releaseof a report, namely, Recommendations for Enhancing Reactor Safety in the 21 st Century. They consisted of 12
recommendations covering short- and long-term actions followed by the NRC’s issuing three orders withrespect to the short-term recommendations in March 2012. The orders required the implementation of thefollowing 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, 2014d):
All boiling-water reactors (BWRs) with Mark I and II containment systems must have reliable hardened
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 fuel poolsin the event of an emergency; and

Nuclear power plants must be capable of responding to multiple simultaneous events and ensuring thatreactors and spent fuel pools remain cooled. The order specifies a three-phase approach involving useof installed on-site resources, use of portable on-site equipment and indefinite use of off-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 tomitigate 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, 2014d).

CLIMATE CHANGE
The US pledged to reduce economy-wide GHG emissions in the range of 17.0% by 2020 from 2005 underthe 2009 Copenhagen Accord. However, this pledge also states that the final US target will be determinedby domestic legislation (Department of State, 2010). To date, no climate legislation has been passed by
Congress, so an economy-wide emissions goal has yet to be conclusively defined. Nonetheless, theadministration has declared its commitment to reducing GHG emissions, and state and local governments
have developed their own goals and action plans. There are several state and regional initiatives toincorporate a price for carbon emissions including plans implemented in California and the Northeast.

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An important U.S.-China Joint Announcement on Climate Change made in late 2014 will target an
economy-wide target of reducing US GHG emissions by 26.0-28.0% below its 2005 level in 2025
(Whitehouse, 2014).

GREENHOUSE GAS ENDANGERMENT FINDING
There are two ways that GHGs may be regulated at the federal level in the US. First, Congress may passlegislation to control GHG emissions. Alternatively, the EPA may issue a ruling (an ‘endangerment finding’)that carbon dioxide 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, a2007 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 or not to issue an endangerment
finding. In December 2009, the EPA issued an endangerment finding, which gave the EPA the authority toissue rules to limit GHG emissions. EPA has used this authority to move forward vehicle emission standards
and to define GHG permitting requirements for large CO2 emitters (EPA, 2012b). 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 US energy developments in future.
Principally, the EPA is proposing to limit CO 2 emissions in the power sector. The proposed standard
restricts CO2 emissions to a limit of 454 kilograms (1000 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 is also investigating CO2 emission limits for existing generating
units, as of June 2014 a proposed rule was issued, the final rule is expected in summer 2015. The emission
regulation is aimed at limiting climate change by enforcing the use of modern and more efficient fossil fuelgeneration technologies (EPA, 2012c). The carbon restriction will essentially require new coal plants tooperate using the latest high efficiency technology, employ biomass co-firing fuels or utilise carbon
sequestration.
In addition to GHG emissions limits, the EPA has enforced emission standards on mercury and toxic
pollutants in 2012. The strict emission standards will be fully enforced by 2015. This will have a major impact
on reducing toxic emissions from coal, primarily in the electricity sector (EPA, 2012b). The new standards
will require expensive technological retrofits to existing facilities and will affect almost half the coal
generating capacity. Most of the affected coal facilities are over 40 years old and the new standards are likely
to result in extensive capacity retirements, which may exceed 50 GW.

STATE AND CITY LEVEL CLIMATE CHANGE INITIATIVESIn the absence of an economy-wide plan to reduce US GHG emissions, a number of regional, state and citylevel initiatives have been formed and were active in 2010.

In California, the Global Warming Solutions Act (AB 32) was signed into law in September
2007. This law builds upon the 2000 California Climate Action Registry and the 2005 Executive
Order S-3-05, in which it was noted that the state was particularly vulnerable to the impact of global
warming, citing impacts to ‘water supply, 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 programme in the period
2012–2020 (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, focusing on reducing carbon dioxide (CO2)emissions from the power sector by 45.0% from 2005 levels by 2020. The first permit auction for the capand-trade system was conducted 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 10.0% below 1990 levels by 2020 (NEG & ECP, 2008).
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 theregulatory or market mechanisms that might be used to achieve them (MGA, 2007).
A host of other regional initiatives focused on climate change or clean energy have now also been
formed across the US with Mexican states and Canadian provinces, including the Western Governors
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Association Clean and Diversified Energy Initiative, the Southwest Climate Change Initiative, the West Coast
Governors’ Global Warming Initiative, and the Western Climate Initiative (six states and two Canadianprovinces, aiming for 15.0% below 2005 levels by 2020) (WCI, 2007). These regional initiatives represent
attempts to actively collaborate on goal setting and the development of action plans. Except for the RGGIin the north-east, all the initiatives are still in the design phase.
Municipal governments have undertaken other GHG initiatives, notably the US Mayors’ Climate
Protection Agreement, launched in Seattle in 2005. By December 2009, there were 1016 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 meet or beat Kyoto Protocol
targets (USCM, 2009).

FUTUREGEN INITIATIVE
FutureGen is a public–private partnership undertaken by the US DOE and the FutureGen Industrial
Alliance that focuses on the sequestration of carbon dioxide from coal-fired power plants. When it was firstannounced in 2003, its aim was to build a single smaller-than-commercial scale demonstration of a nearzero emissions power plant that could produce electricity and hydrogen from coal and serve as a laboratory
for further R&D. Construction was scheduled to begin in 2009 on a plant using integrated gasification
combined cycle technology. The initiative was restructured to focus on a large-scale commercial
demonstration. The preferred site is a recently retired coal plant in Illinois State owned by Ameren Energy
Resources. In January 2014, DOE issued a Record of Decision (ROD) to provide financial assistance for
the FutureGen 2.0 Project of approximately $1 billion of cost-shared funding, mainly appropriated underthe ARRA. This decision is to implement the proposed action in the Final Environmental Impact Statement(EIS), evaluating the potential environmental impacts associated with construction and operation of the
FutureGen 2.0 Project (DOE, 2014d).

VEHICLE EMISSION STANDARDSIn 2007, EISA mandated a 40.0% increase in combined car and light truck fleet fuel economy (CAFE)
standards by 2020, to reach 14.9 kilometres per litre (35 miles per gallon), and required further study into
commercial vehicle fuel economy (CRS, 2007b). 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 and in cooperation with the State of California, to harmonise economy-wide fuel standards to23.2 kilometres per litre (54.5 miles per gallon) for cars and light-duty trucks by 2025. The supportive
automakers together account for over 90.0% of all vehicles sold in the US (NHTSA, 2011). In addition, the
EPA and NHTSA recently proposed the first fuel economy standard for heavy-duty vehicles(NHTSA, 2011). In the absence of standards, the average fuel economy of heavy-duty trucks has improved,in absolute terms, by 16.0% in the past four decades from 2.3 kilometres per litre (5.5 miles per gallon) in
1970 to 2.7 kilometres per litre (6.4 miles per gallon) in 2008 (EIA, 2012a). The newly proposed standards
are expected to reduce the fuel consumption of heavy-duty vehicles by 10.0–20.0% between 2014 and 2018,
depending on the heavy vehicle type. Based on projected fuel savings, 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 have several loopholes which may inhibit their effectiveness. The chief concern isthe 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 may increase in market share and reduce real fuel efficiency improvements.
A published study suggests average vehicle sizes, particularly for light trucks, may increase between 2.0%
and 32.0% under the new standards. This would result in a net reduction in the average fuel economy ofbetween 1 and 4 miles per gallon (between 0.4 and 1.7 kilometres 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 rate lower
than anticipated.

AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009
PROGRAMMESAs of late 2014, USD 30.2 billion was authorised in funding for energy and environment under the ARRA.
Major investment programmes include the Weatherisation Assistance Program, which invests in energy
efficiency improvements for the homes of low-income families. Other notable projects include thedevelopment of electric vehicle, smart grid technology and greater support for renewable energy. ARRA
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also contains tax credits for the purchase of alternatively fuelled vehicles. The EIA estimated that ARRA
funding would achieve 50.0% more generation of renewable electricity (excluding hydro) by 2012, as well as
efficiency measures that will reduce residential and commercial energy expenditures by 2.6% in 2020. ARRA
is also expected to result in the development of about 1 gigawatt of coal fired generating capacity with carbon
capture and sequestration by the end of 2018 (EIA, 2014g, 2014h).
NOTA BLE EN E RG Y D EV EL O PM E NT S
CLIMATE ACTION PLAN
On 25 June 2013, President Obama announced the Climate Action Plan, a plan for tackling climate change.
The President’s Climate Action Plan consists of wide variety of executive actions and has three key pillars
as follows:

Cut Carbon Pollution in America: In 2012, even as the economy continued to grow, the U.S. carbon
emissions fell to the lowest level in two decades. So, in order to build on this progress, the Obama
Administration is putting in place tough new rules to cut carbon pollution.

Prepare the United States for the Impacts of Climate Change: Hand in hand in taking new steps
to reduce carbon pollution, the Plan also includes preparation for the impacts of the changing climatethat are already being felt across the economy. Moving forward, the Obama Administration will help
state and local governments strengthen the roads, bridges, and shorelines to better protect people’s
homes, businesses and way of life from severe weather.



Lead International Efforts to Combat Global Climate Change and Prepare for its Impacts: It is
understood that no country is immune from the impacts of climate change and no country can meetthis challenge alone. Hence, it is imperative for the United States to couple action at home withleadership internationally. America 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 through the international negotiations(Whitehouse, 2013)
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 Nation’s Security. The firstever comprehensive energy review will focus on energy infrastructure such as the transmission, storage anddistribution infrastructure. It will also identify the threats, risks and opportunities for energy and climate
security, which will enable the Federal government to develop concrete integrated actions to implement
energy and environmental policy goals (DOE, 2014b).
BILATERAL COOPERATION WITH CHINA
The United States of America and the People’s Republic of China have a critical role to play in combating
global climate change, one of the greatest threats facing humanity. The seriousness of the challenge calls
upon the two sides to work constructively together for the common good. Hence on 14 November 2014,
the US and China reaffirmed the importance of strengthening bilateral cooperation on climate change andwill work together, and with other countries, to adopt a protocol, another legal instrument or an agreed
outcome with legal force under the Convention applicable to all Parties at the United Nations Climate
Conference in Paris in 2015 (Whitehouse, 2014).

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VIET NAM

VIET NAM
I N T ROD U C T I ON

Viet Nam is located in South-East Asia, shares borders with Cambodia and Laos to the west and China to
the north. The economy has an area of 333 972 square kilometres and a marine exclusive economic zone
stretching 200 nautical miles from its 3 260 kilometre coastline. In 2012, its population was 88.8 million
people, of which 32.0% lived in cities and 68.0% in rural areas (GSO, 2014).
While maintaining the socio-politic stability, building an open socialist-oriented market economy andprogressively industrialising the country, Viet Nam’s economic growth was 7.1% for GDP and 5.6% forincome per capita per annum on average over 1990-2011. However, since 2008, the pace of the economy’s
development has exhibited some slowdown compared to the previous period. This is a result of the global
context, such as volatile energy prices, a prolonged financial crisis, recessions, and from intrinsic
shortcomings in the economy structure. In 2012, Viet Nam recorded a GDP of USD 427.7 billion (a growthof 5.3% from 2011 level) and an income per capita of USD 4 818, both at the 2010 price based on PPP(EDMC, 2014). In September 2012, to achieve the goal of turning Viet Nam into a modern industrialised
country by 2020 with further international integration, the government of Viet Nam has established andissued the National Strategy on Green Growth to 2020 with a vision to 2050 (PMVN, 2012a) and in February
2013 the Socio-Economic Development Master Plan up to 2020 (PMVN, 2013a). Accordingly, Viet Nam
will accelerate the economy restructure in association with the growth model renovation towards
guaranteeing growth quality and improving the economy’s efficiency and competitiveness during the periodof 2013-20.
Energy is a key driving sector for Viet Nam’s economic development, contributing to the country’s
industrialisation through attracting foreign investment and export earnings. Endowed with diverse fossil
energy resources such as oil, gas and coal, as well as renewable sources, Viet Nam has been a net energy
exporter since 1990, exporting mainly of crude oil and coal, and being self-sufficient in natural gas. As ofend 2012, Viet Nam’s proved fossil energy reserves consisted of 4.4 billion barrels of oil, 600 billion cubic
metres (bcm) of gas, 150 million tons (Mt) of coal (BP, 2014). Renewable energy resources suitable for thedevelopment include hydro, solar, biomass, wind and geothermal. The current economic and technicalpotential of hydro is estimated about 20 000 MW (excluding about 4 000 MW suitable for developing smallhydropower with less than 30 MW capacity per site). Potential power capacity for deployment within the
coming 15 years from wind, biomass and geothermal are about 2000 MW, 800 MW and 300–400 MW
respectively (IE, 2011).
Table 1: Key data and economic profile, 2012
Key data

Energy reserves

Area (sq. km)a

Oil (billion barrels)d

4.4

88.8

Gas (billion cubic metres)d

600

427.7

Coal (million tonnes)d

150

4 817

Uranium (kilotonnes U)e

1.0

333 972

Population (million)b
GDP (USD (2010) billion at PPP)c
GDP (USD (2010) per capita at PPP)c

Source: a. (GSO, 2014); b. (WB, 2014); c. (EDMC, 2014); d. Proven reserves (BP, 2014); e. proven reserves ofuranium (WEC, 2010).
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 2012 was 44 347 kilotonnes of oil equivalent (ktoe), which
is a slight increase of 1.9% from the 2011 level and double compared to the 2000 level (EDMC, 2014) 2. Byenergy source, 35.6% of supply came from coal, 35.3% from oil, 18.6% from natural gas and 10.5% fromother sources. During 2005-12, primary electricity (including hydropower as the major source next toelectricity import in a tiny share of less than 5.0%) developed at the fastest rate, averaging 17.7% per annum,

2 EDMC excludes non-commercial energy sources such as biomass, wood waste etc.

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much higher than the average growth of 8.1% per annum of TPES. However, fossil fuels remained the
major primary energy sources in absolute quantity and coal passed oil in 2012 for the first time to take thefirst position among the primary energy sources, reflecting the government policy since 2007 to increase
coal power generation.

COAL
Viet Nam’s coal production and export had an average annual growth rate of 20.9% and 39.4%, respectively,
during 2000-07 and then slowed down at average -0.1% and -11.1% per year during 2008-12, reflectingchanges in government policy prioritising coal conservation for domestic uses rather than boosting exports
for generating foreign currencies. In 2012, Viet Nam produced about 23 734 ktoe of anthracite and semianthracite coals, which is 9.1% less than what it produced in 2011 but about the same level as that produced
in 2007. With increasing domestic demand for coal, coal export has steadily declined to 8 521 ktoe in 2012,
about 36.0% of the country’s production and roughly half of its export in 2007.
Viet Nam has about 48.7 billion tons as of 2010 in estimated potential coal resources (PMVN, 2012b).
The sub-bituminous-rich coal basin of Red River Delta (in the provinces of Thai Binh, Hung Yen and Nam
Dinh) accounts for 81.0%. The anthracite-rich coal basin in the north-east (in the provinces of Quang Ninh,
Bac Giang and Hai Duong) accounts for a share of 18.0%. And the share of other mines in the provincesof Hai Phong, Thai Nguyen, Lang Son, Nghe An, and Quang Nam account for about 7.0%. Peat coal in the
Mekong delta is about 1.0%. Until now, Viet Nam’s domestic coal has produced and supplied mainly from
opencast and underground mines in the Quang Ninh province. Vinacomin is the dominant coal producer
in Viet Nam with output accounting for about 95.0% of the Viet Nam total coal production. Exploration
activities in the Red River Delta coal basin is still preliminary, and given its characteristics of complex
geological conditions and as a sensitive environmental and economic area, the exploitation of coal resourcesin this basin is forecasted to take place only beyond 2020. From 2020, Viet Nam will need to rely oninternational cooperation and foreign investments in order to effectively and sustainably develop theseresources.

OIL
Oil reserves are mainly offshore and in the southern part of Viet Nam. Active and successful offshore
exploration since 2011 increased the number of oil reserves. Crude oil production grew 9.8% from 15 959
ktoe in 2011 to 17 518 ktoe in 2012 (16.3% down from a peak of 20 940 ktoe in 2004), of which 55.0% wasexported. The Cuu Long basin in southern Viet Nam has been the primary area for oil production. As ofthe end of 2013, there were 23 producing oil fields in Viet Nam (PVN, 2014). According to PVN’s forecast
and planning, oil production will be about 16-18 Mt/year until 2022 and then will decline.
Viet Nam is a net crude oil exporter but net importer of petroleum products. Petroleum products
imports have shown a downward trend since 2009 as the first refinery in Viet Nam, the 140 000 bbl per day
Dung Quat refinery, came on operation over that period. However, to meet the increasing demand for
petroleum products in the economy, imported petroleum products continue to account for the majority part
(9 109 ktoe or 58.0%) of Viet Nam’s total primary oil supply, which was 15,643 ktoe in 2012. According to
the government’s existing master plan for refinery development up to 2025, the government will build four
new refinery construction projects, the Dung Quat expansion, Nghi Son, Vung Ro, and Long Son. As ofend 2014, one new project, the Nhon Hoi refinery of PTT, is also under consideration. This expansion
expects to increase the Viet Nam’s refining capacity to 25 Mt by 2020 and 45-58 Mt by 2025.

NATURAL GAS
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 shore in 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 2012, 13 oil and gas fields produced an annual natural gas supply of 9.4 bcm, raising 9.2% comparedto the 2011 level, and translating to an annual average growth of 8.6% during 2005-12 (PVN, 2014). Growthin the electricity, fertiliser and petrochemical industries have driven demand for natural gas.

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Since 2007 foreign investment increased and has led to greater exploration for natural gas, significantly
increasing Viet Nam’s proved natural gas reserves. In 2012, natural gas reserves increased from 6.8 Tcf in2011 to 24.7 Tcf in 2012, according to Oil and Gas Journal.

POWER GENERATION
In 2012, with a total installed power capacity of nearly 27.5 GW (VNEEP, 2013), Viet Nam produced 117
094 GWh (or 10 114 ktoe), growing at an annual rate of 13.2% from its 2011 level, and 4.4 fold the outputs
in 2000. Of this total electricity output, 45.0% came from hydropower plants and 55.0% from thermal power
plant (EDMC, 2014). During 2008-12, according to Viet Nam’s energy statistics, the installed hydropower
capacity doubled from 6.0 GW to 12.6 GW, reflecting an average growth of 18.0% per annum, higher thanthat for the overall thermal power plants, which was at 12.0% per annum. As a result, hydropower’s sharein Viet Nam’s total installed capacity increased significantly from 38.0% in 2008 to 48.0% in 2012. Among
thermal power sources, gas-fired power plants’ contribution remained the biggest in terms of capacity inabsolute value (7.7 GW in 2012); however, coal-fired power plants recorded the fastest pace of growth indevelopment, averaging 19.0% per annum from 2008 through 2012. With a total capacity reached 4.9 GW,
coal power’s share increased by 4.0% to 19.0% in 2012. Growing deployment of hydropower and coal power
led to relative reductions in gas and oil power plants’ role in Viet Nam’s electricity system. Gas power plants
experienced a sharp decline in its share from the record level of 41.0% in 2008 to 29.0% in 2012, and from
6.0% to 5.0% for share of oil power plants over the same period.
In order to optimise the electricity supply and cost-effectiveness to all regions in the country, Viet Nam
has also relied on power sources from biomass and electricity imports since 2004 from neighbouring
economies and countries such as China and Laos. The participation of these sources were, however, still
very marginal in the economy’s power system over 2008-12.
Table 2: Energy supply and consumption, 2012
Primary energy supply (ktoe)

Final energy consumption (ktoe)

Power generation (GWh)

Indigenous production

54 046 Industry sector

16 106 Total

117 094

Net imports and other-8 059 Transport sector

10 701

Thermal

64 289Total PES

44 347 Other sectors

8 271

Hydro

52 805Coal

15 802 Total FEC

35 078

Nuclear–Oil

15 643

Coal

9 678

Geothermal

–

Gas

8 253

Oil

14 896

Others

Other

4 648

Gas

1 438

Electricity and other

9 065

507

Source: (EDMC, 2014)

FINAL ENERGY CONSUMPTION
In 2012, Viet Nam’s total commercial final energy consumption (TFEC) was 35 078 ktoe, up 2.2% from2011. By fuel source, oil contributed the largest share (42.5%), followed by coal (27.6%), electricity andothers (25.8%) and gas (4.1%). Between 2008 and 2012, consumption of coal and oil continued to beconstrained to low growths of 4.0% per year and 1.9% per year in average; by contrast, gas and electricity
grew rapidly, at an average annual growth rate of 27.0% and 11.6%, respectively.
Industry is an important driving sector in GDP growth and it had the biggest final energy demand at 46.0%
of TFEC. This sector consumed mainly coal at 52.0%, then electricity 30.0%, petroleum products 10.0%,
and natural gas 9.0%. The transport sector was the second largest energy-consuming sector accounting for30.0% of TFEC and remained the main consumer of petroleum products at 72.0% of the economy’s totalrequirement. The other sector’s (residential, agricultural and commercial) consumption represented 24.0%
of TFEC. In this sector, electricity accounted for 52.0%, oil 31.0%, and coal 17.0%. Demand on electricity
grew fast in the residential sector, reflecting the improvement of household income, which brings about anincrease in electric appliance use, and of power supply quality.

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ENERGY INTENSITY ANALYSIS
In 2012, Viet Nam’s energy intensity was 103.7 tonnes of oil equivalent per USD million GDP (PPP), which
is a decrease of 3.2% from 107 tonnes of oil equivalent per USD million GDP in 2011, and almost at thesame level as in 2008.
In 2012, encouraging improvements in energy efficiency continued to be observed in all sectors. The
transport sector recorded the fastest decline in energy intensity, at 6.0% in 2012 from its level of 26.6 tonnesof oil equivalent per USD million GDP in 2011. The industry sector, although with the highest level ofenergy intensity of 37.7 tonnes of oil equivalent per USD million GDP in 2012, has attained a reduction of
1.8% compared to the previous year. Other sectors’ energy intensity was the lowest, at 19.3 tonnes of oil
equivalent per USD million GDP in 2012, which is a reduction of 1.5% from 2011 level.
Table 3: Energy Intensity Analysis, 2012
EnergyEnergy Intensity (tonnes of oil
equivalent per million USD)
2011

2012

Change (%)
2011 vs 2012

Primary Energy

107.1

103.7

-3.2

Final Energy Demand

84.6

82.0

-3.1

Industry

38.4

37.7

-1.8

Transportation

26.6

25.0

-6.0

Others

19.6

19.3

-1.5

Source: (EDMC, 2014)
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:

Viet Nam Oil and Gas Development Strategy to 2015 with orientation to 2025 (PMVN, 2006a);

Viet Nam Gas Development Master Plan for the period to 2015 with orientation to 2025, also known
as, GMP2011 in brief (PMVN, 2011b);

Viet Nam Power Development Master Plan for the period 2010-2020 with perspective to 2030, also
known as, PDP7 (PMVN, 2011c);Viet Nam Coal Development Master Plan to 2020 with perspective to 2030 (PMVN, 2012b).

Below is the summary of some main targets for the energy development in Viet Nam for the next 1015 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 Mtoe in 2020 and 310–320 Mtoe
in 2050;Ensuring the phased development of refineries to meet domestic demand for petroleum products, andincreasing 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 in the total commercial primary energy supply of 5.0% in 2025
and 11.0% in 2050;

Completing the rural electrification program for rural and mountainous areas, and increasing the
proportion of rural households with access to electricity to 100.0% in 2020;

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

Changing the electricity, coal and oil–gas sectors to operate in competitive markets with state regulation;
establishing a competitive electricity retail market in the period after 2022; and by 2015 for coal andpetroleum products markets; and

Carefully reviewing safety issues and actively preparing the conditions for putting the first unit of a
nuclear power plant into operation during the 2020-25 period, and then gradually expanding the roleof nuclear power in the economy’s energy 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 draft laws, policies,
development strategies, master plans, economy-wide target programs, technical-economic program, andimportant projects for all energy sectors. It submits them to the Government, 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, 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 MOIT, the General Directorate of Energy (GDE) and the Energy Regulatory Authority ofVietnam (ERAV) are two key advisory and executive units, assisting MOIT’s Minister with the managementof the energy sectors.
On 25 October 2011 the PMVN’s 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 (inaccordance to Provision 66 of Electricity Law 2004) and the PMVN’s Decision 153/2008/QD-TTg dated
28 November 2008 established the ERAV. It specialises in implementing regulatory activities in theelectricity sector in order to ensure a safe and high-quality supply of electricity for the economy. It also
fosters the economical and efficient consumption of electricity and upholds the equity and transparency inthe sector in compliance with the law. ERAV’s concrete tasks include:Implementing regulatory activities relating to electricity market and tariff (including approving theTermed 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

Doing inspections for electricity activities.

Viet Nam Oil and Gas Group (Petrovietnam, or PVN), Viet Nam National Petroleum Group(Petrolimex), Viet Nam Electricity (EVN), Viet Nam National Coal and Mineral Industries Holding
Corporation Limited (Vinacomin) are the leading state-owned enterprises (SOEs) in energy industries inViet Nam. They actively contribute to formulating and implementing development strategies, master plans
and annual plans issued by the Government in energy sectors. The government restructured the SOEs
gradually to operate on a commercial basis. PVN still participates in some regulatory activities relating to oiland gas exploration and exploitation, and gas distribution.

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 the regional energy systems;

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

Expanding stockpiles of petroleum products; andCombining energy security with assurance of defence and security.

To lessen dependency on oil product imports and to ensure energy security, the government has
implemented the following detailed policies and measures:Strengthen domestic energy supply capacity through legislative reforms (especially regarding price,fiscal systems, equity among enterprises forms, information transparency) and the expansion of theinfrastructure;

Apply preferential policies for financing and expanding international cooperation to strengthen the
exploration and development of indigenous resources, thereby increasing reserves and the exploitabilityof 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 MARKETPOWER SECTOR RESTRUCTURE
The Government of Viet Nam established a competitive power market as part of the long-term development
strategy of electricity sector. The Electricity Law of December 2004 (effective from 01 July 2005 andamended on 20 November 2012) outlines the major principles for establishing the power market inViet Nam. The scheme and conditions for the power market are detailed in the PMVN’s Decision
26/2006/QD-TTg dated 26 January 2006 (hereinafter Road Map) and revised by PMVN’s Decision
63/2013/QD-TTg dated 08 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.

The application of the market is a means for creating a new dynamic in Viet Nam’s power sector. It
aims to reinforce the effectiveness of production and business activities within the electricity sector, facilitate
the decrease of selling electricity prices, and enhance the transparency and efficiency in power generationand distribution activities to ensure the robust development of the electricity sector over time.
On 1 July 2011, Viet Nam’s competitive generation power market launched its pilot operation andcommenced full operation on 1 July 2012. Additional enacted regulations complement the road map. These
cover licensing and technical concerns, market rules, tariffs and contract regulation. As a result, by the endof 2014, there were 55 power plants with a total capacity of 12.82 GW directly participating in sellingelectricity on the spot market. Those 55 power plants constitute 40.0% of total capacity of the power system
and about 52 power plants are yet to participate. They include hydropower, ‘build-operate-transfer’ (‘BOT’),‘build-operate-own’ (BOO) and some gas-fired power plants in the south-west region with a total capacityof over 18 GW or 60.0% of the total capacity of the power system. The total installed capacity of the plants
directly involved in competitive electricity market is likely to increase in the coming years.
MOIT’s Circular 30/2014/TT-BCT dated 02 October 2014, requires power generating companies
involved in the competitive market, certain payment settlements principle. Contract coverage of not higher
than 95.0%, applies in the first year of the electricity market, which is gradually decreased in the following
years to not lower than 60.0%. For example:


240

From 01 July 2012 to 31 Dec 2012, contract coverage applied to both hydro power plant and thermal
power plant was 95.0%;

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

From 01 January 2013 to 31 March 2013, contract coverage applied to both hydro power plants andthermal power plants was 90.0%; andFrom 01 April 2013 to now, the contract coverage applied with reservoir more than two days is 80.0%,
and for hydro power plants with reservoir less than two days as well as thermal power plants is 90.0%.

As part of the electricity sector reform, EVN has been corporatising member enterprises since the early
2000s. So 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 Corporation was established after merging eleven power companies who are
eligible customers in Viet Nam Competitive Wholesale Power Market (VWEM); and

In 2012, EVN established three Generation Companies (GENCOs) including GENCO 1, 2 and 3.

In addition, the Electricity Power Trading Company, which is the ‘Single Buyer’ in the current power
market, and the National Load Dispatch Centre, which manages the spot market’s transactions, still operate
as branches 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), remain under the management of EVN. EVN
has a strong position in the competitive generation market as the biggest player.
In 2013, Viet Nam restructured the power generating market as follows (NLDC, 2014):


EVN’s power plants accounted for 63.0% of the total installed capacity; EVN’s ownership was 26.0%
and EVN’s joint stocks 37.0%;

PVN’s power plants accounted for 11.0%;Foreign investors’ power plants accounted for 8.0%;

Vinacomin’s power plants accounted for 6.0%; andVarious other local investors’ power plants accounted for 12.0%.

According to the Roadmap, Viet Nam is preparing Competitive Wholesale Power Market. On 22 July
2014, Minister of MOIT issued the Decision 6463/2014/Q-BCT on approval of the Conceptual Design of
the Vietnam Wholesale Electricity Market of Vietnam.

TARIFFSElectricity prices are in accordance with the market mechanism 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 in Viet Nam is calculated annually by MOIT and is based on:the audited costs;

the generation, transmission, distribution sectors’ investors’ reasonable profits; andthe costs of regulating, managing and supporting services in the electricity system.

The baseline is threshold for electricity retail tariff adjustments. Adjustments occur following changes
in fundamental costs such as fuel cost, exchange rates, and generated capacity. Any changes occur within
the tariff scope 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 are allowed to fluctuate in the range from VND 1,437/kWh (USD
6.8 cents) to VND 1 835/kWh (USD 8.7 cents). According to the PMVN’s decision No. 69/2013/QDTTg dated 19 November 2013 (effective from 1 January 2014), EVN is allowed to increase retail tariffs onlywhen:

the fundamental costs change from 7.0% to under 10.0%;

the Electricity Price Stabilisation Fund has been used; andMOIT, through consultation with the Ministry of Finance (MOF), provides an endorsement.

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Any tariff increase outside of the approved tariff scope and in cases of cost fluctuation of 10.0% ormore 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 othermeasures stipulated in legislations where 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 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. In
operation from 2009 by the Binh Son Refinery Company (BSR), it is a PVN’s 100.0%-owned 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 Ministry of Industry and Trade, the Ministry of Planning andInvestment (MPI) and the Ministry of Finance (MOF), controls the PEF market. MOIT administers allenterprises participating in the market, especially refineries, importer-wholesale enterprises, and thedevelopment of petroleum trading infrastructures (import terminal, strategic stockpiles, commercial
stockpiles, and oil products pipelines) in order to ensure the supply of PEF for the economy. Annually,
MOIT selects qualified enterprises to implement PEF imports, allocates the import quota 3 to theseenterprises based on the MPI’s forecast of total PEF demand for the economy, and approves their importingand production plans. MOIT manages the development of refineries, oil trading infrastructure according to
the Master Plans approved by the Prime Minister. MOF manages all fiscal and economic issues, including
tax rates, retail prices and the Petroleum Price Stabilisation Fund.
As of June 2013, there are 17 wholesale enterprises in the domestic PEF market, of which Petrolimex
is the leading state owned enterprise with a market share of 48.0%, PV Oil has 17.0% (PV Oil also distributes
BSR’s output products), and the remaining 35.0% is from 15 other companies. Fourteen of the 17 wholesale
enterprises were authorised to import by MOIT in 2013. The list of importers can change every year
depending on each enterprise’s business performance, and whether they achieved the import quota of theprevious year. In general, three state-owned enterprises namely Petrolimex, PV Oil and Saigon Petro, holdthe biggest quotas, and together they can make up to nearly 80.0% of 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 term of quantity and range of products. Foreign investors are
yet to participate in PEF trading in domestic market.
In term of the retail market, Viet Nam has more than 12 000 petrol stations as of 2013. State-owned
enterprises financed 30.0% of these stations and private investors financed 70.0%. The government isplanning to increase the number of fuelling stations to 18 000 by 2020.
In September 2014, the government issued a new decree on PEF business, which came into effect on
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 for importer-wholesale enterprises andrefineries is that they must ensure a 30-day minimum stockpile equivalent available according to their levelof supply and product structure. The average daily sales in the domestic market during the previous year
determines the stockpile level. This includes stockpiles for both the economy’s energy security andcommercial needs.
From 2009, the government regulates retail PEF prices based on the approval of a baseline for theimporter-wholesale enterprises’ selling price. The base price is composed of a number of price elements
including: CIF importing price of importers; government taxes and levies (import tax, excise tax, VAT,

3 The PEF import quota is the minimum annual amount of petroleum products that an authorised enterprise can import.

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environment tax); business expenses norm; deductions for the Petroleum Price Stabilisation Fund; and profit
norm.
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 the case of raising prices, importer-wholesale
enterprises are allowed to decide the adjustments equivalent to changes of their costs up to 7.0%, after
having informed (in case of a change less than 3.0%) or received guidelines from MOIT and MOF (in caseof a change above 3.0% to 7.0%). The Prime Minister decides on the adjustments when they increase morethan 7.0%. Intervals between the two consecutive price adjustments are set at a minimum of 15 days in thecase of increasing prices, and a maximum 15 days in the case 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 gas market. According to the Price Law, gas prices are not subject
to government regulation. All upstream sellers and downstream buyers are free to negotiate the price andother terms in the Gas Purchase and Supply Agreement (GPSA) with PVN and PVGas. The gas priceformulas and levels are set with consideration to their competitiveness against alternative fuels. This ensuresa reasonable profit margin for investors in related upstream and midstream gas projects. PVN submits
GSPA, including price formula and level, to authorised organisations and the Prime Minister for approval
before these GSPA come into effect. PVGas is responsible for planning, developing and operating gas
infrastructure projects to ensure a safe and reliable natural gas supply and support gas exploration andproduction in Viet Nam.

COAL MARKET
Vinacomin’s production and sales account for 95.0% of the total market in Viet Nam. Recently, the NorthEast Coal Corporation separated from Vinacomin to become an independent company and operate underthe management of the Ministry of Defence. In addition, PVN established the PV Power Coal, which is incharge of coal imports, trading, and ensuring coal supply to 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 forthese power plants of PVN is about 16 Mt in 2020 and 20 Mt in 2030. Compared to the total coal demandfor power generation, PVN will take a share of about 24.0% by 2019-20, and 10.0% by 2030.
Since July 2009, Vinacomin set the price for local customers, except power generators, at the market price.
In addition, 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 raiseaccording to the latest electricity price adjustment. Any adjustments are no less than the coal production
cost, in order to ensure funding for the renovation, expansion and improvement of the capacity of theexisting mines and building of new mines to meet coal demand and contribute to improvements in energy
efficiency.

ENERGY EFFICIENCYIn April 2006, the Prime Minister approved the Viet Nam National Energy Efficiency Program (VNEEP)
for 2006–2015 (PMVN, 2006b). 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 economical andefficient use of energy in society as a whole.

The aim of the program was to save 3.0%–5.0% of the total energy consumption over the 2006–10
period and 5.0%–8.0% in the 2011–15 period.
The program includes six components:

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

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;

promote EE&C in building; and

promote EE&C in transportation.

Phase one of the VNEEP for the period 2006–11 was successfully implemented, saving about 4 900
ktoe in total energy consumption for the period 2006–10, equivalent to 3.4% of the total energy
consumption in the respective period. Key legal documents on EE&C have been built and issued, including
the Law No 50/2010/QH12 dated 17 July 2010 on Energy Savings and Efficiency (effective from 1 January2011) and its implementing regulations and guidelines by sectors. Phase two for the 2012–15 period is now
underway (PMVN 2012c).
MOIT is the focal coordinator of the EE&C and is authorised to administer the implementation of the
VNEEP. As part of this mechanism, the government established Energy Efficiency and Conservation
Office within MOIT on 7 April 2006 (MOIT, 2006). The main work of the office is to develop organisations
and systems for improving energy efficiency and conservation at the government level from the central
government to the local government. According to the MOIT’s report at the 7th National Conference on
Energy Saving held in Tien Giang Province on 17th October 2014, a network of 14 energy conservation
centres and more than 40 industrial promotion centres, counselling centres, technology transfer centres havebeen established across the country.
MOIT established a National Steering Committee chaired by MOIT to monitor the VNEEP. The
committee includes representatives from the Union of Vietnam Associations of Science and Technology
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; Planning andInvestment; Justice; and Finance.
The United Nations Development Programme (UNDP) and the Viet Nam Ministry of Science andTechnology have recently finished a project to raise the effectiveness of energy use in small and medium
enterprises (SMEs). The Global Environmental Fund through the UNDP funded the project. Over five
years from 2006-10, the project provided USD 29 million to implement 500 SMEs operating in the areas ofclean production, ceramics, weaving, paper and pulp manufacture, and food processing. The project
included six sub-programs: supporting policy and institutional development; improving communications
and awareness; building technical capability; supporting providers of energy-saving services; providing
financial assistance; and providing guidance in using energy economically and effectively. The project saved
about 136 000 tonnes of fuel oil and reduced CO2 emissions by 0.96 million tonnes annually during 2006–
10.
The Promotion of Energy Efficiency and Conservation project, funded by Japan, began in 2000 andfinished successfully in 2010. The Association of South East Asian Nations (ASEAN) Centre for Energy
jointly implemented this project, along with the ASEAN economies and the Energy Conservation Centre,
Japan. The project focused on the building, industry, energy management and transport sectors.
In order to realise targets in energy efficiency programs, the Government encourages major energy-using
establishments to improve their energy planning, management and auditing. Major energy-using
establishments are those with the consumption of energy as follows:Establishments of industrial, agricultural production, and transportation units with a total yearly energy
consumption of at least 1000 toe.



Buildings used as headquarters, offices, accommodations, institutions of education, health care,recreation, fitness and sports, hotels, supermarkets, restaurants, stores with a total yearly energy
consumption of at least 500 toe.

MOIT, in coordination with other Ministries, related sectors and localities, shall organise and manage
the operation of these establishments. In addition, it will coordinate with the related Ministries, Departments
and People's Committees of Central Provinces and Cities to set up a list of these establishments, and annually
update and submit that list to the Prime Minister for approval.

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According to the List issued by the Prime Minister in 2013, there were 1 720 major energy-using
establishments in the whole country. Cities and provinces with large number of such establishments are Ho
Chi Minh City (241); Binh Duong (178); Hanoi (176); Dong Nai (106); Quang Ninh (98); Ba Ria - Vung Tau(89) and An Giang (6). The four provinces without any major energy-using establishments are Bac Kan,
Ninh Thuan, Dak Nong and Bac Lieu.

RENEWABLE ENERGYThe National Strategy on Climate Change (the PMVN’s Decision 2139/QD-TTg dated 6 December 2011)
stipulated the missions and targets for development of new and renewable energies for the period to 2020
and with a vision to 2050. It aims to:

Review, plan and develop hydroelectric projects properly for various purposes, so that the total output
capacity of hydroelectric plants can reach 20 000-22 000 MW by 2020;

Boost research and development of new and renewable producing technologies, including wind energy,
solar energy, tidal energy, geothermal energy, biofuel, and universal energy; to design and implement
policies on engaging socio-economic sectors in applying and popularising renewable energies; and

Guarantee energy security through synchronously developing different sources of energy; to raise thepercentage of new and renewable energies to 5.0% of the total primary commercial energy supply by2020 and 11.0% by 2050.

Since 2008, the government of Viet Nam developed policies to support the use of renewable energy,
as follows:

SMALL HYDRO POWER
The MOIT’s circular No. 32/2014/TT-BCT dated 09 October 2014 on Regulation on avoided cost basedon electricity tariff and power purchase agreement for small hydropower plants (MOIT, 2014) replaces theprevious MOIT’s Decision No. 18/2008/QD-BCT dated 18 July 2008 on ‘Regulation on avoided cost basedon electricity tariff schedule and standard power purchase agreement’.

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) and the MOF’s circular No.
96/2012/TT-BTC dated 8 June 2012 on ‘Financial mechanisms for grid-connecting wind power projects’.
The key elements of the decision on wind power development are incentives for capital investment, and theprovisions about related land use, transmission fees and electricity tariffs called the Fit-In Tariff (FIT). The
FIT is equal to 0.078 USD/kWh and Electricity of Viet Nam (EVN) is responsible for purchasing electricity
from all wind power plants. The government provides a subsidy of 0.01 USD/kWh of the power price for
EVN through the Viet Nam Environment Protection Fund.

BIOMASS AND WASTE POWER
Decision No. 24/2014/QD-TTg dated 24 March 2014 on ‘Mechanism for supporting biomass power
development and Decision No. 31/2014/QD-TTg dated 5 May 2014 on ‘Mechanism for supporting solid
waste power development’ support the biomass and waste power development.

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 to 2015 with a vision to 2025, stipulating thetarget to build and develop biofuel production and use nationwide (PMVN, 2007b). By 2015, the output of
ethanol and vegetable oil will reach 250 000 tons (enough for blending 5 million tons of E5 and B5),
satisfying 1.0% of the whole country's gasoline and oil demand. Towards 2025, Viet Nam aims to build an
advanced biofuel industry and the biofuel production technology applied in Vietnam will eventually reach
the world's advanced level. The ethanol and vegetable oil output will increase to 1.8 million tons, satisfying
some 5.0% of the whole country's gasoline and oil demand.
MOIT, in coordination with concerned ministries, branches, organisations and individuals, assumes
the prime responsibility for organising the efficient and timely implementation of the biofuels scheme. It
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annually reports to the Prime Minister. Enterprises that want to invest in biofuels producing projects are
required submit their plan for development to MOIT. Biofuels traded and used in Viet Nam are required tofollow the technical regulation and standards for biofuels.
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. From 1 December 2014, thedistribution and use of E5 for all motorised road vehicles is mandatory in seven cities and provinces,including Ha Noi, Ho Chi Minh City, Hai Phong, Da Nang, Can Tho, Quang Ngai, and Ba Ria-Vung Tau.
It will be mandatory for the whole economy from 1 December 2015. E10 will be mandatory in theabovementioned seven cities and provinces from 1 December 2016, and then will expand to the wholecountry from 1 December 2017.
From the 2007-15, the government classifies investment in biofuel production as an area eligible for
special investment incentives. Biofuel production enterprises are entitled to an income tax exemption or
reduction for biofuel products according to the Government’s Decree No. 24/2007/ND-CP of 14 February
2007, detailing the implementation of the Law on Enterprise Income Tax. They are entitled to the highest
land rent and land use incentives for 20 years. Raw materials, components, machinery and equipment forscientific research and technological development for biofuel production are exempt from import tax. Raw
materials, components, machinery and equipment used for biofuel production are eligible for the lowest
import tax rate.
Since the 2007 deployment of government Decision No. 177/QD-TTg dated 20 November 2007
(PMVN, 2007b), investments in biofuel research and production have increased. Biofuel research focuseson biofuel technologies, application in electricity generation and transportation use. The government has
invested in domestic research capacity to advance the biofuel sector in accordance with the framework of
Project 177, as well as in other economy-wide and provincial funding programs available for the scientificand technological development of Vietnam. In 2009 many ethanol plants were built in Quang Nam, Phu
Tho, Quang Ngai (Dung Quat), Binh Phuoc and Dong Nai. Investments have increased from domestic
enterprises including Petrovietnam. In 2014, there were five ethanol producers with a total installed capacityof 365 000 tons per year, enough for mixing 7.3 million tons of E5.

NUCLEARIn June 2010, the Prime Minister approved a plan to build and develop nuclear technology industry and tocontribute to socioeconomic development and the strengthening of the economy’s nuclear scientific andtechnological capacity (PMVN 2010).
MOIT submitted a 2005 pre-feasibility study on the building of a 2 000 MW nuclear power plant in
Ninh Phuoc or Ninh Hai (two districts of Ninh Thuan Province in central Viet Nam) for approval. In mid2009, MOIT submitted a revised version of the study (now called an investment report), which was approvedby the National Assembly in November 2009.
In July 2010, the Prime Minister also approved the ‘Planning Orientation on Nuclear Power
Development in Vietnam up to 2030’ project. This proposes that one unit with a capacity of 1 000 MW will
operate by 2020.
The construction of both plants will begin in 2014–15, and will be followed by the further developmentof the economy’s nuclear energy capacity so that it reaches 8 000–10 000 MW by 2030 (IE, 2011). However,after the March 2011 Fukushima nuclear power plant accident in Japan, safety issues in the development
and operation of nuclear power plants became a top priority for Viet Nam, and the program’s timeframe
and the generation capacity over the long term are under careful review.

CLIMATE CHANGE
In Viet Nam, the government exercises unified management over natural resources and environmental
protection throughout the country. The institutional framework for environmental governance consists of
the administrative hierarchy, with economy-wide representation through the National Assembly, andprovincial-, district-, and commune-level representation through People’s Councils and Committees. Morethan ten line ministries and central agencies deal with natural resources, and other ministries deal with generalplanning responsibilities. The Ministry of Natural Resources and Environment (MONRE) played a central
coordinating role in environmental management.

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Since 1990s, the government of Viet Nam motivated by the serious impacts of climate change on the
country’s sustainable development. Viet Nam is one of the economies most affected by climate change. It
signed the United Nations Framework Convention on Climate Change (UNFCCC) on 16 November 1994,
signed the Kyoto Protocol (KP) in 1997 and ratified it on 20 August 2002. Viet Nam has fulfilled all
requirements to be an Annex II economy for the 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, comprising officials fromMONRE 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 the Ministry of Natural
Resources and Environment, or 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 climate change’s impact on sectors and regions over specific periods, and todevelop feasible action plans that can effectively respond to climate change in the short and long term inorder 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 (the Decision 2139/QD-TTg). This strategy has a century-long vision and it is the foundation for
all other ministerial, sectoral and local strategies, plans and programs.
Viet Nam has set a target to reduce 8.0-10.0% of its COs emissions compared to its 2010 level and to
reduce annual energy intensity at a rate of 1.0-1.5%.
Many international financial institutions and developed economies in the APEC region, including theWorld Bank, the Asian Development Bank, and the governments of Australia, Canada, Japan, the US andothers are helping Viet Nam to 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

TOWARD A LOW-CARBON ECONOMY
In 2013-14, Viet Nam continues to revise its legal framework to facilitate and enhance the effectiveness ofdeveloping new and renewable energy projects, especially small hydro, wind power, biomass and waste
power, and biofuels (for more information see the Renewable section).
In addition, MOIT issued Circular No. 02/2014 dated 16 January 2014, stipulating the concretemeasures for enhancing energy savings and efficiency in the industrial sector. In previous years, MOIT
issued similar regulations for the transport (2011) and agricultural (2013) sectors.
Viet Nam is currently revising the Power Development Master Plan to 2020 with perspective to 2035
(PDP7 revised). Renewable energy is expected to have a bigger share in 2035 compared to the previous
PDP7.

ENHANCING TRANSPARENCY IN ELECTRICITY ANDPETROLEUM PRODUCTS MARKETS
Enhancing the transparency of the government’s electricity and petroleum engine fuels markets regulation
as well as the regulations monitoring the business performance information of SOEs in these key andsensitive sectors is a focus of the government. Two regulations relating to these issues include:

MOIT’s Directive No. 11/CT-BCT dated 22 April 2014 on enhancing the public communication andinformation transparency in electricity and petroleum products trading activities; andGovernment’s Decree No. 61/2013/ND-CP dated 25 June 2013 on regulations monitoring financeand business performance, and financial information transparency of enterprises owned by the Stateand having State financial participation.

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In order to accelerate administration reforms and enhance the quality of state management inconditions of commercial and economic international integration of the economy, the Prime Minister
revised the functions, powers and tasks of many governmental organisations, including MOIT’s,emphasising MOIT’s task of managing SOEs.
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VIET NAM——(2013). Approving the Socio-economic Development Master Plan up to 2020. Decision No. 339/QD-TTg,
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U SEF UL LI N K S
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—www.evn.com.vn
Energy savings (EVN)—tietkiemnangluong.vn
Trade & Investment Promotion Center, 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 Limited—www.vinacomin.vn
Vietnam Energy—nangluongvietnam.vn
Vietnam Economic Times—www.vneconomy.com.vn
Vietnam News Agency— http://vietnamnews.vn/

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