South Korean Gas Imports

opportunities for growthLNG IN KOREA

proudly produced for:

Australian Government Departmentof Industry, Tourism and Resources

ABARE

Allison Ball

Karen Schneider

Jane Mélanie

Robert Curtotti

KEEI

Changwon Park

Jaesung Kang

Jaekyu Lim

ABARE RESEARCH REPORT 03.4

© Commonwealth of Australia 2003

This work is copyright. The Copyright Act 1968 permits fair dealing for study,research, news reporting, criticism or review. Selected passages, tables or diagramsmay be reproduced for such purposes provided acknowledgment of the source isincluded. Major extracts or the entire document may not be reproduced by anyprocess without the written permission of the Executive Director, ABARE.

ISSN 1037-8286ISBN 0 642 76489 1

Ball, A., Schneider, K., Mélanie, J., Curtotti, R., Changwon Park, Jaesung Kang andJaekyu Lim 2003, LNG in Korea: Opportunities for Growth, ABARE and KEEI,ABARE Research Report 03.4, Canberra.

Australian Bureau of Agricultural and Resource EconomicsGPO Box 1563 Canberra 2601, Australia

Telephone +61 2 6272 2000 Facsimile +61 2 6272 2001Internet www.abareconomics.com

ABARE is a professionally independent government economic research agency.

Korea Energy Economics Institute665-1 Naeson-Dong, Euiwang-Si, Gyunggi-Do, 437-713, Korea

Telephone +82 3 1420 2114 Facsimile +82 3 1422 4958Internet www.keei.re.kr

ABARE project 2835

foreword

Natural gas has played an increasingly important role in meeting Korea’srapidly growing energy demand since its introduction in the mid-1980s. Thistrend is likely to continue, with forecast strong growth in natural gasconsumption over the next decade and beyond. With limited domesticreserves, Korea has relied exclusively on imports of liquefied natural gas(LNG) to meet its natural gas requirements. LNG will continue to meet themajority of Korea’s projected demand although, over the longer term, pipelinenatural gas imports could provide a complementary source of gas supply.

A critical issue for Korea is that natural gas supply plans have not kept pacewith projected demand and a significant gap between demand and supplycould develop over the next decade. Failure to resolve the issues surround-ing long term LNG procurement soon could leave Korea vulnerable to gassupply shortfalls in the coming years.

The key objective in this report is to assess the potential growth in naturalgas demand in Korea and, in particular, the role that LNG could play in thatmarket. Korea’s current and projected gas supply situation over the mediumto longer term is also reviewed. To meet future Korean natural gas demand,potential sources of LNG supply in the Asia Pacific market are examined asis the feasibility of pipeline natural gas supply options.

The study was undertaken jointly by ABARE and the Korea EnergyEconomics Institute.

BRIAN S. FISHER SANG-GON LEEExecutive Director PresidentABARE KEEI

August 2003

iiiLNG in Korea: opportunities for growth

acknowledgments

The authors wish to thank several colleagues for their valuable contributionsduring the preparation of the report: in ABARE, Vivek Tulpulé and LindsayFairhead; in the Department of Industry, Tourism and Resources, Paul Kay;and in the Australian Embassy, Seoul, H.E. Colin Heseltine, AustralianAmbassador to the Republic of Korea, Anthony Aspden, Sian Ferguson, KimHye-Young and Bill Brummitt.

Many organisations in Korea provided information and valuable commentson the study. In particular, the authors are grateful for contributions from thefollowing: the Ministry of Commerce, Industry and Energy; the Korea GasCorporation; the Korea Electric Power Corporation; POSCO; SKCorporation; the Korea South-East Power Company; the Korea SouthernPower Company; LG-Caltex Oil Corporation; and LG InternationalCorporation.

In addition, the authors gratefully acknowledge the information and insightsprovided by Gavin Harper, ChevronTexaco, Seoul; Jeff Feltham, North WestShelf Australia LNG, Perth; Damian Deveney and Rob Mitchenall, ShellPacific Enterprises Limited, Seoul; and Sean Rodrigues, Woodside Energy,Perth.

ABARE and KEEI also gratefully acknowledge the support of Chevron-Texaco, North West Shelf Australia LNG and Woodside Energy for the trans-lation, publication and launch of the Korean language version of the studyin Seoul on 28 August 2003.

ABARE’s contribution to the report was funded by the Australian Departmentof Industry, Tourism and Resources.

iv ABARE research report 03.4

contents

Summary 11 Introduction 8

Objectives in the study 9

2 Energy and natural gas consumption in Korea 11Energy consumption 11Natural gas consumption 17Natural gas supply 21Gas pricing 27

3 Factors affecting Korea’s future natural gas demand 31Environmental issues 31Security of energy supply 33New sources of demand 34Energy market reform 36

4 Projecting natural gas demand in Korea 45Analytical framework 45Reference case projections 51

5 Alternative policy scenarios 57Electricity and gas sector deregulation 57Impacts of a gas supply disruption 62

6 Natural gas supply considerations 67Pipeline natural gas 67Can pipeline natural gas compete with LNG? 72Natural gas supply and demand balance 73Supplying LNG to Korea 76

7 Conclusions 82

vLNG in Korea: opportunities for growth

AppendixA Structure of the global trade and environment model

(GTEM) 84

References 91

boxes1 Korea’s LNG supply shortfall in winter 2002–03 242 Gas price setting procedures in Korea 283 Economic reform under the Roh Moo-hyun

administration 384 Assessing the costs of electricity generation 395 Entry of private LNG importers into the Korean

gas market 436 Benefits of deregulation in the electricity and

gas sectors 587 LNG supply disruption to Korea in 2001 638 A ‘gas-for-peace’ deal with North Korea – implications

for pipeline projects 709 Alternative natural gas supply and demand balance 7510 Australian LNG supply 81

figuresA LNG consumption, by sector 2B Monthly LNG consumption, by sector 3C Projected natural gas consumption, reference case 4D Potential gas demand and supply balance 61 Total primary energy consumption 112 Fuel mix in primary energy consumption 133 Final energy consumption, by sector 144 Motor vehicle registrations 155 Final energy consumption in key sectors, by fuel 156 Energy imports, by fuel 177 City gas demand, by sector 198 LNG monthly consumption, by sector 209 City gas monthly consumption patterns, by sector 20

10 LNG imports 21

vi ABARE research report 03.4

11 LNG import terminals and pipeline network 2512 Average LNG and crude oil import prices 2713 Fuel mix in district heating systems, 2000 3414 Electricity generation costs 4015 Indicative long run marginal costs for power generation 4116 Deviation from the reference case in a GTEM simulation 4717 Alternative projections for share of gas fired power

generation 4818 Residential consumption of coal, gas and electricity 5019 Annual growth in energy consumption, reference case,

2001–15 5220 Primary energy consumption, by fuel, reference case 5221 Total primary energy consumption by fuel, reference case 5322 Annual growth in gas consumption, by sector, reference

case, 2001–15 5423 Gas consumption, by sector, reference case 5424 Projected unmet gas demand, reference case 5525 Change in energy prices following deregulation, 2015 5926 Change in production and exports of energy intensive

goods following deregulation, 2015 6027 Change in energy consumption following deregulation,

2015 6028 Gas consumption by sector following deregulation, 2015 6129 Fuel mix in electricity generation following deregulation,

2015 6230 Change in gas and electricity price following a gas

supply disruption, 2005 6431 Change in GNP following a gas supply disruption,

2005 6532 Change in sectoral output following a gas supply

disruption, 2005, 6533 Gas consumption following a gas supply disruption, 2005 6634 Possible gas pipelines to Korea 6735 Potential natural gas demand and supply balance 7436 Alternative natural gas demand and supply balance 75

viiLNG in Korea: opportunities for growth

37 Proved recoverable reserves in countries exporting LNG to the Asia Pacific market, 2002 77

tablesA Total primary energy consumption, 2002 2B LNG imports, by source, 2002 3C Projected natural gas demand and supply 51 Major energy and economic indicators 122 International comparison of major energy and economic

indicators, 2000 123 Total primary energy consumption, 2002 134 Electricity generation, by fuel 165 Electricity plants and capacity, 2001 166 Energy import indicators 177 LNG consumption, by end use 188 City gas consumption, by region 199 LNG imports, by source 2210 Existing mid and long term LNG contracts 2311 LNG receiving terminals 2612 Planned expansion of LNG storage tanks 2613 Planned expansion of gas pipeline network 2614 Wholesale gas price for power plants, January 2003 2715 Wholesale price for city gas, January 2003 2916 Retail price for city gas, Seoul area, January 2003 2917 Mid to long term projections for district heating supply 3518 Fuel costs for electricity generation, 2000 3919 Cost estimates for new generating plants 4020 Regions and sectors in GTEM in this study 4621 Projected share of electricity generation, by fuel, reference

case 4922 GDP and primary energy consumption, reference case 5123 Revision of special consumption taxes on fuel sources 5324 Contracted gas supply and projected shortfall, reference

case 5625 Projected energy consumption following deregulation,

2015 61

viii ABARE research report 03.4

26 Sakhalin gas reserves 6927 Potential natural gas demand and supply balance 7428 Alternative natural gas demand and supply balance 7529 LNG trade in the Asia Pacific, 2002 7630 Existing LNG plants, Asia Pacific market 7831 LNG plants under construction and planned, Asia

Pacific market 7932 Indicative LNG transport costs to Korea from various

exporters, 2001 80

ixLNG in Korea: opportunities for growth

summary

Since its introduction in 1986, natural gas has played an increasingly impor-tant role in meeting rapidly growing energy demand in the Republic of Korea(Korea). This trend is likely to continue, with forecast strong growth in naturalgas consumption over the period to 2015. With limited domestic reserves,Korea has to date relied exclusively on imports of liquefied natural gas (LNG)to meet its natural gas requirements. LNG will continue to meet the major-ity of Korea’s projected demand, although pipeline natural gas imports couldprovide a complementary source of gas supply over the medium to longerterm.

An important issue for Korea is that gas supply plans have not kept pace withprojected demand and a significant gap between demand and supply coulddevelop over the next decade. Procurement of LNG supplies over the longerterm remains uncertain in Korea as the government is delaying entering intonew long term contracts until plans to liberalise Korea’s domestic gas marketare progressed. Failure to address this issue soon could leave Korea vulner-able to gas supply shortfalls over the medium term.

The key objective in this report is to assess the potential growth in naturalgas demand in Korea over the period to 2015 and, in particular, the role thatLNG could play in that market. Korea’s current and projected gas supplysituation over the medium to longer term is also reviewed. In this context,potential sources of LNG supply in the Asia Pacific market are examined,as well as options for pipeline natural gas supply to Korea from the RussianFederation.

Energy overview Energy consumption in Korea has increased by more than 7 per cent a yearover the past two decades, driven by rapid growth in economic output andrising personal incomes. Total primary energy consumption in 2002 reached209 million tonnes of oil equivalent, compared with 44 million tonnes of oilequivalent in 1980. Oil is the main source of energy in Korea, accountingfor 49 per cent of primary energy consumption (table A), although its sharehas been declining in recent years.

1LNG in Korea: opportunities for growth

Korea depends on imports for morethan 97 per cent of its non-nuclearenergy requirements. In conjunc-tion with its reliance on oil, this hasled to a strong emphasis on energysecurity and supply diversificationpolicies. In this context, natural gaswas introduced into the Koreanmarket in 1986 in the form ofimported LNG.

Natural gas consumption in KoreaNatural gas use in Korea has grown at an average annual rate of 19 per centsince 1990, albeit from a small base, and represented more than 11 per centof primary energy consumption in 2002. In 2002, natural gas consumptionwas 18.1 million tonnes (25.0 billion cubic metres). The rapid growth hasbeen a result of active government policies to encourage natural gas use,expansion in gas infrastructure, including gas distribution networks and elec-tricity generation plants, and rising personal incomes that have induced ashift in preferences to clean and efficient fuels.

Rapid growth in city gas consumption in Korea over the past decade is themain source of the sharp rise in LNG demand (KEEI 2003a; figure A). Thecity gas sector accounted for 62 per cent of Korean LNG consumption in2002, while electricity generation comprised 33 per cent. Within the city gassector, the majority of demand isfrom the residential sector and isdriven by strong demand for heat-ing and, increasingly, space cool-ing. This has led to strong seasonalfluctuations in LNG consumptionin Korea (KEEI 2002a, 2003a;figure B). In the electricity sector,LNG accounted for 11 per cent oftotal power generation in 2001 andis used primarily as a peak loadfuel.

Currently all natural gas demandin Korea is met by imported LNG

2 ABARE research report 03.4

A Total primary energyconsumption, 2002 Korea

Mtoe %

Coal 49.1 23.5Oil 102.7 49.1LNG 23.6 11.3Nuclear 29.8 14.2Renewables 3.9 1.9

Total 209.1 100.0

Source: KEEI (2003a).

LNG consumption, by sector Korea

15

10

5

1986 1990 1994 1998 2002

Mt

A

OtherElectricity generationCity gas

and Korea is the world’s secondlargest importer of LNG afterJapan. The majority of LNGimports are on the basis of longterm take or pay contracts fromIndonesia, the Middle East,Malaysia and Brunei (table B).Korea also uses the spot marketextensively to meet winter demandpeaks and any shortfalls incontracted supply. From late 2003,domestic gas supply will beginfrom a small field in the East Seabut supply from this project willmeet only around 2 per cent ofKorea’s current gas demand.

Factors affectingfuture natural gasdemandWhile natural gas demand is ex-pected to continue to grow strong-ly in Korea, a range of issues willaffect the extent and profile offuture demand, including environ-mental considerations, energysecurity issues and new sources ofgas demand. One of the most important factors will be the anticipated liber-alisation of domestic electricity and gas markets. While the deregulation andprivatisation plans for these sectors developed by the previous governmenthave stalled under the current administration, some form of liberalisation islikely to occur over the medium term.

Electricity market liberalisation is likely to increase competitive pressureson power generators and provide incentives for cost minimisation. Based onfuel costs alone, LNG is generally less competitive than other energy sources.However, gas fired electricity generation could compete more effectivelywhen the total cost of generation is considered because of its lower capitaland operating costs. This suggests a more robust future for gas use in power


B LNG imports, by source, 2002Korea

Mt %

Qatar 5.2 28.9Indonesia 5.0 28.2Oman 4.1 22.8Malaysia 2.3 12.9Brunei 0.8 4.3Australia 0.2 1.0Other 0.3 2.0

Total 17.8 100.0

Sources: KOGAS (2003); BP (2003).

Monthly LNG consumption, by sector Korea

Dec DecDec 200220012000

Mt

BElectricity generationCity gas

0.5

1.0

1.5

2.0

Other

generation in a deregulated, competitive market, especially to meet peakdemand.

Similarly, the expected transition to a more efficient and competitive struc-ture in the gas market has the potential to increase the relative competitive-ness of natural gas and stimulate new demand. However, the delay inimplementing gas market reform is having some serious implications forKorea’s long term gas supply security. This is because the Korean govern-ment is postponing entering new long term LNG supply contracts until theissue of reform has been progressed.

Projecting natural gas demand in KoreaThe analysis of the potential demand for natural gas in Korea over the periodto 2015 presented in this report is based on results from ABARE’s globaltrade and environment model (GTEM). The energy demand projections arebased on an assumption that GDP growth in Korea will average 5 per centa year between 2001 and 2015.

The projections are also based on assumptions relating to the projected fuelmix in electricity generation. In Korea there is some uncertainty surround-ing the role that natural gas may play in power generation over the outlookperiod. The assumptions used in this study are from the Korea PowerExchange (KPX 2002a). The share of gas in total electricity output is assumedto rise over the first half of the outlook period but to fall between 2007 and2010 as a result of strong expan-sion in nuclear and coal firedoutput. At 2015, the share of gasis 11 per cent.

On the basis of these assumptions,total primary energy consumptionis projected to expand by 3.5 percent a year to reach 319 milliontonnes of oil equivalent in 2015.Natural gas is projected to remainone of the fastest growing fuels inKorea, averaging 5.0 per centgrowth a year over the period2001–15 to reach 33.3 milliontonnes (45.9 billion cubic metres)


Projected natural gas consumption, reference case Korea

Mt

C

5

10

15

20

25

30

2003 2006 2009 2012 2015

ResidentialCommercialIndustry

Electricity

or around 13 per cent of total primary energy consumption. The fall in over-all natural gas use between 2007 and 2010 reflects the assumed fall in gasfired power generation over this period (figure C). The strongest growth indemand for natural gas is expected to be in the residential and industry sectors.

Based on existing LNG import contracts, it is expected that there will be agas supply shortfall of around 3 million tonnes in Korea in 2005 (table C).Taking into account the expiry of some existing contracts, supply in 2015could be around 20 million tonnes lower than projected natural gas demand.

Natural gas supply considerationsIn the absence of significant domestic reserves, there are two options forKorea to meet the anticipated gas supply shortfall –– to sign new LNG importcontracts and to import pipeline natural gas. Additional short term solutionsinclude increased LNG spot market purchases, cargo swaps with other coun-tries such as Japan, and midterm LNG contracts. Two midterm (seven year)contracts were recently signed with Australia and Malaysia, with supply tobegin in late 2003.

Over the longer term, there is potential to develop pipeline natural gas supplyto Korea. A pipeline from Irkutsk in eastern Siberia through northern Chinato Korea is currently the subject of a feasibility study, the results of whichare expected by September 2003. The Korean government considers thatsupply from the Irkutsk pipeline could begin from 2008–10 and that it coulddeliver 7 million tonnes of natural gas a year for thirty years. However,construction of the 4100 kilometre, US$11 billion pipeline would have tobegin rapidly to be operational within this timeframe. The commercial viabil-ity of the project also depends to a large extent on the commitment of China


C Projected natural gas demand and supplyKorea

2005 2010 2015

Mt Mt Mt

Projected gas demand, reference case 23.9 24.2 33.3KOGAS LNG contracts 19.4 14.6 11.9POSCO/SK LNG contract 1.0 1.0 1.0Projected domestic supply 0.4 0.4 0.4Projected gas supply shortfall 3.1 8.2 20.0

to the pipeline –– without demand from China, there is unlikely to be suffi-cient gas to justify construction of the pipeline on commercial grounds.

Korea’s decision to use pipeline natural gas will depend significantly on itscompetitiveness with imported LNG. Korea has sought pipeline prices thatare believed to be competitive with LNG and that would enable the projectto proceed on a commercially sound basis. However, some analysts haveexpressed doubts that pipeline natural gas could compete in Korea with LNGover such distances, especially in an environment of declining internationalLNG prices (Platts 2003a,b). Other recent trends, including greater flexibil-ity in the terms and conditions on which LNG is available, including an abil-ity to meet seasonal demand patterns, can also be expected to increase theattractiveness of LNG. Economic factors aside, pipeline natural gas may stillform a part of Korea’s gas supply mix in the medium to longer term if noneco-nomic factors, including energy security and geopolitical concerns, areemphasised in the decision making process.

Indicative gas supply and demand balanceA potential natural gas supply and demand balance for Korea is provided infigure D based on the demand projections developed in the report and currentand known planned gas supply. The balance assumes that 0.4 million tonnesa year of gas will be delivered from Korea’s Donghae project and that theby POSCO/SK contract for around 1 million tonnes of LNG a year from2005 will proceed. It also assumes that pipeline natural gas supply fromIrkutsk will begin from 2010.


Potential gas demand and supply balance Korea

Mt

D

5

10

15

20

25

30

2003 2006 2009 2012 2015

Gas supply shortfall/possible additional LNG

Pipeline natural gas supply, Irkutsk

Donghae gas field supply

POSCO/SK LNG contract

KOGAS LNG mid term contracts

KOGAS LNG long term contracts

On the basis of these assumptions, there is projected to be a natural gas supplyshortfall of 13.0 million tonnes at 2015. The supply gap becomes more signif-icant after 2010, when stronger growth in natural gas demand is forecast thanin the earlier part of the outlook period. This shortfall is likely to be met bynew LNG import contracts. The need for additional LNG contracts could begreater if the Irkutsk project is delayed beyond 2010 or is not able to supply7 million tonnes of gas a year.

In these circumstances, Korea would need to secure additional LNG contractsof around 3 million tonnes by 2005 and further term contracts to meet theprojected shortfall in the remainder of the outlook period. Failure to contractadditional medium to long term gas supplies is likely to leave Korea vulner-able to gas shortages and to exacerbate the difficulties it has experienced inrecent years.

A key issue in this context is the government’s preference to delay enteringinto new LNG supply contracts until decisions have been made regardingthe reform of the gas market. However, waiting for gas reform plans to beimplemented before committing to new LNG contracts is exacerbating thegas shortfall issue. Because gas market reform is complex and requires goodplanning to implement effectively, it is not necessarily in Korea’s best inter-ests to put pressure on the reform process to hasten the signing of new LNGcontracts, or vice versa. By waiting, however, Korea is potentially missingthe opportunity to secure favorable terms and conditions that are currentlybeing offered under long term contracts in the international market.

Further, there are currently a number of LNG supply projects in the AsiaPacific region –– existing and planned –– that have the capacity to meetKorea’s long term gas requirements. Indeed, the size of Korea’s long termgas requirements is sufficient to justify additional investment in productioncapacity by LNG suppliers. However, given the time required to bring newdevelopments to the market, it will be important for Korea to commit to newsupply contracts as soon as possible if it is not to face an increasingly diffi-cult gas supply situation in the medium term. The current competitivenessof the LNG supply industry and its responsiveness to changing market condi-tions will also ensure that Korea’s long term energy security objectives aremet.


introduction

The Republic of Korea (Korea) has achieved remarkable economic progressover the past fifty years, moving from a low income agrarian economy to aninternationally competitive and highly industrialised economic system. Thisstrong economic performance has been underpinned by large scale and oftengovernment-directed industrial development. The sustained shift from primaryindustries to more energy intensive sectors, including iron and steel produc-tion and ship building, along with rising incomes, limited natural resourceendowments and climatic factors, has played a key role in shaping energyconsumption patterns in Korea.

In particular, Korea’s strong economic growth and expansion of energy inten-sive industries has led to a rapid rise in energy consumption. Primary energyconsumption has grown at more than 7 per cent a year since 1980, reaching209 million tonnes of oil equivalent in 2002. Korea is the fourth largest energyconsumer in Asia, with its fuel mix heavily biased toward oil.

With limited indigenous energy resources, a key characteristic of the Koreaneconomy is its dependence on imports for more than 97 per cent of its energyrequirements, excluding nuclear power. From an energy policy perspective,this import dependence has led to a strong emphasis on energy security andstrategies to diversify fuel supplies. With such high import dependence likelyto continue, security of energy supply can be expected to remain one of thekey pillars of energy policy in the foreseeable future.

In this context, natural gas (in the form of imported liquefied natural gas orLNG) was introduced into the Korean market in 1986 and has since playedan increasingly important role in the fuel mix. Natural gas represented 11per cent of Korea’s total primary energy consumption in 2002.

LNG imports have increased in line with the rising consumption of gas, andKorea is now the world’s second largest importer of LNG after Japan. In2002, Korea imported nearly 18 million tonnes of LNG, primarily under longterm contracts with suppliers from Indonesia, Malaysia, Brunei and theMiddle East. This is equivalent to around a quarter of Asia Pacific LNG trade.

8

1

ABARE research report 03.4

The role of natural gas in meeting Korea’s energy demand is likely to continueto expand over the next decade, as gas offers a competitive and clean alter-native fuel for a range of end uses. This trend is being reinforced by stronginvestment in new gas distribution networks. Also important will be proposedreforms in Korea’s electricity and gas industries that are likely to introducemore efficient and competitive energy markets.

Korea’s limited domestic gas resources mean that any growth in gas consump-tion will need to be supplied either by increased LNG imports and/or theintroduction of pipeline natural gas. While KOGAS, Korea’s gas importingmonopoly, has mid and long term LNG contracts for volumes of 19 milliontonnes a year, Korea’s first contract with Indonesia will expire in 2007.Further, a shortfall in contracted LNG supply is expected to expand over theperiod to 2015 as more long term contracts expire and Korean natural gasdemand increases.

This likely gas shortfall is emerging as a serious issue for Korea as KOGAShas delayed signing new long term LNG contracts until plans to reform thegas market are progressed. To date, KOGAS has addressed the anticipatedsupply shortfall by increasing its use of the spot market and by entering intomidterm LNG contracts with Australia and Malaysia. However, to ensurethat its gas requirements over the coming years can be met cost effectivelyand without risk it will be necessary for Korea to consider entering intofurther mid or long term LNG supply contracts in the near future.

Over the longer term, pipeline natural gas could provide an additional andcomplementary source of gas supply to the Korean market. The feasibilityof a long distance gas pipeline from the Irkutsk region in the RussianFederation is currently being considered by government and industry inKorea. In addition to cost effectiveness, a critical factor in the overall assess-ment of such projects will be their contribution to energy security and diver-sity of energy supply.

Objectives in the studyThe key objective in this report is to assess the potential growth in naturalgas demand in Korea and, in particular, the role that LNG could play in thatmarket. The likely demand for natural gas is analysed on the basis of assump-tions related to economic growth, the fuel mix in power generation and otherfactors that will influence energy sector outcomes. These include policies


associated with liberalisation of the electricity and gas markets, security ofenergy supply, nuclear power policies and environmental issues.

The study also assesses the emerging natural gas supply gap faced by Koreaand reviews the options available to meet this shortfall. Sources of LNGsupply in the Asia Pacific market and their key characteristics, includingresource availability, production capacity and security of supply are exam-ined. Also analysed are options for pipeline natural gas supply to Korea, witha focus on the feasibility of long distance pipelines from the RussianFederation, and their potential competitiveness with LNG.


energy and natural gasconsumption in Korea

Energy consumption Primary energy consumption in Korea has grown rapidly over the past twodecades, at an average rate of 7.4 per cent a year. In 2002, energy consump-tion was 209 million tonnes of oil equivalent, compared with 44 milliontonnes of oil equivalent in 1980 (KEEI 2003a; figure 1). While the Asianfinancial downturn in the late 1990s had a significant impact on the Koreaneconomy –– energy consumption fell by 8.1 per cent in 1998 –– it has sincerecovered rapidly (KEEI 2003a). Korea accounted for 8 per cent of AsiaPacific energy consumption in 2002 (BP 2003).

Driving the rapid growth in energy consumption has been Korea’s strongeconomic performance. The Korean economy has grown at an average annualrate of 7.1 per cent since 1980, with gross domestic product (GDP) valuedat 596 trillion won (US$477 billion) in 2002 (table 1). Economic growth fellsharply in 1998 as a result of the Asian financial downturn but recoveredquickly to reach 6.3 per cent in 2002, reflecting robust domestic consumerspending and growth in export sectors. Economic growth in 2003 is expectedto slow to around 3.5 per cent as a result of the sluggish world economy.

Energy intensity, or energyconsumption per unit of economicoutput, remains high in Korea, at0.4 tonnes of oil equivalent perthousand won in 2002 (table 1).This reflects the fact that economicgrowth has been led by expansionin energy intensive industries,including petrochemicals, steel andshipbuilding. While Korea’senergy intensity has declined since1997 as a result of industrialrestructuring, it remains one of thehighest among OECD countries(table 2).

11

2

LNG in Korea: opportunities for growth

Total primary energy consumption Korea

1982 1986 1990 1994 1998 2002

Mtoe

1

50

100

150

200RenewablesNuclearLNGOilCoal

Energy consumption per person in Korea has also grown rapidly, from 1.2tonnes of oil equivalent in 1981 to 4.4 tonnes of oil equivalent in 2002 (table1). Current levels are similar to those of Japan and Germany, although lowerthan in Australia and the United States (table 2).

Fuel mix in primary energy consumptionTotal primary energy consumption is the total energy used by an economy.Primary fuels include coal, crude oil and net imports of petroleum products


1 Major energy and economic indicatorsKorea

Annual growth

1981 1991 20011981 1991 2001 2002 –91 –2001 –02

% % %

Energy consumption Mtoe 45.7 103.6 198.4 209.1 8.5 6.7 5.4Real GDP a trillion won 139.2 327.4 560.9 596.4 8.9 5.5 6.3Population million 38.7 43.3 47.3 47.6 1.1 0.9 0.6Energy intensity toe/’000 won 0.4 0.4 0.4 0.4 -0.3 1.1 -0.9Energy consumptionper person toe 1.2 2.4 4.2 4.4 7.3 5.8 4.7

a in 2002 prices.Sources: KEEI (2003a); KNSO (2003).

2 International comparison of major energy and economic indicators,2000

Primary energy Energy Energyconsumption intensity a consumption b

Mtoe toe/’000 US$ per person

Korea 193.6 0.30 4.10Japan 524.7 0.17 4.13Chinese Taipei 11.5 0.20 3.74China 1 142.4 0.24 0.91United States 2 299.7 0.26 8.35Germany 339.6 0.18 4.13Australia 110.2 0.23 5.75OECD average 5 316.9 c 0.22 4.74non-OECD average 6 251.5 c 0.32 0.64

a Tonnes of oil equivalent per thousand 1995 US$ PPP. b Tonnes of oil equivalent per person. c Total.Sources: IEA (2002a,b).

(hereafter referred to as oil), naturalgas, nuclear power and renewables(hydropower and others such aswind and solar power).

Oil constitutes the largest share ofprimary energy consumption inKorea, at 49 per cent in 2002 (table3). While demand for oil hasgrown by more than 6 per cent ayear on average over the pastdecade, its share of primary energyconsumption has declined steadily since 1994 (KEEI 2003a; figure 2). Highcrude oil prices in recent years have contributed to the declining share of oil,as have government efforts to reduce Korea’s dependence on imported oilsupplies.

Coal is also an important energy source in Korea, representing 23 per centof primary energy consumption in 2002. While coal demand has been strongin recent decades, a significant change in the composition of coal consump-tion has occurred over this period. Anthracite coal is the main domesticenergy resource available in the Korean territory and was the major energysource before being replaced by oil in the 1970s. However, anthracite has toa large extent been replaced by imported bituminous coal –– the share ofanthracite in total primary energy consumption was 2 per cent in 2002.

Natural gas has led the growth inenergy consumption in Korea sinceLNG was introduced into themarket in 1986. LNG consumptionhas grown at an average annualrate of 18.7 per cent over the pastdecade, to reach 11 per cent ofprimary energy consumption in2002, compared with 3 per cent in1990. This rapid growth, albeitfrom a small base, is a result ofactive government policy initia-tives encouraging LNG use and theexpansion of gas infrastructure


3 Total primary energyconsumption, 2002 Korea

Mtoe %

Coal 49.1 23.5Oil 102.7 49.1LNG 23.6 11.3Nuclear 29.8 14.2Renewables 3.9 1.9

Total 209.1 100.0

Source: KEEI (2003a).

Fuel mix in primary energy consumption Korea

1982 1986 1990 1994 1998 2002

%

2

20

40

60

80

RenewablesNuclearLNGOilCoal

throughout the country. LNG consumption is discussed in more detail laterin this chapter.

Use of nuclear power has also grown rapidly since the commissioning ofKorea’s first nuclear power plant in 1977, to reach 14.2 per cent of primaryenergy consumption in 2002. This large expansion in the use of nuclear powerreflects government policy responses to Korea’s growing reliance on importedenergy.

Renewable energy, including hydropower, constitutes a marginal share inprimary energy consumption, at 2 per cent in 2002, although use of nonhy-dro renewables has been growing in recent years. Supportive governmentpolicies, including the New and Renewable Energy Development andPromotion Act, which encourages the installation of waste incineration facil-ities to generate heat and power and residential solar hot water systems, havebeen introduced as a means of reducing Korea’s dependence on importedfossil fuels and to provide clean energy.

Final energy consumptionTotal final energy consumption is defined as the total amount of energy usedby final consumers. It includes energy used by industry, transport, residen-tial and commercial services sectors but does not include the energy used inconversion (principally electricity generation and petroleum refining) anddistribution activities.

In 2002, final energy consumptionin Korea was 161 million tonnes ofoil equivalent (KEEI 2003a; figure3). The industry sector is the largestfinal energy user in Korea, ataround 55 per cent in 2002. Thissector has also been one of thefastest growing users of energy inrecent years. Energy consumptionin the residential and commercialsectors has grown more slowly andrepresented 22 per cent of finalenergy consumption in 2002. Thetransport sector has become morevisible over the past decade as a


Final energy consumption, by sector Korea

1982 1986 1990 1994 1998 2002

Mtoe

3

20

40

60

80

100

120

140 Public/othersResidential/commercialTransportIndustry

result of the rapid expansion invehicle ownership (KEEI 2003a;figure 4) and transport volumes inKorea, and now accounts for 21 percent of final energy consumption.

Within these sectors, there havebeen notable changes in fuelchoices. There has been substitu-tion away from heavy fuel oil andcoal toward natural gas and elec-tricity in the industry sector,reflecting the advantages of thesefuels in terms of environmentaland inventory costs. In the resi-dential and commercial sectors, rapid economic growth and rising incomeshave led to a shift in consumer preferences away from coal to more conve-nient and clean fuels such as natural gas and electricity. The share of coal inthe residential and commercial sectors, for example, fell from 23 per cent in1992 to 2 per cent in 2002, while the share of gas rose from 8 per cent to 30per cent over the same period (KEEI 2003a; figure 5).

Electricity generationElectricity consumption in Korea has grown more rapidly than overall energyuse over the past two decades, at10.2 per cent a year, to reach 278terawatt hours in 2002. The largestelectricity consumers in Korea arethe industry sector, accounting formore than half of electricity use in2002, and the commercial sector(26 per cent) (KEEI 2003a).

Nuclear power constitutes thelargest source of electricity gener-ation in Korea, at 39 per cent in2001 (table 4). Korea currently hassixteen nuclear units in operationat four sites, representing 27 percent of total electricity generating


Motor vehicle registrations Korea

1982 1986 1990 1994 1998 2002

million

4

2

4

6

8

10

12 TrucksBusesPassenger cars

Final energy consumption in key sectors, by fuel Korea

1982 1990Industry Residential and

commercial

2002 1982 1990 2002%

5

20

40

60

80 Other

Electricity

City gas

Petroleum

Coal

capacity (table 5). Coal also accounts for approximately 39 per cent of powergeneration in Korea, while 30 per cent of capacity is coal fired.

LNG represented 11 per cent of electricity generation in 2001 but accountedfor 25 per cent of capacity. This is because LNG is used primarily as a peakload fuel in Korea. There were 104 LNG fired units in 2001, reflecting theirsmaller size and peak load application.

Oil fired power generation in Korea has declined significantly over the pasttwo decades, to 10 per cent in 2001, as has hydropower, to 1.5 per cent in 2001.

Energy importsKorea’s dependence on energyimports has grown significantly inthe past two decades, from 74 percent of energy requirements,excluding nuclear power, in 1980to more than 97 per cent in 2002(table 6). Energy imports werevalued at US$31.5 billion in 2002and represented 21 per cent ofKorea’s total import bill. Oilaccounted for the majority ofenergy imports, at around 80 percent in value terms, while LNGimports accounted for 13 per cent.


4 Electricity generation, by fuelKorea

1981 1991 2001

TWh % TWh % TWh %

Coal 2.5 6.3 20.1 17.0 110.3 38.7Oil 32.1 79.8 27.2 22.9 28.2 9.9LNG – – 9.9 8.4 30.5 10.7Nuclear 2.9 7.2 56.3 47.5 112.1 39.3Renewables 2.7 6.7 5.1 4.3 4.2 1.5

Total 40.2 100.0 118.6 100.0 285.2 100.0

Sources: KEEI (2001); KPX (2002a).

5 Electricity plants and capacity,2001 Korea

Numberof units Capacity Share

GW %

Coal 38 15.5 30.5Oil 21 4.5 8.8LNG 104 13.0 25.5Nuclear 16 13.7 27.0Renewables 200 4.2 8.1

Total 379 50.9 100.0

Source: KPX (2002b).

Energy imports have grown rapidlyin line with energy consumption,from 33 million tonnes of oil equiv-alent in 1980 to 215 million tonnesof oil equivalent in 2002 (KEEI2003a; figure 6).

In addition, Korea remains highlydependent on the Middle East forits supplies of crude oil, at 73 percent in 2002 (table 6). This is lowerthan in 1980, however, and reflectsdiversification away from MiddleEastern oil following the oil pricerises of the late 1970s and early1980s. While LNG was introduced as a means of diversifying energyconsumption away from oil, Korea has also depended entirely on importsfor its natural gas supply. Such rapid growth in energy imports and importdependence has raised concerns in Korea over diversity and security of energysupply sources. This issue is discussed further in the following chapter.

Natural gas consumptionNatural gas consumption in Korea has grown rapidly since LNG was firstimported in 1986, at an average rate of 18.7 per cent a year over the pastdecade. In 2002, natural gas consumption was 18.1 million tonnes of LNG(25.0 billion cubic metres), compared with 2.3 million tonnes (3.2 billioncubic metres) in 1990 (KEEI 2003a).


6 Energy import indicatorsKorea

1980 1990 2000 2002

Energy imports US$b 6.5 10.9 37.6 31.5Overseas energy dependence a % 73.5 87.9 97.2 97.3Oil share in energy imports b % 92.3 82.5 83.6 79.7LNG share in energy imports b % – 4.4 10.1 12.7Middle East share of crude oil imports b % 98.8 73.4 76.8 73.4

a Excluding nuclear power. b Dollar value.Sources: KEEI (2002b, 2003a); MOCIE (2003).

Energy imports, by fuel Korea

1982 1986 1990 1994 1998 2002

Mtoe

6

150

100

50

200 LNGOilCoal

Gas consumption, by sectorRapid growth in city gas use –– or gas for nonpower generation –– is themain reason that LNG demand has increased so sharply (table 7). In theinitial stage of the natural gas industry in Korea, most LNG was consumedin power generation. However, with the expansion of the pipeline distribu-tion network and rising personal incomes, consumption of city gas has grownsignificantly. Since 1990, LNG consumption by the city gas sector has grownat an average annual rate of 28 per cent. The city gas sector accounted for62 per cent of total LNG consumption in 2002, followed by electricity gener-ation (33 per cent), district heating (3 per cent) and other uses (2 per cent).This is in contrast with other countries, including Japan and Chinese Taipei,where electricity generation is the main user of LNG.

Demand for LNG in electricity generation in recent years has remainedsteady, largely as a result of relatively high LNG prices. However, electric-ity sector demand for LNG spiked in late 2002 in response to increases incrude oil prices. While LNG prices are linked to international crude oil prices,the time lag in the adjustment to LNG prices meant that LNG became morecompetitive over this period and replaced oil fired power generation. LNGdemand for electricity generation in October and November 2002, for exam-ple, was 86 per cent and 68 per cent greater than their 2001 levels respec-tively (KEEI 2003a).


7 LNG consumption, by end useKorea

DistrictElectricity heat City gas Other Total

kt kt kt kt kt

1986 45 – – 8 531990 1 741 – 575 12 23291995 3 412 150 3 417 108 7 0871996 4 448 173 4 561 179 9 3621997 5 197 178 5 770 232 11 3781998 4 029 159 6 232 222 10 6641999 4 591 177 7 886 306 12 9612000 4 353 335 9 528 339 14 5562001 4 653 630 10 299 402 15 9902002 5 969 540 11 194 425 18 128

Sources: KEEI (2002c, 2003a).

City gas demandLNG currently accounts for 99.5per cent of city gas supply inKorea, hence trends in the city gassector have a direct impact onLNG demand. Liquefied petroleumgas (LPG) accounts for the remain-ing 0.5 per cent of city gas supply.

Korea’s consumption of city gas in2002 was 14.1 billion cubic metres,equivalent to 10.3 million tonnesof LNG. Increasing use of gas inthe residential sector has driven theexpansion in city gas demand, withaverage annual growth of 27 percent since 1990 (KEEI 2003a:figure 7). In 2002, the residential sector accounted for 55 per cent of totalcity gas demand. City gas is mainly used in this sector as a fuel for cooking,space heating and increasingly, space cooling.

Industry use of city gas has grown at a similar rate over the past decade, toconstitute 27 per cent of city gas consumption in 2002. This growth reflectsin part marketing efforts to boost gas sales in this sector. KOGAS, the stateowned gas company, provides subsidies for industrial customers to buildnatural gas facilities or cogeneration units, and for commercial users to installgas cooling systems. The commercial sector is the smallest user of city gas,


City gas demand, by sector Korea

1986 1990 1994 1998 2002

billion m3

7

2

4

6

8

10

12 IndustryCommercialResidential

8 City gas consumption, by regionKorea

Consumption Annual Connectionsgrowth Network as at

1990 2000 2001 1990–2001 2001 Dec. 2001

million million millionm3 m3 m3 % km ’000

Capital area a 706 7 799 8 148 24.9 89 927 6 019Province area 257 4 381 4 709 30.3 41 099 2 671

Total 963 12 180 12 858 26.6 131 027 8 691

a Includes Seoul, Incheon and Gyeonggi.Source: Citygas Association (2002).

accounting for around 18 per centof city gas consumption in 2002.

The rapid expansion in city gasdemand has been driven to a largeextent by the development of gasdistribution networks throughoutthe country. Korea’s widespread gasdistribution system has enablednatural gas to penetrate the marketquickly, including in provincialareas (table 8). However, the Seoulregion is by far the largest con-sumer of city gas, with more than 6 million users at the end of 2001.

Patterns of gas useLNG consumption in Korea exhibits strong seasonal fluctuations. LNG usein the peak winter months (December–February) generally averages at leasttwice that in summer (KEEI 2002a, 2003a; figure 8).

Most of this seasonal variation is explained by city gas use in the residentialsector where about two-thirds of annual gas consumption occurs during thewinter season (KEEI 2002a, 2003a; figure 9). The peak in winter is associ-ated with high heating loads. Colder than average temperatures during wintermonths can further increase thepeak demand. The turndown ratio,the difference between the highestand lowest demand months, for thissector was 7.1 in 2002. That is, gasconsumption in the peak monthwas 7.1 times consumption in themonth of lowest demand.

Although city gas consumption inthe commercial sector is alsoaffected by winter temperatures, themonthly consumption pattern isless severe than in the residentialsector. The turndown ratio in 2002


LNG monthly consumption, by sector Korea

2000 2001DecDec Dec

2002

Mt

8Total

Electricity generation

City gas

0.4

0.8

1.2

1.6

2.0

City gas monthly consumption,by sector Korea

2000 2001DecDec Dec

2002

9

8

0.4

0.2

0.8

1.2

1.0

0.6

Industry

Commercial

Residential

billion m3

was around 2.8 in the commercial sector. The industry sector exhibits theleast monthly fluctuations in demand, with a turndown ratio of around 1.6in 2002.

LNG demand in the electricity sector exhibits little seasonal fluctuationcompared with that of city gas, although LNG demand for power generationcan also peak in winter (figure 8). This partly reflects maintenance sched-ules for base load coal and nuclear plants that increase demand for gas firedplants at that time.

The strong seasonal fluctuations in LNG demand evident in Korea havecreated supply and storage problems as contracted LNG deliveries have typi-cally taken place throughout the year. This has necessitated significant invest-ment in gas storage capacity at LNG import terminals.

Natural gas supply

Domestic gas reservesKorea’s only known gas reserves are in the Donghae field in the East Sea.Recoverable reserves in that field are estimated at around 6 billion cubicmetres, equivalent to just over 4 million tonnes of LNG. The Korea NationalOil Corporation (KNOC) plans to begin full commercial production of thisfield from late 2003. The Donghae-1 project is expected to deliver 0.4 milliontonnes of natural gas a year to KOGAS, or approximately 2 per cent ofKorea’s current gas demand (EIA 2002).

LNG importsThe government owned Korea GasCorporation (KOGAS) was estab-lished in 1983 and currently controlsLNG imports, LNG receiving termi-nals, the national gas distributionnetwork, and wholesale LNG salesin Korea. KOGAS supplies LNG tocity gas distribution companies andto electricity generators.

Korea is currently entirely depen-dent on LNG imports for its natural


LNG imports Korea10

1986 1990 1994 1998 2002

US$b

3

2

1

4Volume

Value

Mt

4

8

12

16

gas supply. Korea is the second largest importer of LNG in the world afterJapan, importing 17.8 million tonnes in 2002 (KEEI 2003a; figure 10).Indonesia has traditionally supplied the majority of Korea’s LNG; however,in recent years Korea has diversified its supply sources. In 2002, Indonesia,Malaysia, Qatar and Oman supplied more than 90 per cent of Korea’s LNGimports (table 9).

Currently, Korea purchases most of its LNG requirements under seven longterm take or pay contracts that account for 17 million tonnes of LNG (table10). New procurement of LNG is based on ‘The Basic Plan of Long TermLNG Supply and Demand’ issued by the Ministry of Commerce, Industryand Energy (MOCIE). Plans are revised every two years and the latest plan–– the sixth –– was released in November 2002 (MOCIE 2002a). Based onthe demand and supply projections in the plan, the government permitsKOGAS to directly negotiate an LNG procurement deal with the supplier.The government typically approves the new LNG contract, after KOGASand the supplier set the price and other terms and conditions. However,KOGAS is postponing entering into new long term contracts until plans torestructure the gas sector are progressed. The issue of gas market reform isdiscussed further in chapter 3.

Long term contractual supplies have typically not been adequate to meet therapid rise in Korea’s demand for LNG, particularly in the winter months.

9 LNG imports, by sourceKorea

Volume Shares

1990 1995 2000 2002 1990 1995 2000 2002

Mt Mt Mt Mt % % % %

Indonesia 2.29 5.26 6.13 5.02 99.5 74.2 42.6 28.2Malaysia – 1.04 2.44 2.30 – 14.7 16.9 12.9Brunei – 0.71 0.80 0.77 – 10.0 5.6 4.3Qatar – – 3.05 5.15 – – 21.2 28.9Oman – – 1.59 4.06 – – 11.1 22.8Australia – 0.06 0.05 0.18 – 0.8 0.4 1.0United ArabEmirates – – 0.24 0.23 – – 1.7 1.3

Other a 0.01 0.03 0.07 0.12 0.5 0.4 0.5 0.7

Total 2.30 7.09 14.37 17.83 100.0 100.0 100.0 100.0

a Includes cargo swaps with Japan and Chinese Taipei.Sources: KEEI; KOGAS (2003); BP (2003).


This has resulted in Korea also entering into short term contracts from theearly 1990s. At their peak, between 1996 and 1999, short term contractscontributed almost 4 million tonnes a year to Korea’s LNG supply. Korea isalso an active buyer of spot product, to cope with winter peak demand andis one of the largest markets for LNG spot trade in the world.

However, this reliance on the spot market has not always resulted in an opti-mal outcome for Korea. In winter 2002–03, for example, there was anunprecedented shortage of LNG in Korea and KOGAS had difficulty sourc-ing additional spot cargoes (see box 1). This recent experience has high-lighted the vulnerability of Korea’s current gas supply situation and theimportance of having adequate and secure long term LNG supplies.

More recently Korea has entered into midterm contracts with Australia andMalaysia to supply 0.5 and 1.5–2.0 million tonnes of LNG a year respec-tively for seven years, beginning in late 2003. Delivery schedules in thesecontracts are heavily biased toward winter supply. Under the contract withNorth West Shelf Australia LNG, 100 per cent of the contracted volume willbe delivered in the winter months.


10 Existing mid and long term LNG contractsKorea

Source Project name Amount Agreement period

Mt/yrLong termIndonesia Arun III 2.30 1986 – 2007Indonesia Korea II 2.00 1994 – 2014Indonesia Bontang V 1.00 1998 – 2017Malaysia MLNG II 2.00 1995 – 2015Brunei BLNG 0.70 1997 – 2013Qatar Ras Laffan 4.80 1999 – 2024Oman OLNG 4.06 2000 – 2024

Total 16.86

MidtermMalaysia MLNG Tiga 1.50 a 2003 – 2009Australia NWS Australia LNG 0.50 2003 – 2009

Total 2.00

a The contract includes an option for an additional 0.5 million tonnes.


Box 1: Korea’s LNG supply shortfall in winter 2002–03An unprecedented domestic shortage of LNG during winter 2002–03 requiredKOGAS to source additional supplies on international markets. KOGASpurchased a reported record 42 spot cargoes that winter, totaling around 2.5million tonnes. This was equal to nearly 15 per cent of Korea’s contracted LNGvolumes at that time. Arrangements were also made with suppliers to redirectcargoes from other existing contracted customers, including some Japanesepower companies, to Korea. In comparison, in the previous winter KOGASpurchased 22 spot cargoes.

The domestic supply shortage that necessitated such unprecedented access tothe spot market was the result of a number of factors. There was a sharp andunexpected rise in LNG use by electricity generators during this period as LNGbecame relatively less expensive than oil. While LNG prices are linked to inter-national crude oil prices, there is a time lag before rises in crude oil prices filterthrough. LNG was therefore cheaper over this period because of the lag in LNGprice adjustment following the increase in crude prices.

Increased LNG demand by electricity generators coincided with an early start toa cold Korean winter, which boosted city gas demand by the residential sector.

The situation was exacerbated by limited spare international LNG shippingcapacity. This was related in part to Japan’s increased demand for spot LNGcargoes over the same period as the Tokyo Electric Power Company (TEPCO)increased its use of LNG in response to the closure of its nuclear plants.

Highlighting Korea’s difficulty in sourcing cargoes, KOGAS purchased threelong haul LNG cargoes from Algeria, redirected from Gaz de France, and isunderstood to have exceeded the prevailing prices for these cargoes by morethan 10 per cent.

To help alleviate the tight gas supply situation, the Korean government requiredpower plants running on LNG to switch to petroleum fuels. A nuclear plant under-going maintenance and repairs was also brought back on line earlier than planned.

Korea is likely to continue to require spot cargoes and short term contracts tomake up further projected supply shortfalls as KOGAS is currently delayingentering into new long term contracts for LNG until plans to restructure the gassector are progressed. In the interim, KOGAS has signed two midterm contractswith Australia and Malaysia to begin supplying in late 2003, which will allevi-ate the projected shortfall to some extent.

It has also been reported that KOGAS has reached an agreement with TohokuElectric Power Company in Japan to swap LNG cargoes when appropriate as ameans of avoiding a repeat of last winter’s LNG shortage. Unlike Korea, Japanconsumes more LNG in summer than in winter as a result of its relatively higherdemand for air conditioning. This mismatch in seasonal demand has in the pastlent itself to diverting LNG cargoes originally destined for Japan to Korea duringthe winter, subject to the consent of producers.

Sources: Reuters (2003a); Energy Argus (2002a,b; 2003a,b).

Gas supply infrastructureKorea currently has three LNG receiving terminals at Pyeongtaek, Incheonand Tongyeong (figure 11). These terminals are all owned and operated byKOGAS. POSCO, Korea’s largest steel producer, has commenced construc-tion of an LNG receiving terminal at Kwangyang that is expected to be inoperation in 2005. This will be the first privately owned terminal in Korea.


11 LNG import terminals and pipeline networkKorea

Pyeongtaek LNGterminal

Tongyeong LNG terminal

Donghae field

KwangyangLNG terminal (under construction)

Incheon LNG terminal

Seoul

Twenty-six LNG storage tanks arelocated at the three existing termi-nals: fourteen in Incheon, ten inPyeongtaek and two in Tongyeong.The total storage capacity at thethree terminals is 3 billion litres,equivalent to 2.2 million tonnes ofgas (table 11). The Incheon termi-nal is being expanded to includefour additional storage tanks a yearbetween 2002 and 2004 to meetprojected growth in LNG demand.According to the sixth Basic Planof Long Term LNG Supply and Demand, Korea will have an LNG storagecapacity of more than 7 billion litres (5.4 million tonnes) by 2015 (table 12).

In 2002, the operational length of the national gas pipeline network was 2442kilometres. In the sixth Basic Plan of Long Term LNG Supply and Demand,it is planned that a total of 2597 kilometres of nationwide pipeline will beoperational by 2010 (table 13). The network currently supplies natural gasto customers in around 60 cities, mainly through city gas companies.


11 LNG receiving terminalsKorea

Supply Storage Storage capacity capacity tanks

t/hr GL no.

Pyeongtaek 2 016 1 000 10Incheon 2 970 1 680 14Tongyeong 750 280 2

Total – 2 960 26

Source: KOGAS (2003).

12 Planned expansion of LNG storage tanks Korea

2001 2002–03 2004–05 2006–07 2008–10 2011–15

GL GL GL GL GL GL

New storage tanks 280 1 500 680 700 960 1 260Total storage tanks 2 280 3 780 4 460 5 160 6 120 7 380

Source: MOCIE (2002a).

13 Planned expansion of gas pipeline network Korea

2001 2002 2003–07 2008–10 2011–15

km km km km km

New pipeline 131 30 140 15 –Total pipeline 2 412 2 442 2 582 2 597 2 597

Source: MOCIE (2002a).

Gas pricing

LNG import pricesIn 2002, the average LNG importprice to Korea was US$223.80 atonne, equivalent to aroundUS$4.30/MBtu (million Britishthermal units). Prices since 2000have been considerably higher thanin previous years, as gas contractprices rose in line with movementsin international oil prices (KEEI2003a; figure 12). This reflectsstandard long term contract condi-tions in which up to 90 per cent ofthe LNG price is indexed to move-ments in international oil prices.

Wholesale and retail gas pricesThe KOGAS wholesale price for gas consists of a feedstock cost and a supplycost, the latter of which is differentiated by type of user and end use. Thismethodology is discussed in more detail in box 2. Gas supply costs for powerplants are differentiated on a seasonal basis, reflecting storage costs, hencesupply costs in winter are higher than in summer. The average wholesaleprice of gas to electricity generators was between 325 and 327 won (US$0.28)


Average LNG and crude oil import prices Korea

1990 1994 1998 2002

US$/t

12

US$/bbl

5

10

15

20

25

50

100

150

200

250Crude oil import priceright axis

LNG import priceleft axis

14 Wholesale gas price for power plants, January 2003Korea

For POSCO For others

won/m3 US$/m3 US$/MBtu won/m3 US$/m3 US$/MBtu

Feed stock cost 293.30 0.25 6.96 293.30 0.25 6.96

Average supply cost 31.41 0.03 0.75 33.26 0.03 0.79– for winter 40.71 0.03 0.93 42.56 0.04 1.01– for summer 22.12 0.02 0.52 23.97 0.02 0.57– for other seasons 31.41 0.03 0.75 33.26 0.03 0.79

Average gas price 324.71 0.28 7.71 326.57 0.28 7.75

Average exchange rate, January 2003, US$1=1170.5 won.Source: KOGAS (2003).


per cubic metre at January 2003 (table 14). This is equivalent to betweenUS$7.71 and US$7.75/MBtu.

The wholesale price for city gas (table 15) is higher than for power plantsand is different across end uses, including heating, industry and commercialuse. The feed stock cost for city gas was 305 won (US$0.26) per cubic metreat January 2003, while the average supply cost was 74 won (US$0.06) per

Box 2: Gas price setting procedures in KoreaThe regulation of natural gas prices in Korea is based on the City Gas BusinessLaw. The objectives of the regulations are to ensure that gas companies do notcharge customers unreasonable supply costs and to enable gas companies tosustain their business on a sound basis.

Rates are subject to approval from the relevant regulatory institutions. Wholesalegas supply rates need to be approved by the Minister of Commerce, Industryand Energy, while the rates for retail gas supply must be approved by the provin-cial government in its jurisdictional area.

For wholesale pricing, KOGAS adopts ‘cost of service’ as the principle of itsrate making system. This includes a predetermined reasonable return on invest-ment. The KOGAS wholesale price consists of a feedstock cost and a supplycost.

The feedstock cost is the sum of the LNG import price (cif) and additionaldomestic costs associated with LNG importing, including import tariffs andlevies, handling charges, a special excise tax, and a safety management fundcontribution.

Supply costs are determined by type of demand (that is, city gas and powerplants) and then by type of use. For power plants, use is based on season, whilecity gas uses include space heating, cooling, commercial, industry and cogen-eration/community energy system use. These rates are then divided by an esti-mated supply volume to produce unit prices.

To reflect changes in import prices in the wholesale price, KOGAS adjusts theLNG feedstock cost for power plants on a monthly basis and for city gascustomers every two months. The supply cost is subject to annual adjustment.

Local city gas companies design city gas retail prices by adding locally specificsupply costs to the wholesale price paid to KOGAS. That is, city gas retail ratesare determined by the cost to recover the total expenditure by the local distrib-ution company for supplying city gas to end users. The total cost of serviceincludes a reasonable return on investment as well as reasonably estimated totaloperating costs.

Source: KEEI.


15 Wholesale price for city gas, January 2003Korea

won/m3 US$/m3 US$/MBtu

Feed stock cost 305.08 0.26 7.24

Average supply cost 74.35 0.06 1.76House heating 104.18 0.09 2.47Commercial 41.11 0.04 0.98Cooling – – –Industry 29.51 0.03 0.70Cogeneration/CES– winter 66.84 0.06 1.59– summer – –– other seasons 29.51 0.03 0.70

Average city gas wholesale price 379.43 0.32 9.00


16 Retail price for city gas, Seoul area, January 2003

won/m3 US$/m3 US$/MBtu

Retail cost of service 43.09 0.04 1.02

Average retail price 422.52 0.36 10.03Heating– cooking 445.15 0.38 10.56– heating (house) 450.60 0.38 10.69– heating (apartment) 450.60 0.38 10.69– heating (building) 462.16 0.39 10.97

Commercial I 442.71 0.38 10.51Commercial II 399.09 0.34 9.47

Cooling 232.72 0.20 5.52

Industry 349.70 0.30 8.30

Cogeneration/CES: district heating– winter 379.64 0.32 9.01– summer 312.80 0.27 7.42– other seasons 342.31 0.29 8.12Cogeneration/CES: others– winter 405.08 0.35 9.61– summer 338.24 0.29 8.03– other seasons 367.75 0.31 8.73


cubic metre. Combining these costs, the average city gas wholesale pricewas 379 won (US$0.32) per cubic metre at January 2003, equivalent to aroundUS$9.00/MBtu. City gas for cooling is exempt from the supply cost charge,lowering its wholesale price, in order to encourage demand for gas coolingsystems, while cogeneration/community energy systems are also exemptfrom the supply cost charge during summer.

Table 16 shows city gas retail prices in the Seoul area in January 2003. Theretail price is the sum of the wholesale price for city gas and the retail costof service. The retail cost of service is the cost of supplying city gas to endusers. In Seoul this is calculated to be 43 won (US$0.04) per cubic metre.The average retail price in Seoul at January 2003 was 423 won (US$0.36)per cubic metre, equivalent to US$10.03/MBtu, although the price variedacross end uses.


factors affecting Korea’s futurenatural gas demandWhile natural gas demand is likely to grow strongly in Korea, a range ofissues will affect the extent and profile of future demand. These include envi-ronmental factors, energy security concerns, the pace of investment in gasfueled district heating systems, growing demand for cooling systems by theexpanding Korean middle class, and the implications of plans to deregulateKorea’s electricity and gas markets.

Environmental issuesUntil recently, environmental issues were generally given low priority inKorea in favor of economic expansion. As a result, most major cities andindustrial areas have significant environmental pollution problems. However,the environment and sustainable development, particularly in relation toenergy use, are emerging as some of the most important issues facing thecountry. Major regulations and policies to address environmental issues havebeen introduced since the Korean Ministry of Environment was establishedin 1990.

Energy related environmental policiesKorea’s energy related environmental policies focus principally on air qual-ity control in the electricity, industry and transport sectors. The 1990 AirQuality Preservation Act, for example, bans the construction of thermal powerplants that use fuels other than natural gas in the Seoul metropolitan area.This law also sets permissible emission standards for stationary and trans-port emission sources.

One of the main goals of long term energy policy in Korea is to create abalance between economic growth and environmental protection. Many poli-cies, at both the national and local government level, emphasise and encour-age substitution away from conventional fossil fuels such as coal andpetroleum, to relatively clean fuels, including natural gas. Mandatory airquality controls and stricter emission standards reinforce this trend.

31

3


In the industry sector, for example, recent trends indicate movement out ofcoal and oil into natural gas and electricity. In the iron and steel sector, naturalgas accounts for around 12 per cent of energy consumption (IEA 2002a).

Another relatively new source of demand for natural gas is the expansion ofcompressed natural gas (CNG) vehicles. More than 40 per cent of Korea’sair pollution is from motor vehicle emissions and in the Seoul metropolitanarea this source accounts for 85 per cent of total air pollutants. To reduce theemission of pollutants by motor vehicles the Korean government is promot-ing the use of CNG vehicles for public transport. The provisional operationof four CNG buses began in 1998 and has been gradually extended.According to government plans, 20 000 existing diesel buses will be replacedby CNG buses by 2007.

If this replacement plan is carried out as scheduled, natural gas demand inthe transport sector could account for a significant proportion of total gasdemand. To implement the plan, the Korean government is providing buscompanies with subsidies and tax incentives to purchase new CNG vehicles.In addition, a heavily discounted natural gas price is being offered and morenatural gas stations will be provided.

Climate change response policiesClimate change has become one of the focal points of environment and energyrelated policies in Korea. Korea has had the fastest growth in carbon diox-ide emissions from fuel combustion among OECD countries over the pastdecade: carbon dioxide emissions in Korea grew by 6.7 per cent a yearbetween 1990 and 2000, while the OECD average over this period was 1.2per cent a year (IEA 2002c). As a relatively low carbon intensive fuel, naturalgas is likely to benefit from increased emphasis on reducing the rate of growthin greenhouse gas emissions.

Korea established an Inter-Ministerial Committee on the United NationsFramework Convention on Climate Change in April 1998 comprised of repre-sentatives of relevant government agencies, academia and industry under thechairmanship of the Prime Minister to coordinate overall activities relatedto climate change policy. In December 1998, Korea developed its firstcomprehensive action plan for climate change policy (1999–2001). One ofthe major achievements of the action plan was the introduction of voluntaryagreements with the largest greenhouse gas emitting sectors –– includingiron and steel, petrochemicals and cement –– to reduce carbon dioxide emis-


sions and energy consumption. The government recently released the secondcomprehensive action plan (2002–04) in March 2002. This included a rangeof measures and expanded programs to stimulate efforts to ensure real green-house gas emission reductions and provisions for developing a national green-house gas emissions reduction target.

In November 2002 the Korean government ratified the Kyoto Protocol. Asa non-Annex B party to the protocol, Korea would not be bound by any emis-sion reduction targets if the protocol enters into force but would be eligibleto participate in projects under the clean development mechanism.

Security of energy supplyTo enhance energy security, a key objective of Korea’s energy policy hasbeen to diversify both the types and sources of fuel supply. This policy ledto the introduction of natural gas into the market in the mid-1980s and wasbehind the high level of government investment in natural gas infrastructurethat facilitated its expansion.

However, as discussed in chapter 2, oil remains the dominant source of energyin Korea, accounting for around half of primary energy consumption in 2002.In addition, around three quarters of crude oil imported by Korea is from theMiddle East. The Korean government is likely to continue to attempt toreduce oil dependency by promoting the development and use of alterna-tives to oil, including natural gas and nuclear power.

Overseas investmentThe government is further reducing the risks associated with imported energysupply through the promotion of equity participation in the exploration andproduction of overseas resources of oil, gas and coal. The government’sOverseas Resource Development Program, funded by the Energy SpecialAccount, encourages Korean companies to participate in overseas explo-ration and production business activities. Korea has equity investments, forexample, in Oman LNG and RasGas, in addition to long term LNG supplycontracts with these companies.

According to the Korean government’s second Basic National Energy Plan(2002–11), as much as 30 per cent of Korea’s natural gas supply by 2010could be sourced from projects or fields in which Korean companies have


invested (MOCIE 2002b). This target is likely to have implications for futuresources of natural gas supply for Korea.

New sources of demand

District heating systemsThe development of district heating systems throughout Korea is generatingnew demand for natural gas. A district heating system supplies large areas,including apartment complexes and office buildings, with heat produced bycombined heat and power plants or other large scale heat production facili-ties using various fuels, including natural gas.

District heating systems are generally part of larger community energysystems that provide the integrated supply of heating and electricity tocommunities. These systems are regarded as efficient, economical and envi-ronmentally friendly energy sources.

Because many communities in Korea are placing more emphasis on envi-ronmental protection, clean energy sources, including natural gas, are indemand for district heating systems. This is despite LNG being relativelymore expensive than other fossil fuels. Moreover, district heating systemsare usually located in major cities such as Seoul and Busan, where the useof fuels other than natural gas is prohibited under the Air Quality PreservationAct. LNG accounted for around three-quarters of energy consumption indistrict heating systems in Korea in 2000 (KDHC 2002; figure 13).

According to the Korean govern-ment’s Basic Plan for Mid to Longterm Supply of District Heating, itwill spend about 1.4 trillion won by2006 to provide district heating for426 000 new households (MOCIE2002c) (table 17). By 2006, about1.6 million households will benefitfrom district heating. This signifi-cant projected expansion of districtheating is likely to contribute tofuture growth in natural gas demandin Korea.


Fuel mix in district heating systems, 2000 Korea13

Oil 24.2%

LNG 75.8%

Cooling systemsSince the 1990s, rapid economic growth, rising personal incomes and moreaffluent lifestyles have stimulated greater demand for summer cooling inKorea. This trend is likely to continue as the penetration of cooling is notyet widespread throughout the country.

The uptake of electricity based cooling systems has increased the summerpeak level of electricity in recent years. As gas is a peak load fuel, the grow-ing demand for summer cooling is in turn creating new demand for naturalgas.

In addition to growth in electric cooling systems, gas cooling systems arealso likely to become more widespread in Korea, creating new direct demandfor natural gas. The diffusion of gas cooling systems is expected to ease tosome extent the seasonal imbalance of supply and demand in the natural gasindustry as LNG demand in summer begins to rise.

While gas cooling systems in Korea have been available for commercial usesince the mid-1980s, recent demand for residential gas cooling systems hasemerged as a result of the development of new small size cooling systemtechnology. By 2010, it is anticipated that there will be 175 000 residentialgas cooling systems across Korea, compared with 450 in 2002 (KOGAS2003).

The penetration of gas cooling systems will be assisted by government promo-tion policies, including a preferential low interest loan scheme for their instal-lation. KOGAS is also encouraging new demand in this area with its ownassistance program that provides subsidies to customers to install gas cool-ing systems.


17 Mid to long term projections for district heating supplyKorea

2002 2003 2004 2005 2006

New residences ’000 101 79 117 152 78Total residences ’000 1 166 1 245 1 362 1 514 1 592

New investment bill won 310 468 303 232 100Total accumulatedinvestment bill won 310 779 1 081 1 313 1 413

Source: MOCIE (2002c).

Energy market reformKorea is in the process of deregulating the electricity and gas industries inorder to introduce competition and to enhance efficiency in these key energymarkets. This follows the deregulation of the petroleum industry that occurredin the late 1990s.

In 1999, the then Korean government announced plans to restructure theelectricity industry, including the privatisation of the state owned monopolyKorea Electric Power Corporation (KEPCO) (MOCIE 1999a). In the sameyear, the government announced a plan to restructure the gas industry andto privatise the Korea Gas Corporation (KOGAS) (MOCIE 1999b). The keyobjectives of the proposed reform programs were to introduce competitioninto these monopoly sectors, to enable long term, stable and cost effectiveenergy supplies and to increase consumer benefits through the expansion ofconsumer choice.

Electricity market reformThe fundamental elements of the former government’s Basic Plan forRestructuring the Electricity Industry included:

■ unbundling of the generation, transmission and distribution sectors ofKEPCO;

■ restructuring of KEPCO’s generation assets into six companies, includ-ing one company to hold KEPCO’s nuclear and hydro assets;

■ separation of KEPCO’s distribution assets into six companies;

■ privatisation of the non-nuclear and hydro generation companies and thedistribution companies; and

■ phasing in of wholesale and retail competition, with full retail competi-tion from 2009.

In the first phase, KEPCO was separated into a power generation businessand a transmission/distribution business, and the generation assets weredivided into the proposed six generating companies in April 2001. The sixgenerators currently compete among themselves and independent powerproducers in a cost based pool market –– a transitional step to wholesalecompetition –– by bidding available capacity on a daily basis.


Other reforms undertaken to date include the establishment in April 2001 ofthe Korea Power Exchange (KPX), an independent nonprofit organisationresponsible for operation of the wholesale electricity market. The KoreaElectricity Commission was also established at the same time to overseeKPX and the electricity market and to implement industry reforms.

However, since the appointment of the new administration in early 2003,reforms in the electricity sector have stalled. This is a result of the new govern-ment’s intention to review the privatisation plans of its predecessor. Keyfactors driving the review are concerns to ensure that efficiency increasesare realised, concerns about privatising natural monopoly industries if suffi-ciently strong regulatory frameworks are not in place, and a desire to builda consensus for privatisation with labor groups. This reflects the generallymore cautious approach to economic reform of the current governmentcompared with its predecessor and has led to some uncertainty over the direc-tion and timing of further reform (see box 3).

In particular, the plan to privatise the five non-nuclear and hydro generatingcompanies has been delayed indefinitely. In March 2003 the governmentcanceled the sale of Korea South-East Power Company (KOSEPCO) –– thefirst company nominated for sale –– after all potential investors indicatedthat they would not be submitting final bids. This outcome was partly a resultof the uncertainty surrounding the new administration’s views on economicreform and the lack of clear market rules and a regulatory framework for theplanned power pool market. Regional and international economic uncer-tainty is also a key reason for the lack of interest from buyers. KEPCO isnow considering an initial public offering of a minority of the stock ratherthan the sale of a strategic stake through a tender process. However, this islikely to be delayed for some time, in order to ensure more favorable marketconditions (Energy Argus 2003c,d).

Also delayed is the planned division of KEPCO’s power distribution assets,scheduled to be split into six companies in April 2004. At present it is uncer-tain when and if this stage of reform will be implemented (Korea Times2003b). In the interim, KEPCO will continue to manage the transmissionand distribution sectors.

The introduction of the two way bidding pool system, scheduled for 2003,has also been delayed. It is understood that the earliest this operation couldbegin is April 2004. With the delay in the reform process, the timetable for


the introduction of full retail competition, planned from 2009, is now alsouncertain.

Given the uncertainties over the future of electricity sector reforms, it is diffi-cult to predict the impact that reforms could have on natural gas demand. In


Box 3: Economic reform under the Roh Moo-hyun administrationThe new Korean government under President Roh Moo-hyun took office in lateFebruary 2003. It inherited from its predecessor a number of plans for reformthroughout the economy, including privatisation plans for public entities inseveral sectors. These included the banks that had been nationalised during theAsian financial downturn of the late 1990s, as well as the railways, the elec-tricity sector and the gas sector.

Since coming to office, the government has emphasised the need for ongoingand consistent structural reform in order to strengthen Korea’s economic funda-mentals and to enhance external credibility. To do so, in addition to reform inthe above four major sectors, the government is focusing on further promotingmarket liberalisation, deregulation, privatisation and labor sector flexibility.

Privatising Korea’s banks, which are still around 25 per cent state owned acrossthe system as a whole, has been the key priority to date. The government recentlysold the Chohung Bank to the Shinhan Financial Group, although there werestrong labor protests over the issue. It is now targeting its stake in the KoreaExchange Bank.

Apart from the banking sector, all other privatisation plans that the governmentinherited from its predecessor are being reviewed. This move has led to someuncertainty over the timing and direction of further reform throughout the Koreaneconomy.

More broadly, a priority of the Roh government is to increase transparency andaccountability in the business sector. It has announced that it will continue toimplement policies that enhance market transparency and corporate governance,improve supervisory regulations in the accounting sector, and limit large Koreanconglomerates from controlling the financial sector. The government is alsotargeting improving labor relations, laws and institutions to global standards,by making the formal sector, particularly its unionised component, more flexi-ble, and by improving protection in the informal sector. Part of this policy willinvolve establishing socially cohesive labor management relations.

The government is also aiming for Korea to become a north east Asian busi-ness hub and to strengthen its economic ties in the region. To do so, it is imple-menting measures to foster investment, including greater fiscal, financial andtax support, as well as regulatory improvements.

Sources: MOFE (2003a,b); Korea Times (2003a); Economist Intelligence Unit (2003); AsiaPulse (2003).

a liberalised and privatised electricity sector, LNG demand for power gener-ation will be determined on a commercial basis. Greater competitive pres-sures faced by generation companies will provide incentives for costminimisation. This is likely to affect fuel procurement decisions as genera-tors give more weight to the cost of alternative fuels, including LNG.

Based on fuel costs alone, LNG in Korea is generally less competitive thanother fuels. However, when the total cost of generation, or the long runmarginal cost of electricity supply, is taken into account, there is evidencethat gas fired generation can be competitive against other fuels, includingcoal (see box 4). This is because gas fired plants typically have lower capi-tal costs, consume less land, have shorter construction times and lower oper-ating costs. Based on these comparative costs and higher fuel conversionefficiency relative to coal fired plants, private investors tend to favor gas firedplants over coal (Poten and Partners 2002).

The advantage of gas will be reduced, however, if investors, including publicinvestors, are not required to meet private sector rates of return on their elec-tricity generation assets. Nevertheless, the strong outlook for electricityconsumption growth in Korea and the advantages of natural gas suggest thatthere could be a more robust future for gas use in power generation in a dereg-ulated, competitive environment.


Box 4: Assessing the costs of electricity generationThe total cost of electricity generation has several components, including capi-tal expenditure for plant construction, operating and maintenance costs, and fuelcosts. In Korea, as elsewhere, the costof gas per kilowatt hour is higher onaverage than other energy sources,including coal, oil and nuclear (table18). In particular, LNG prices haveincreased in recent years in Korea,while those for coal have remainedfairly stable.

However, despite relatively high fuelcosts, gas fired power generation has anumber of economic advantages overcoal fired plants. These include easierproject financing, lower capital require-ments, less land, easier siting, shorterconstruction times, lower operating and

18 Fuel costs for electricity generation, 2000 Korea

won/kWh USc/kWh

Nuclear 4.4 0.3Imported coal 13.3 1.0Domestic coal 48.8 3.7Gas 87.1 6.6Oil 52.6 4.0Hydro 0.0 0.0Pumped storage hydro 17.8 1.3

Average 18.0 1.4

Source: IEA (2002d).


maintenance costs, including lowerlabor and water requirements, andgreater thermal efficiency. Assmaller plants, they also tend to bemore flexible in supply. Environ-mental advantages of gas firedplants include lower noise, fewerpollutants emitted into the localenvironment, and a significantlylower carbon intensity than coal.Figure 14 (FACTS Inc. 2002)shows that capital requirements andoperating costs for gas fired elec-tricity generation can in fact be lessthan half those for coal, contribut-ing to lower total costs at a range ofgas prices.

This conclusion is supported by data for the United States on electricity produc-tion costs for new plants for a variety of generation technologies, includingpulverised coal, gas combustion turbine, gas combined cycle, nuclear, solar

Electricity generation costs 80% load factor, 10% discount rate

USc/kWh

14

3

2

1

4

CoalGas at $4/MBtu

Gas at $3.5/MBtu

Gas at $3/MBtu

FuelOperatingCapital

19 Cost estimates for new generating plantsIn 2003 US dollars

Years to Plant Fixed Variable Base caseconstruct size Capital O&M O&M Fuel total cost

MW $/kW $/kW c/kWh $/MBtu c/kWhNuclear– DOE 5 600 1 821 60.84 0.045 0.43 5.0– Platts – – – – – – –Coal– DOE 4 400 1 122 25.21 0.319 1.27 4.0– Platts 3 400 1 028 18.342 0.183 0.81 3.7Gas CC– DOE 3 400 586 10.63 0.212 3.40 3.8– Platts 2 400 443 15.27 0.204 3.31 3.8Gas CT– DOE 2 120 457 8.50 0.319 3.40 6.1– Platts 1 120 347 5.09 0.046 3.31 10.3Solar PV– DOE 2 5 3 526 10.47 0.000 0.00 22.3– Platts 1 5 7 185 0.00 7.839 0.00 61.8Wind– DOE 3 50 976 27.15 0.000 0.00 6.6– Platts 1 50 896 0.00 1.018 0.00 5.9

Source: Drennen et al. (2003).

Gas market reformThe key components of the former government’s Basic Restructuring Planfor the Natural Gas Industry were to:

■ divide KOGAS into a gas import/wholesale business and a gas supply facil-ity (receiving terminals, pipelines and storage infrastructure) business;

■ separate the gas import/wholesale business of KOGAS into three inde-pendent companies in 2001, with the existing long term LNG importcontracts divided between the three;

■ privatise two of these companies and retain KOGAS ownership of thethird;

■ provide third party access to the facility sector; and

■ introduce competition in the retail sector, ending the regional monopolythat city gas companies currently enjoy.


photovoltaic and wind (table 19).These costs incorporate a range ofplant and economic assumptions,including capital, operating andmaintenance costs, fuel costs,construction times, and interestand discount rates. The data indi-cate that gas combined cycleplants can be the least cost elec-tricity generation alternative.

The advantage of gas, especiallyover coal, is likely to be higher atlow load factors as a result of thelower fixed costs of gas firedgeneration (figure 15). This rein-forces the benefits of gas as a fuelfor peak load electricity genera-tion. As the load factor increases,fuel costs become a more impor-tant component of total costs and the advantage of coal increases. In addition,if the required rate of return on investment is lower, say in the case of publicsector investment, the advantage moves more toward coal fired generation.

Sources: Poten & Partners (2002); Platts (2003c); FACTS Inc. (2002); Drennen et al. (2003); IEA(2002d).

Indicative long run marginal costs for power generation Korea

15

CCGT(gas)

Coal

Load factor (%)

$/MWh

As in the electricity sector, gas market reform has not progressed signifi-cantly over this period. The previous government had difficulty passing therequired legislation for the implementation of the proposals. Under the newadministration, the proposed reforms have been delayed further, with thegovernment proposing that a review be conducted before any reforms takeplace.

The government announced in March 2003 that the facility sector of KOGASwill maintain its present status as a state owned corporation –– that is, privati-sation of the LNG receiving terminals, storage infrastructure and pipelinenetwork will be excluded from any gas industry restructuring (Asia Pulse2003). It is anticipated, however, that the LNG receiving terminals, storageand pipeline networks owned by KOGAS will be opened to third party access.

In the import/wholesale sector of KOGAS, the government is consideringtwo options: the original plan to split KOGAS into three companies, or allow-ing private companies to import LNG alongside KOGAS under a licensingsystem (MOCIE 2003; Reuters News 2003b).

The previous government’s option for reform –– to split KOGAS into threecompeting businesses –– is considered problematic because the existingcontracts held by KOGAS are likely to be at higher average prices than futurecontracts. Hence, the new arrangements must involve a pooling of old andnew contracts to ensure the disposal of volumes under the take or pay system(FACTS Inc. 2003a) and the establishment of some competitive equitybetween the companies. The complexities involved in the reassignment ofcontracts is one of the reasons why the gas market reform process has beendelayed and why it is generally believed that the licensing system option ismore likely to be adopted.

Under the current industry structure, private parties can import LNG for theirown use, subject to several requirements. This has not occurred in Korea todate. However, there are currently plans by POSCO and SK Corporation tobegin importing LNG from 2005 through POSCO’s planned LNG receivingterminal in Kwangyang for own use in electricity generation facilities andsteel plants. If successful, this would represent the first element of compe-tition in Korea’s LNG supply (see box 5).

As with proposed reform in the electricity sector, the uncertainty surround-ing the timing and nature of reforms in the gas industry makes it difficult topredict the impact that this issue will have on future natural gas demand.


However, any transition to a more efficient and competitive industry struc-ture would have the potential to enhance the relative competitiveness ofnatural gas and therefore stimulate increased demand.

It is important to note, however, that the delay in implementing gas marketreform has some serious implications for Korea’s long term gas supply


Box 5: Entry of private LNG importers into the Korean gas marketWhile KOGAS has to date been the sole LNG importer in Korea, private compa-nies are in principle permitted to import LNG, subject to several requirements.These include that the gas be for own use, that the importer have adequate stor-age capacity, and that it negotiates access from KOGAS to the gas pipelinenetwork.

POSCO, Korea’s largest steel producer, currently holds a licence to import LNGfor its own consumption, which is around 0.5 million tonnes a year. In the past,the company has not imported LNG directly, relying instead on supplies fromKOGAS. However, POSCO is planning to begin importing LNG directly from2005. It is currently building an LNG receiving terminal in Kwangyang, with aplanned capacity of around 1.7 million tonnes a year. It is understood thatPOSCO is still negotiating with KOGAS over access rights to the pipelinenetwork.

POSCO’s decision to bypass KOGAS is reported to stem from the need to seekcheaper supplies of gas to boost competitiveness against other steel manufac-turers, including those from China. New international LNG contract prices havetended to be lower than prices under KOGAS’s existing import contracts, thefirst of which is not due to expire until 2007.

The planned import terminal is larger than POSCO’s own LNG needs andPOSCO has announced that it intends to supply LNG from 2006 to a new 900megawatt thermal power plant in Kwangyang planned by SK Corporation.

In March 2003, POSCO and SK issued a tender for the supply of up to 1.1million tonnes of LNG a year for twenty years from 2005. Of this, POSCOwould use around 0.5 million tonnes and SK between 0.35 and 0.6 million tonnes.A shortlist of two potential suppliers, MLNG Tiga and Tangguh, was announcedin May 2003.

If the Korean government chooses to implement a gas import licencing systemas a means of introducing competition into the gas market, POSCO, with likelyspare capacity at its import terminal, could be in a strong position to win a licenseand increase its import volumes for the purpose of reselling. It may also be thatthe move by POSCO and SK to import LNG directly will create the impetus forother companies to seek their own LNG imports.

Sources: FACTS Inc. (2003a,b); Reuters (2003c); Energy Argus (2003e,f); Energy IntelligenceGroup (2003a).

security. KOGAS’s current delay in entering into new long term LNGcontracts because of the uncertainties of reform means that the gap betweencontracted gas supply and projected demand is growing. Waiting for reformplans to be implemented before committing to new long term contracts isexacerbating this situation. As demonstrated in other countries, successfulgas market reform is a highly complex process that requires good planningand time to implement. It is not necessarily in Korea’s best interests to putpressure on the reform process in order to hasten the signing of new LNGcontracts, or vice versa. Delinking new LNG procurement decisions fromthe implementation of reform is possible if appropriate assignment ofcontracts is part of the reform process.

An important issue for Korea in this context is that the current LNG marketis highly competitive in terms of price and other contract conditions. Reportsof recent long term contracts signed by various suppliers with China, Japanand Chinese Taipei indicate that producers are able to meet buyers’ demandsfor lower prices and increased contract flexibility. By committing to newLNG contracts in this climate, Korea would also have the opportunity tobenefit from similar conditions. However, these market dynamics couldchange relatively quickly if new sources of demand, such as China and thenorth American west coast, materialised over the next several years. By delay-ing its commitment to new LNG contracts, Korea could be putting its abil-ity to secure equally favorable long term contract conditions at risk.


projecting natural gas demandin Korea

Analytical frameworkThe analysis of the potential demand for natural gas in Korea over the periodto 2015 presented in this chapter is based on simulation results fromABARE’s global trade and environment model (GTEM). GTEM is a multi-region, multisector, dynamic general equilibrium model of the world econ-omy. It is derived from the MEGABARE model (ABARE 1996) and theGTAP model (Hertel 1997).

GTEM is an appropriate framework for analysing energy markets becauseit takes into account the interaction between different sectors of the econ-omy and between economies through trade linkages. The model includes ahigh level of commodity disaggregation, including a detailed treatment ofenergy and energy related sectors and a sophisticated representation of tech-nological change and interfuel substitution possibilities in the energy sector.This enhances the capacity of GTEM to analyse the impacts of changes inenergy policies and other external factors that could influence the operationof energy markets.

Further information on GTEM is provided in appendix A and on ABARE’sweb site (www.abareconomics.com).

Regional and sectoral aggregationAt its most disaggregated level, the version of GTEM used in this studyconsists of equations and data that describe the production, consumption,trade and investment behavior of representative producers and consumers in45 regions across 55 sectors. The database used to simulate the potentialdemand for natural gas in Korea in this report has been aggregated to thefifteen regions and fifteen sectors presented in table 20.

The sectoral aggregation was chosen to include the three fossil fuels –– coal,oil and gas –– and electricity, and the major energy intensive industries thatare likely to influence total energy consumption. The regional aggregation

45

4


identifies major energy producing and trading regions, in particular existingand potential gas suppliers to Korea.

Developing a reference caseAs a dynamic general equilibrium model, GTEM requires a reference caseor a ‘business as usual’ scenario against which the impacts of alternativepolicies can be measured. The reference case projects the growth in key vari-ables in a region in the absence of any significant policy changes or exter-nal shocks. In this study, for example, the reference case represents the likelyoutlook for economic activity and energy demand in Korea over the periodto 2015 in the absence of any changes to key energy, environmental oreconomic policies.

The reference case also provides a benchmark against which the impacts ofpolicy initiatives, such as the deregulation of Korea’s electricity and gasmarkets, can be measured. For example, the impact of deregulation can beisolated by comparing economic growth, sectoral output and investment, gasconsumption and trade, and other variables in the policy simulation againstthose in the reference case scenario.


20 Regions and sectors in GTEM in this study

Regions Sectors

1 Republic of Korea 1 Coal2 Australia 2 Oil3 Canada 3 Gas4 United States 4 Petroleum products5 Japan 5 Electricity6 Western Europe 6 Iron and steel7 Eastern Europe and Russian Federation 7 Aluminium8 China a 8 Nonferrous metals9 Chinese Taipei 9 Chemicals, rubber and plastics10 Indonesia 10 Nonmetallic minerals products11 Malaysia 11 Other mineral products12 Rest of ASEAN b 12 Other manufacturing13 Rest of Asia 13 Trade and transport14 Middle East 14 Agriculture, fisheries and forestry15 Rest of World 15 Services

a Comprises mainland China and Hong Kong. b Comprises the Philippines, Singapore, Thailand andViet Nam.

To provide a numerical example,suppose that reference case gasconsumption at 2015 is projectedto be 30 million tonnes of oil equiv-alent (distance ab in figure 16).Following deregulation of the elec-tricity and gas sectors, gasconsumption at 2015 is projectedto be 33 million tonnes of oil equiv-alent (distance ac). This corre-sponds to a 10 per cent increase ingas consumption from the referencecase level (distance de). Hence theeffect of deregulation in this exam-ple would be to increase gasconsumption by 10 per cent rela-tive to the reference case at 2015.

Economic growthIn developing a reference case forKorea, several key assumptionshave been made. The first of theserelates to projected GDP growthrates in Korea and in other regions identified in the aggregation. The histor-ical growth rates used in the study from 1995 to 2001 are from theInternational Monetary Fund. Long term projections to 2015 are fromABARE and are derived by fitting an ARIMA (autoregressive integratedmoving average) forecasting model to the historical GDP data.

GDP in Korea is assumed to grow at an average annual rate of 5 per centbetween 2001 and 2015. While this projected growth rate is lower than theaverage achieved over the past fifteen years it, nonetheless, reflects a sustainedrecovery from the Asian financial downturn that led to a sharp contractionin GDP in 1998. Growth prospects for Korea in the medium term will remainhighly dependent on the strength of the world economy, particularly that ofthe United States. Given this uncertainty, a sensitivity analysis that assumesaverage annual GDP growth of 4 per cent over the outlook period is alsoconducted to examine the impacts that lower growth in Korea could have onenergy and gas consumption.


Deviation from the reference case in a GTEM simulation16

Mt

Policy simulation

Reference case

c

b

a

d

e

2001 2015 Time

2001

0

30

33

10

2015 Time

Deviation fromthe reference case (%)

Fuel mix in electricity generationAlso incorporated in the reference case are assumptions relating to the fuelshares in electricity generation. In GTEM, electricity production is modeledusing a ‘technology bundle’ approach. Under this approach, electricity isgenerated by a finite number of technologies, or fuels, with distinct fixedinput requirements. The power generation technologies in the model are coal,oil, gas, nuclear, hydropower and other renewables. The share of each fuelin total electricity generation is determined exogenously (outside the model)in the reference case, using government and other projections. In a policysimulation, substitution between fuels occurs in response to changes in rela-tive costs.

In Korea there is some debate surrounding the projected fuel mix in elec-tricity generation over the period to 2015. MOCIE published in 2002 a setof projections in its first Basic Plan of Long Term Electricity Supply andDemand that indicates a decline in the share of gas fired power generationover the period 2007–12 (MOCIE 2002d). This is a result of planned expan-sions in nuclear and coal fired capacity. MOCIE has indicated in subsequentdiscussions that its next set of projections is likely to incorporate highershares of gas fired electricity generation than those in the basic plan.

An alternative set of projections is published by the Korea Power Exchange(KPX 2002a). The KPX ‘most probable plan’ projections do not predict thesame magnitude of decline in the share of gas fired power generation overthat period, although a decline also occurs between 2007 and 2010 (figure17). Taking into considerationdiscussions with MOCIE andindustry representatives in Korea,current uncertainty surroundingfuture nuclear developments, envi-ronmental concerns over coal firedpower generation, and the relativecompetitiveness of gas fired powergeneration over the long run whentotal costs are taken into account,the KPX fuel share projections areused in this study.

As indicated in table 21, significantchanges are expected to occur in the


Alternative projections for share of gas fired power generation Korea

%

17

2003 2006 2009 2012 2015

4

8

12KPX (2002a)MOCIE (2002d)

fuel mix in electricity generation in Korea over the reference case. Based onKPX projections, nuclear power is likely to continue to be the main form ofelectricity generation over the outlook period, with its share increasing from39 per cent in 2001 to 46 per cent in 2015. This expansion is underpinnedby government policy responses to growing reliance on energy imports, asdiscussed in chapter 2. Five nuclear power plants are currently under construc-tion and an additional eight units are planned for construction by 2015.However, the long term development of nuclear power in Korea will have toovercome growing public resistance to the siting of new nuclear plants andwaste disposal. There are doubts among some analysts and industry repre-sentatives that these nuclear projections can be realised, given such concernsand previous delays in nuclear expansion in Korea. Experience in other coun-tries, including Japan and Chinese Taipei, reinforce a less optimistic expan-sion in nuclear power for Korea.

Coal is also expected to remain a major fuel for base load and midload elec-tricity generation in Korea, maintaining its share of the fuel mix at around38 per cent. The continued reliance on coal reflects the competitiveness ofimported bituminous coal in Korea relative to other fuels (table 18).

Gas is assumed to account for 11 per cent of electricity generation in 2015,similar to its level in 2001. This is despite an expected increase in the shareof gas fired generation in the first half of the outlook period. The projectedgrowth in nuclear and coal fired capacity is the main reason behind the limitedgrowth in gas fired electricity generation, as is the current high cost of LNGin Korea.


21 Projected share of electricity generation, by fuel, reference caseKorea

2001 a 2005 2010 2015

% % % %

Coal 38.7 38.4 44.2 37.8Oil 9.8 7.6 4.8 2.8Gas 10.7 13.2 6.7 11.2Nuclear 39.3 38.8 42.1 46.1Renewables 1.5 2.0 2.1 2.1

Total 100.0 100.0 100.0 100.0

a actual.Source: KPX (2002a).

Conversely, the share of oil fired electricity generation is expected to declinesignificantly over the outlook period, from 10 per cent in 2001 to 3 per centin 2015. This is driven principally by energy security concerns and the rela-tively high marginal cost of oil fired power generation.

The main risk in these assumptions is that Korea will not be able to realiseits ambitious targets for nuclear power expansion or that planned additionsto coal fired capacity will be slower than expected. In these circumstances,it is likely that the share of gas fired power generation would not decline overthe intermediate period. This could occur, for example, if gas fired capacitywere used at higher load factors than currently assumed.

Other assumptionsIn the reference case it is also assumed that:

■ the switch away from oil toward natural gas in Korea’s industry andcommercial sectors will continue over the projection period as access togas improves in line with the expansion of gas distribution networks andongoing policy efforts to increase gas consumption in these sectors.

■ the income elasticity of demand for coal by households in Korea is nega-tive. This means that as personal incomes rise in Korea, consumption of coal by households will fall. This reflects recent experience in Koreaindicating that the residential sector is moving rapidly away from coaland into cleaner and more efficient fuels, principally gas and electricity(KEEI 2003a: figure 18).

■ the household income elasticityfor gas and electricity is stronglypositive, implying that house-hold demand for gas and elec-tricity will grow more rapidlythan GDP. This reflects theimpacts of higher personalincomes on demand for cleanand convenient fuels in the resi-dential sector.

■ the capacity for Korea to meetits gas requirements fromdomestic sources is limited by alack of reserves. While there are


Residential consumption of coal, gas and electricity Korea

1990 1994 1998 2002

Mtoe

18

8

6

4

2

10

Coal

Electricity

City gas

plans for offshore gas production to commence in 2003, gas supplies fromthe Donghae field are unlikely to meet more than 2 per cent of Korea’stotal gas requirements. As a result, Korea is unable to expand domesticproduction significantly in response to increases in domestic gas demand.

■ energy market reform in Korea, particularly in the electricity and gassectors, will not progress over the outlook period, with no further reformsthan those already undertaken assumed to take place.

Reference case projectionsThe reference case projections presented here represent a possible outlookfor energy demand, and in particular natural gas demand, in Korea over theperiod to 2015, in the absence of any major policy changes or external shocks.The results, however, are not forecasts of what will actually happen in theregion. They are projections based on the set of assumptions outlined earlierthat are considered plausible at the present time. If these assumptions arerealised, the projections could provide a reasonable estimate of energy devel-opments in Korea.

Energy consumption, by fuel Underpinned by significant increases in economic output, energy consump-tion in Korea is expected to grow strongly over the period to 2015. Totalprimary energy consumption is projected to grow at an average rate of 3.5per cent a year, to reach 319 million tonnes of oil equivalent in 2015 (table22). This implies a continuing decline in Korea’s energy intensity over theoutlook period, reflecting efficiency gains in energy use in many sectors and

22 GDP and primary energy consumption, reference case Korea

Totalprimary energy

Real GDP a consumption

US$b trillion won Mtoe

2001 423.0 560.9 196.12015 843.0 1 117.9 319.0

Average annual growth % % %

2001–15 5.0 5.0 3.5

a 2002 prices and exchange rates.


continued restructuring of the econ-omy toward less energy intensivesectors.

When lower economic growth isassumed over the outlook period,growth in energy consumption isprojected to slow to 3.3 per cent ayear, to reach 310 million tonnes ofoil equivalent in 2015.

Natural gas consumption isprojected to grow by 5.0 per cent ayear between 2001 and 2015, from16.7 to 33.3 million tonnes (23.1 to45.9 billion cubic metres) (figure 19). Driving this growth will be the issuesdiscussed in chapters 2 and 3, including increasing pressure for industry touse cleaner and more efficient fuels for environmental reasons and escalat-ing demand for city gas by the residential and commercial sectors. However,the increase in overall demand for gas is moderated by continued improve-ments in the efficiency of gas use in industry and electricity generation. Theshare of natural gas in Korea’s primary energy mix is projected to increaseto 13.0 per cent at 2015, from 10.6 per cent in 2001 (figure 20). Under thelower economic growth assumption, natural gas demand is projected to reach32.2 million tonnes in 2015.

Coal consumption in Korea isprojected to grow more slowly thanin previous years, at an annual rateof 2.0 per cent, to reach 60.4million tonnes of oil equivalent in2015 (figure 21). Lower growth isa result of the reorientation of theeconomy toward less fossil fuelintensive forms of production suchas light industry and services, andan assumed substitution away fromcoal in the residential sector towardnatural gas. Underpinning much ofthe growth in coal consumptionwill be growth in electricity gener-


Annual growth in energy consumption, reference case,2001–15 Korea

%

19

4

3

2

1

5

RenewablesNuclear

GasOil

Coal

Renewables0.6%Nuclear

14.3%Gas

10.6%

Coal 23.3%

Renewables0.8%Nuclear

17.5%

Gas 13%

Coal 18.9%

2001

2015

20

Oil 51.2%

Oil 49.8%

Primary energy consumption,by fuel, reference case Korea

ation. As a result, coal will remaina major energy source over theoutlook period, although its contri-bution to the primary energy mixis projected to fall from 23 per centin 2001 to 19 per cent in 2015.

Demand for oil is projected to growby 3.3 per cent a year over theperiod to 2015. Oil is expected toremain the dominant source ofenergy in Korea, with its contribu-tion to total primary energyconsumption falling only margin-ally to around 50 per cent in 2015.A significant proportion of the growth in oil consumption is accounted forby the transport sector, which, in turn, reflects the impacts of high GDPgrowth and rising personal incomes on the demand for freight and passen-ger travel. Moderating the growth in oil consumption over the projectionperiod is a significant shift away from oil in the fuel mix for electricity gener-ation and government policies to reduce Korea’s reliance on oil. Also limit-ing oil demand growth are rising taxes on oil consumption, in line with anongoing government program designed to rebalance the taxation burdenacross competing fuels. These changes can be expected to increase the rela-tive cost of oil to industry and to enhance the competitiveness of natural gasfor industrial applications (table 23).

Nuclear energy is projected to be one of the fastest growing energy sourcesin Korea, driven by the increasing role it is assumed to play in electricitygeneration. Growth in nuclear power is projected to average 5.1 per cent a


21

2003 2006 2009 2012 2015

Mtoe

50

100

150

200

250

300 RenewablesNuclearGasOilCoal

Total primary energy consumption, by fuel, reference case Korea

23 Revision of special consumption taxes on fuel sourcesKorea Index of fuel prices after tax amendment (based on LNG at 100)

LNG Heavy oil Kerosene Diesel LPG

m3 litre litre litre litre

July 2002 100 84 175 200 194July 2004 100 85 189 238 238July 2006 100 87 205 252 277

Source: MOCIE (2002b).

year over the period 2001–15, to reach 55.9 million tonnes of oil equivalentat 2015, or around 18 per cent of primary energy consumption. Underpinningthese projections is the assumption that there will be sufficient investmentin nuclear power infrastructure to support the growth in consumption.However, as discussed earlier in this chapter, there remains significant publicopposition to the siting of proposed nuclear plants, making future projec-tions of nuclear consumption somewhat uncertain.

Demand for hydropower and other renewables is projected to grow by 5.5per cent a year over the period to 2015, although from a relatively small base.Much of this growth will be derived from government programs that focuson research and development ofalternative energy sources. Forexample, the government an-nounced the Alternative EnergyR&D Basic Plan in February 2001,which provides a framework withinwhich to develop alternative energysources, in particular, energyderived from wind and photovoltaicpower. Specific measures includeprovision of financial supportthrough low interest loans and pref-erential tax treatments and incen-tives, and by legislating thatKEPCO buy at least 1 per cent ofelectricity requirements fromrenewable sources (IEA 2002d).

Gas consumption, by sector Most of the growth in Korea’s gasconsumption will be driven by theresidential sector. In this sector, gasconsumption is projected to rise by5.7 per cent a year over the periodto 2015 (figure 22), to reach 14.4million tonnes (figure 23). Under-pinning this increase in demand isthe continued switch from coal andoil to natural gas. This is reinforced


22

%

1

2

3

4

5

6

ResidentialCommercialIndustryElectricity

Annual growth in gas consumption, reference case, 2001–15 Korea

23

2003 2006 2009 2012 2015

Mt

5

10

15

20

25

30ResidentialCommercialIndustryElectricity

Gas consumption, by sector, reference case Korea

by growing demand for gas cooling systems as incomes rise and technolo-gies for modular gas cooling units are further developed.

Gas consumption in the industry and commercial sectors is projected to riseat 6.4 per cent and 4.3 per cent a year respectively over the period to 2015,to reach 6.8 million tonnes and 2.8 million tonnes respectively. This will bedriven by continued government policies encouraging gas use, supported byinvestment in expanding the distribution network. Key factors behind thepush for greater gas use include environmental considerations, associated inparticular with the emission of sulfur dioxide particulates from consump-tion of heavy fuel oils, and continuing efforts to reduce oil dependence forenergy security reasons.

Consumption of natural gas in the electricity sector is expected to grow byaround 3.6 per cent a year over the period 2001–15, which lowers its sharein total gas consumption from 34 per cent in 2001 to 28 per cent in 2015.The assumed fall in gas fired electricity generation in the years 2007–10accounts for the fall in overall natural gas consumption shown in figure 23over this period.

Natural gas imports In Korea, with all natural gas currently imported in the form of LNG, changesin natural gas demand to date have been reflected in changes in LNG imports.As discussed previously, indigenous gas production in Korea is expected tobegin from late 2003 and to supply around 0.4 million tonnes a year to 2015.Pipeline natural gas may also formpart of the gas supply structure overthe longer term.

KOGAS currently has long termtake or pay contacts of 16.9 milliontonnes of LNG a year. It alsorecently negotiated two midtermcontracts of 2.0–2.5 million tonnesa year. However, a number ofKorea’s contracts will mature priorto 2015, the first being theIndonesian Arun contract thatexpires in 2007. This will leaveincreasing shortfalls in natural gas


24

Mt

5

10

15

20

25

30

2003 2006 2009 2012 2015

Projected unmet gas demandDomestic gas field supplyCurrent LNG supply contracts

Projected unmet gas demand, reference case Korea

supply to meet projected demand over the outlook period (figure 24). Basedon current contracts, the projected shortfall in gas supply could be as largeas 20 million tonnes by 2015 (table 24).

The projected gap between current contracted levels and projected demandover the outlook period is likely to provide a serious challenge for Korea inthe coming years. It also suggests that new long term LNG contracts will berequired to meet demand in the near future. As discussed earlier in the report,KOGAS is currently delaying entering any new long term LNG contractsuntil plans for gas market reform are progressed. This limits Korea’s gassupply options, however, and increases the likelihood that gas supply short-ages could occur in the coming years. Greater security of gas supply couldbe ensured by decoupling LNG procurement from plans for gas marketreform.

Until this issue is resolved, gas supply options include short and midtermLNG contracts and LNG spot cargoes. An additional option to meet naturalgas demand over the medium to longer term currently being evaluated byKorea is the introduction of pipeline natural gas. This issue, and its poten-tial to meet some of the projected gas supply shortfall over the period to2015, is explored in chapter 6.


24 Contracted gas supply and projected shortfall, reference caseKorea

2005 2010 2015

Mt Mt Mt

Indonesia 5.3 3.0 1.0Malaysia a 4.0 2.0 2.0Brunei 0.7 0.7 -Qatar 4.9 4.9 4.9Oman 4.1 4.1 4.1Australia 0.5 – –Total contracted LNG supply b 20.4 15.6 12.9

Domestic gas supply 0.4 0.4 0.4

Projected natural gas demand 23.9 24.2 33.3

Projected unmet gas demand 3.1 8.2 20.0

a Assumes 0.5 million tonne option on MLNG Tiga contract is utilised. b Includes POSCO/SK 1million tonne contract.

alternative policy scenarios

While the reference case presented in the previous chapter provides an outlookfor energy and natural gas demand in Korea over the period to 2015 undera reasonable set of assumptions, there are a number of issues that may influ-ence these outcomes. The reference case, for example, assumes that no furtherprogress is made to liberalise energy markets in Korea over the outlookperiod. However, as discussed in chapter 3, proposed reforms in Korea’selectricity and gas sectors could make a significant difference to market struc-ture and the dynamics of fuel procurement decisions.

Energy security concerns are also likely to remain a major focus of energypolicies in Korea over the outlook period. Yet Korea’s extreme dependenceon imports to meet its fossil fuel requirements makes it vulnerable to exter-nal shocks or disruptions, including interruptions to supply in key energyexporting countries. Indeed, Korea was subject to this form of disruption in2001 when LNG deliveries from Indonesia’s Arun plant were interrupted fora period of several months.

These two issues and their possible impacts on energy and natural gas demandin Korea are explored in this chapter using GTEM. In the first scenario, it isassumed that Korea’s electricity and gas sectors are progressively liberalisedover the period to 2010. The second scenario assumes that a proportion ofKorea’s LNG supplies is interrupted for a period of three months or sixmonths in 2005. Results of these scenarios are reported as deviations fromthe reference case.

Electricity and gas sector deregulation The key features of proposed deregulation in Korea’s electricity and gassectors were outlined in chapter 3. While there are many uncertainties aboutthe structure and timing of reform under the new administration in Korea,the analysis in this chapter assumes that the key reforms outlined in the basicplans for the electricity and gas sectors are fully implemented. That is,complete deregulation of the wholesale and retail electricity sectors and ofthe import, wholesale and retail natural gas sector is assumed to occur by2009.

57

5



Box 6: Benefits of deregulation in the electricity and gas sectorsThe broad principle underpinning reform of the electricity and gas sectors thathas occurred in many economies is that there are significant long term efficiencybenefits from allowing markets to play a greater role in determining what isproduced, consumed or invested. Experience of regulatory reform in economiesthat have already implemented liberalisation policies in these sectors providessome evidence of the type of gains that may be generated in energy markets,including productivity improvements, lower prices, more efficient investmentand wider consumer choice (Fairhead et al. 2002). Further, as energy is a funda-mental input to economic activity, lower energy prices are likely to have econ-omywide implications for the structure and level of economic output.

In general, it can be expected that economies, such as Korea, that have imple-mented only limited major reforms to date will benefit significantly from theimplementation of further comprehensive liberalisation initiatives in electricityand gas sectors. In this study, ABARE has drawn on the available economicliterature to estimate the potential productivity gains that could be derived fromelectricity and gas market liberalisation in Korea.

In the case of electricity market reform, a study undertaken by the Korea Institutefor Industrial Economics and Trade (1999) suggests that regulatory reform inthe electricity industry in Korea could lead to total factor productivity improve-ments of around 1.3 per cent a year over the reform period. Productivity gainsof this magnitude are estimated to lead to an 8 per cent reduction in electricityprices in Korea relative to the reference case over the period to 2010, as costsavings achieved through productivity gains are passed on to electricity usersin terms of lower prices.

These estimates of the potential price impacts of reform could be lower if, forexample, current electricity prices are subsidised or if the rate of return on assetsrequired by a private investor is higher than that received by the current govern-ment owner.

Estimates of the potential efficiency gains from reform of the gas market inKorea are more difficult to obtain. Most of the measurement of the productiv-ity impacts of gas market deregulation is confined to the United Kingdom, whereBritish Gas, a publicly owned, vertically integrated enterprise, was privatisedin 1986, and subsequent reforms adopted to allow competition to develop. Inthis context, the results of a study by Price and Weyman-Jones (1996) are usedto estimate the maximum potential productivity impacts that could be derivedfrom the implementation of comprehensive liberalisation programs in naturalgas sectors characterised by extensive regulatory barriers, such as Korea’s.

Based on this analysis, it is assumed in this study that comprehensive liberali-sation of Korea’s gas sector could lead to an increase in total factor productiv-ity of around 20 per cent relative to the reference case in 2010. This is becauseKorea’s gas sector is highly regulated and that reforms are yet to be implemented.These productivity improvements are phased in through equal annual


increments over the period to 2010. The productivity gains are estimated to leadto a fall in the price of gas by 18 per cent relative to the reference case at 2010.

Although there is a trend toward energy market liberalisation in many of Korea’strading partners, the analysis reported in this study assesses the impacts of energymarket reform in Korea’s electricity and gas sectors in isolation from energysector reform programs being adopted in other countries.

Because of its dependence on imports for natural gas supply, Korea stands togain as much from liberalisation among its trading partners as from domesticreforms. While domestic reform will contribute to lower prices, efficiency gainsfrom reform among major suppliers of gas, such as Indonesia and Malaysia, arelikely to result in even lower gas costs in Korea. These gains are demonstratedin ABARE’s recent study, Deregulating Energy Markets in APEC: Economicand Sectoral Impacts (Fairhead et al. 2002). Because extra-national gas marketreforms can enhance the gains in Korea from domestic reforms, the modelingresults for Korea in this study will differ from those in Fairhead et al. (2002).

This scenario represents the adoption in Korea of a comprehensive liberali-sation package involving greater reliance on market forces in electricitygeneration and retailing and gas imports and retailing –– areas where compe-tition is feasible –– and the design of an effective regulatory framework wherethere is a need for government intervention to address issues associated withnatural monopolies and externalities.

Liberalisation of this nature in electricity and gas markets is projected tohave both direct and indirect impacts on the Korean economy, including onenergy prices, consumption and trade (see box 6). Because the resultspresented in this study are based onassumptions, they should be viewedas illustrative only of the generalimpacts and direction of change thatcan be expected from regulatoryreform in Korea’s energy markets.

Economic impactsAs a result of enhanced productiv-ity and lower electricity and gasprices following deregulation (figure25), total demand for goods andservices in Korea expands relative to the reference case. This

25

–5

–10

–20

–15

% Electricity Gas

Change in energy prices following deregulation, 2015 relative to the reference case Korea

effect is reinforced by the resource allocation benefits of liberalisation –– thatis, the efficiency gains that are realised when resources are employed in theirmost productive end use as energy consumers and producers respond to pricesignals. As a result of these effects, Korea’s GDP at 2015 is 0.3 per cent higherthan its reference case level. This is equal to an increase in GDP at 2015 ofaround US$2.1 billion (2.8 trillion won) relative to the reference case.

Structural impactsUnderlying the rise in GDP in Korea is an improvement in the competitive-ness of industrial and commercial output resulting from higher productivityin the electricity and gas industriesand lower energy prices. In partic-ular, lower electricity and gas priceshave a favorable impact on the coststructures of energy intensive indus-tries such as iron and steel, chemi-cals and plastics, nonmetallicminerals and other manufacturing.This leads to an increase in thecompetitiveness of Korea’s energyintensive sectors relative to othersectors of the economy and relativeto energy intensive production inother economies. Consequently,demand for, and exports of, energyintensive goods rise relative to thereference case, together with theshare of energy intensive industriesin total economic output (figure 26).

Energy consumption impactsReflecting the fall in electricity andgas prices and increased economicoutput, electricity and gas consump-tion in Korea rise by 1.4 per centand 3.1 per cent respectively rela-tive to the reference case at 2015(figure 27). In the case of electric-ity, this is equivalent to an increase


26

%

0.2

0.4

0.6

0.8

1.0

Other manufacturesNonmetallic minerals

Chemicals, rubber and plastics

Iron and steel

ExportsProduction

Change in production and exports of energy intensive goods following deregulation, 2015relative to the reference caseKorea

27

%

1.0

0.5

1.5

2.0

2.5

3.0

ElectricityGasOilCoal

Change in energy consumption following deregulation, 2015relative to the reference caseKorea

in consumption of 6 terawatt hoursin 2015, to around 467 terawatthours. The increase in electricityuse is driven by higher demand bythe industry, commercial and resi-dential sectors. Greater demand forelectricity also increases the rela-tive demand for other fuels, includ-ing coal. Total primary energyconsumption is projected to rise to321 million tonnes of oil equivalentat 2015 (table 25).

The projected rise in natural gasconsumption relative to the refer-ence case at 2015 is equal to around1 million tonnes and total gasconsumption reaches 34.3 million tonnes (47.4 billion cubic metres). Therelative increase in gas consumption following deregulation is driven primar-ily by the enhanced competitiveness of gas as a fuel for electricity and resi-dential applications.

Gas consumption, by sectorThe largest growth in natural gas consumption following deregulation is inthe electricity sector (figure 28). Along with the rise in electricity consump-tion, there is an increase in the shareof natural gas in the fuel mix forelectricity generation in Korea, asgas becomes more competitive rela-tive to other fuels. The share of gasin electricity generation rises from11.2 per cent at 2015 in the refer-ence case to 11.8 per cent followingderegulation (figure 29).

The overall increase in gas con-sumption is moderated by theincreased use of electricity in somesectors relative to the reference case,particularly in industry. The switch


25 Projected energy consump-tion following deregulation, 2015 Korea

Reference case Deregulation

Mtoe Mtoe

Coal 60.4 61.5Oil 158.8 158.9Gas 41.4 42.6Nuclear 55.9 55.9Renewables 2.6 2.6

Total primary energyconsumption 319.0 321.5

Electricity 39.6 a 40.1 b

a Equivalent to 460 terawatt hours. b Equivalentto 467 terawatt hours.

28

Mt

ResidentialCommercial

IndustryElectricity

DeregulationReference case

2

4

6

8

10

12

Gas consumption by sector following deregulation, 2015Korea

toward gas following deregulationwould be expected to be larger ifgas market reform was undertakenindependently from electricitymarket reform, as the relativecompetitiveness of gas would beenhanced.

Impacts of a gassupply disruption As discussed in previous chapters,Korea currently depends entirely onLNG imports for its natural gassupply. While sources of supplyhave expanded over the past few years, four countries — Indonesia, Malaysia,Qatar and Oman — account for more than 90 per cent of Korea’s gas imports.In addition, three of Korea’s current seven long term LNG contracts are withIndonesia. As demonstrated by the events of 2001, this could leave Koreavulnerable to international shocks, including disruptions to LNG supply (seebox 7). As gas is an important input to economic activity, any interruptionto LNG supplies could be costly for the Korean economy.

In this scenario it is assumed that there is a gas supply disruption in 2005that decreases LNG deliveries to Korea and other countries in the north eastAsian region for a period of three months and six months. The disruption toKorea is equivalent to around 2 per cent and 4 per cent of its total LNGdemand respectively in that year.

In the scenario it is assumed that Korea continues to import the majority ofits LNG supplies under long term contracts, at contracted prices. As all othercontracted LNG supply to Korea continues as usual in the year of the disrup-tion, it is expected that these prices will not be affected.

To maintain LNG supply, Korea and other affected countries are required tosource additional cargoes from alternative suppliers, including the spotmarket. It is assumed that spot supplies and transport are available in thissituation, subject to shipping capacity constraints. However, it would be diffi-cult for suppliers to increase LNG production in the short term in responseto a sudden increase in demand.


29

%

10

20

30

40

RenewablesNuclear

GasOil

Coal

Fuel mix in electricity generation following deregulation, 2015Korea

DeregulationReference case

Given the likely increased demand and competition for spot cargoes, it isexpected that spot prices could rise significantly in the short term. Asdiscussed in box 1, with a tight international supply situation, Korea haddifficulty sourcing additional cargoes in early 2003 and in one case paid upto 10 per cent more than prevailing prices to secure a cargo.

Assuming that Korea has not signed any new term contracts for the period2003–05, it would already be meeting a significant shortfall of LNG ––around 3 million tonnes –– on the spot market or through short term contracts.The gas supply disruption would intensify the pressure to source additionalspot cargoes in that year, with a greater proportion of overall LNG demandmet by spot purchases.

During the period of disruption it is assumed that there is limited interfuelsubstitution in Korea. This is designed to reflect the short run nature of theanalysis as well as specific industry conditions that preclude the procurementof alternative energy supplies over that timeframe. Some substitution of nongasfired technologies –– coal, oil, hydro and nuclear –– in the electricity gener-ation sector is permitted, to represent excess capacity in those systems.


Box 7: LNG supply disruption to Korea in 2001In March 2001, security concerns in Indonesia led Exxon-Mobil to shut its ArunLNG complex in North Aceh for several months. The closure of the Indonesiangas plant had a direct impact on the supply of natural gas to Korea as Indonesiawas the largest single LNG supplier to Korea at that time. In 2001, KOGAS helda contract to import 3.4 million tonnes of LNG a year from Arun and Arun wascontracted to supply KOGAS with 20 per cent of Korea’s total annual gas require-ments in that year.

As a result of the disruption to contracted deliveries, involving several cargoesa month for the period of the disruption, Korea was required to seek alternativeLNG supplies to make up the shortfall. Indonesia was able to switch supply tothe Bontang LNG facility to cover some of the cargoes, while Korea was ableto cover its remaining requirements with spot cargoes from Malaysia and Brunei.An LNG swap deal was also arranged with Chinese Taipei and import sched-ules from other LNG suppliers were advanced.

While in this case Korea was able to source adequate additional LNG suppliesto meet its requirements, it was fortunate that the interruption to supply did notoccur in the peak winter months. Considering Korea’s seasonal gas demandpatterns, if the LNG supply disruption had occurred during that season, theimpacts on the gas sector and the broader economy could have been severe.

Sources: Doh (2001); Reuters (2001a,b).

The scenario demonstrates that a disruption in gas supply has impacts on thebroader economy, including on energy prices, energy consumption, sectoraloutput and national income. While this scenario involves an interruption toa relatively small proportion of Korea’s total gas supply, the effects of adisruption could be more severe than modeled here if it occurred duringKorea’s winter, when gas demand peaks, or if international LNG supplycapacity was tighter.

Energy price impactsThe impacts of a disruption to LNG supply are felt primarily on energy prices.Following a three and six month disruption, gas prices in Korea are projectedto rise by 2.6 per cent and 3.9 percent respectively relative to thereference case at 2005 (figure 30).This reflects the fact that a largerproportion of Korea’s total gasimports is now accounted for byhigher priced spot LNG cargoes. Asgas is a key fuel for electricitygeneration, electricity prices alsorise, by around 0.2–0.3 per cent rela-tive to the reference case at 2005.

Economic impactsHigher energy prices and inputcosts that follow the supply disrup-tion have a negative impact onKorea’s economy. Gross national income, for example, is lower than refer-ence case levels. It is projected that a three month gas supply disruption in2005 could result in GNP that is around US$96.5 million (74.7 billion won)lower than in the reference case in the same year. As the length of the disrup-tion period increases, the economic effects deepen. Following a six monthdisruption in gas supply, GNP is around US$142.6 million (110.5 billionwon) lower than in the reference case at 2005 (figure 31).

Sectoral impactsUnderlying the macroeconomic impacts in Korea are changes at the sectorallevel. As the gas supply disruption has an impact on gas and electricity prices


30

%

3 month

6 month

1

2

3

Natural gasElectricity

Change in gas and electricity price following a gas supply disruption, 2005 relative to the reference caseKorea

in Korea, the cost structures ofenergy intensive industries are nega-tively affected in the short termbecause there is limited interfuelsubstitution. Higher energy costsreduce the competitiveness ofenergy intensive industries, leadingto a contraction in demand for theiroutput. The most affected sectors inthis scenario are the nonmetallicminerals and iron and steel indus-tries (figure 32). Industries that areless energy intensive are alsoaffected, though to a lesser degree,depending on the contribution ofelectricity and gas use to their total cost of production.

Because industries that use electricity reduce their output relative to the refer-ence case, the electricity industry also contracts. Electricity production isbetween 152 and 222 gigawatt hours lower than in the reference case at 2005.

Gas consumption impactsAs expected, natural gas consumption in Korea is projected to decline rela-tive to the reference case at 2005 following the rise in gas prices that resultfrom the supply disruption. The fall in gas use is moderated by the limitedability of some users to substituteinto alternative fuels. Under thethree month supply disruptionscenario, gas consumption falls by2.1 per cent relative to the referencecase at 2005, or by around 0.5million tonnes (figure 33). Whensupply is interrupted for six months,gas consumption is projected to fallby around 3.1 per cent relative to thereference case, or by 0.8 milliontonnes in that year.

The results of this scenario highlightthe potential cost to Korea’s econ-


31

–150

–125

–100

–75

–50

–25

US$m

6 month disruption3 month disruption

Change in GNP following a gas supply disruption, 2005 relative to the reference caseKorea

32

–0.06 –0.04 –0.02 %

Electricity

Nonmetallic minerals

Iron and steel

Chemicals, rubber and plastics

Manufacturing

Services

Change in sectoral output following a gas supply disruption, 2005 relative to the reference caseKorea

6 month disruption3 month disruption

omy if reliable, secure supplies ofnatural gas are not ensured. Failureto resolve the issue of LNG pro-curement policy and the projectedgap between supply and demand assoon as possible could leave Koreavulnerable to gas supply shortfallsover the medium term and thesubsequent adverse economiceffects discussed in this scenario.However, Korea could reduce thelikelihood of supply interruptions ifit reduced its reliance on a smallnumber of suppliers by furtherdiversifying its LNG supply portfo-lio.


33

Mt

5

10

15

20

6 month disruption

3 month disruption

Reference case

Gas consumption following a gas supply disruption, 2005Korea

natural gas supply considerations Because Korea has limited indigenous gas resources, with the Donghaeproject expected to supply only 0.4 million tonnes a year, meeting the poten-tial increase in demand for natural gas will require significant increases ingas imports. This could be met either by expanding LNG imports or byconstructing natural gas pipelines to international sources of supply. Eachof these options has different cost profiles and other characteristics that willaffect its competitiveness and penetration in the Korean market.

Pipeline natural gas There is considerable support among government and industry in Korea forthe development of pipeline natural gas supplies, for both economic and

67

6


Sakhalin

Japan

34 Possible gas pipelines to Korea

Okka

Nigata

Pyeongtaek

Pyongyang

Shenyang

Irkutsk

Ulan-Ude

Chita

Manzhouli

Harbin

Lake Baikal

BeijingDalian

Seoul

Vladivostok

Tokyo

Khabarovsk

Russian Federation

Mongolia

China South Korea

North Korea

strategic reasons. While there are many pipeline projects that have beenproposed in the north east Asian region, only two projects are considered tohave realistic commercial potential as sources of supply into Korea over themedium term. These are pipelines from the Irkutsk region in eastern Siberiaand from Sakhalin Island in the Russian far east (figure 34).

IrkutskThe Russian Federation, China and Korea are conducting a joint feasibilitystudy into the supply of pipeline natural gas from the Kovykta field, in theRussian province of Irkutsk, to China and Korea. The results of the feasi-bility study are expected to be released in September 2003.

Natural gas deposits in the Irkutsk region are estimated at around 840 milliontonnes. The volume of gas supplied to Korea could reach 7 million tonnes(10 billion cubic metres) a year for thirty years. China has sought at least 15million tonnes (20 billion cubic metres) a year over the same period.

There are two proposed pipeline routes considered in the feasibility study.The first is overland from the Kovykta field through north eastern China andNorth Korea to Pyeongtaek, south of Seoul. The second route is overlandfrom Kovykta through north eastern China, then via a subsea pipeline fromDalian to Pyeongtaek, bypassing North Korea. Both the proposed pipelineroutes are around 4100 kilometres in length. The Korean Ministry of Financeand Economy recently estimated the total cost of the project to be US$11billion (Reuters 2003d).

It has been agreed by the Russian Federation, China and Korea that eachparty will construct the relevant portion of pipeline in its own territory.However, it is understood that there has been some difficulty in reaching anagreement between the parties on gas prices. China has reportedly soughtgas prices that are linked at least partly with coal prices rather than oil as intraditional LNG contracts. In contrast, the Russian Federation has advocatedthat the price should reflect gas prices for China’s west to east pipeline (DowJones 2003). Korea is believed to have sought gas prices that are 20–30 percent lower than current LNG contract prices.

The Korean government is optimistic that the Irkutsk pipeline could begindelivering natural gas to Korea by 2008–10. However, for a number of reasonsthis view is not shared by all. First, construction of the pipeline would take


a number of years to complete and would therefore need to begin quickly tobe operational within this timeframe.

Second, for Korea, at the end of the pipeline supply chain, the viability ofthe project depends to a large extent on China, including both its potentialnatural gas demand and infrastructure priorities. China’s potential demandfor natural gas is vast, generating some concern that China could absorb allpotential supply from Irkutsk for its own needs. Alternatively, China iscurrently investing large amounts of capital in building the west to east gaspipeline, and some commentators have questioned China’s willingness tocommit to two large pipeline projects in the same time period. There are alsoreports that China prefers to use domestic gas supplies and imported LNGand will be unlikely to commit to Russian pipeline gas before 2015 (Platts2003a,b).

In addition, there are potential security risks for Korea if the proposed pipelinetransits North Korea. However, such an option could also provide strategicadvantages as it could better integrate the North into the region and providethe country with both much needed energy and an alternative to nuclearpower (see box 8).

Given the uncertainties associated with the project, some reports havesuggested that the earliest the Irkutsk pipeline could deliver gas to Korea isaround 2012–13 and that a possible startup date could be after 2015 (Platts2003a,b,d; Wybrew-Bond and Stern 2002). Many of the uncertaintiessurrounding the pipeline project could be clarified when the results of thefeasibility study are announced.

Sakhalin 1Another potential source ofpipeline natural gas to Korea overthe period to 2015 is SakhalinIsland, although no feasibility stud-ies for a route to Korea have beenundertaken. The Sakhalin 1 devel-opment is dedicated to pipelinenatural gas for export. Reserves forthis development are estimated tobe around 354 million tonnes (485billion cubic metres) (table 26).


26 Sakhalin gas reserves

Field Application Reserves

billion m3

Sakhalin 1 Pipeline 485Sakhalin 2 LNG 500Sakhalin 3 Unassigned 970Sakhalin 4 Unassigned 540Sakhalin 5 Unassigned 600Sakhalin 6 Unassigned na

Preliminary total 3 095

na Not available.Source: Platts (2003a).


Box 8: A ‘gas-for-peace’ deal with North Korea – implications forpipeline projectsIt has been suggested, including by some in South Korea, that a ‘gas for peace’plan could form part of a possible solution to the current North Korean nuclearstandoff. Under such a plan, gas could be delivered to the North through theproposed Irkutsk pipeline, or alternatively from the Sakhalin 1 project, in returnfor the North dismantling its nuclear arms program. The proposed pipeline wouldpass through North Korea to supply customers in the South but could allow theNorth to access an agreed volume of gas per year as a transit payment.

Any such arrangement would effectively replace a 1994 accord with the UnitedStates that provided monthly shipments of fuel oil in return for North Korea’sguarantee that it would not pursue its nuclear ambitions. The 1994 accord stalledin late 2002 and oil shipments were halted after North Korea revealed that it hasa uranium enrichment program and later reopened its Yongbyon nuclear powerplant and withdrew from the nuclear nonproliferation treaty. North Korea hassince announced it is in possession of nuclear weapons and tensions have height-ened between North Korea, the United States and several other countries in northeast Asia.

North Korea is suffering a critical shortage of energy and its economy is closeto collapse. It recently announced that it will proceed with its plan to constructtwo new nuclear reactors with a combined generating capacity of at least 200megawatts. Under a ‘gas for peace’ deal, North Korea could be provided withsufficient natural gas to generate an equivalent volume of electricity.

There have been reports that the Russian Federation is likely to favor the proposal,not only because of the geopolitical and security implications but because itwould provide its gas fields with access to the South Korean market. However,the Russian Federation would be unlikely to provide natural gas to North Koreafree of cost, hence any supplies to the North could have to be built into the costof the gas supplied to the South. This could make pipeline natural gas lesscompetitive in South Korea against its established sources of imported LNG.Alternatively, the proposal could form part of a multilateral aid program to NorthKorea.

Such a proposal is still in the early stages of discussion and the North Koreanstance toward this and other such projects on regional energy cooperation remainsuncertain. Other problems include uncertainty surrounding any large scaleprojects in the North, the lack of gas infrastructure in the country, and issuesrelating to sovereign risk. In addition, neither of the proposed gas pipelines isscheduled to be constructed until at least the end of the decade. Nevertheless,the North Korean issue is likely to remain a key point for consideration in thedevelopment of any natural gas pipeline for the South.

Sources: KEEI (2003b); World Markets Research Centre Limited (2003); Energy IntelligenceGroup (2003b).

The distance from Sakhalin to Seoul is shorter than that from Irkutsk andwould imply lower pipeline construction costs. However, recent announce-ments suggest that any pipeline from Sakhalin 1 would target Japan as itsprincipal market. A US$15 billion scheme has been proposed to build a1900–2200 kilometre subsea pipeline that would supply around 6 milliontonnes (8 billion cubic metres) a year of Sakhalin gas to the Niigata or Tokyoarea in Japan from 2008 (Platts 2003b; Energy Argus 2003g).

It is unlikely, however, that Japan’s gas market, with its emphasis on LNG,will absorb the minimum volume of pipeline gas required for the project tobe viable in the medium term –– particularly in the light of recent LNGimport commitments by Japanese companies from the Sakhalin 2 project(Platts 2003e). These market factors could reduce the likelihood of theSakhalin 1 pipeline project proceeding, or at least postpone its developmentuntil there is sufficient market growth (Energy Intelligence Group 2003c).While it has been suggested that pipeline gas from Sakhalin 1 could be redi-rected or extended to Korea to enhance its viability, possibly via the North,there are no well developed plans at this stage (FACTS Inc. 2003a; Platts2003b).

Issues relating to pipeline natural gasNatural gas pipelines are characterised by high capital costs, long construc-tion times and often complex international transit issues. These and otherfactors are important in assessing the overall viability of pipeline projectsinto Korea and their competitiveness with alternative gas supplies.

In the first instance, the size and quality of natural gas reserves that providepipeline gas supplies will be a critical determinant of the viability of boththe Irkutsk and the Sakhalin 1 projects. These projects will be viable only ifthe gas reserve is large enough to recover the costs incurred in constructingthe pipeline and in bringing the gas to end markets. If clusters of reservesare located near the original development, this may increase the lifespan andviability of the project. The gas base must also be dependable, as continu-ity of supply is an essential issue not only for producers and consumers butalso for financiers and other parties involved in the project.

Because of the high capital costs of financing either of the proposed pipelineoptions, access to finance will be an important determinant of their viabil-ity. This is likely to involve both domestic and foreign capital. Well definedlegal, taxation and foreign exchange systems will be important in terms of


encouraging the appropriate flow of foreign funds. While it has been esti-mated that the Irkutsk pipeline project would cost around US$11 billion,there has been little discussion of how this will be financed.

The existence of a viable market will also be a prerequisite to the develop-ment of natural gas pipeline projects in Korea. As discussed above, there issignificant potential for future gas demand growth in Korea. However, exist-ing pipeline proposals have not targeted Korea as a priority market –– ratherthey have been extensions of planned pipeline to other markets, principallyChina and Japan. Hence the dynamics of these markets will be as importantfor the viability of the pipeline projects in Korea as the Korean market itself.

The viability issue will be compounded by factors associated with the tran-sit of gas pipelines through third countries. Transit fees, either financial or inkind through physical deliveries of gas, can add substantially to gas pipelinetransit costs, particularly if the pipeline must traverse more than one country.

In the case of the Irkutsk and Sakhalin pipelines to Korea, the transit issueis compounded by the geopolitical situation surrounding the relationshipwith North Korea. Transit of either pipeline project through North Koreacould present considerable risk for the security of South Korea’s gas supplies,However, as discussed in box 8, there could also be strategic advantagesassociated with such an option, including increased economic and energysecurity for North Korea and access to non-nuclear energy, and the easingof the current political tensions on the peninsula.

Further information on issues related to developing natural gas projects inKorea and the north east Asian region can be found in Park et al. (2002) andPark, Lee and Lee (2002).

Can pipeline natural gas compete with LNG?An important question regarding the implementation of any pipeline projectin Korea is whether pipeline natural gas can compete on a price basis withimported LNG. If pipeline natural gas is not price competitive with LNGthen there is little economic argument for pursuing a pipeline developmentto provide additional gas supply. In these circumstances, agreement to supplygas by pipeline would rely heavily on noneconomic factors such as enhanc-ing energy security through fuel diversification or increasing political stabil-ity and economic security on the Korean peninsula.


There is much speculation about whether pipeline natural gas can competeon a price basis with LNG imports into Korea. Given the absence of pipelinenatural gas in the north east Asian region, a direct comparison with LNGimport prices cannot be made.

As discussed earlier, Korea has reportedly sought gas prices from the Irkutskpipeline project that are 20–30 per cent lower than current LNG contractprices. Such prices could enable pipeline gas to compete with LNG and allowfor some fall in LNG prices over time.

However, some analysts believe that pipeline natural gas cannot be deliv-ered to Korea at such a discount to LNG prices. For example, at distancesgreater than 4000 kilometres, LNG is generally considered to be a more costeffective form of gas transport than pipeline. At around 4100 kilometres, theIrkutsk pipeline is therefore unlikely to have a transport cost advantage overimported LNG (Energy Argus 2002c; Platts 2003a,b).

Further, average LNG contract prices to Korea are likely to fall over theperiod to 2015 as existing contracts expire, making it more difficult forpipeline natural gas to compete with LNG. The downward trend in priceswill be the result of new technology and production methods, lower ship-ping costs and greater competition. The terms and conditions on which LNGis available are also likely to become more flexible (Platts 2003a).

Economic factors aside, pipeline natural gas may still form an important partof Korea’s gas supply mix in the medium to longer term. This could occurif noneconomic factors, including security and geopolitical concerns, areemphasised in the decision making process.

Natural gas supply and demand balanceAn indicative natural gas demand and supply balance for Korea is providedin figure 35 that sees new pipeline gas supply complementing existing LNGsupply toward the end of the outlook period. The balance is based on the setof demand projections for Korea that were developed in chapter 4, in whichgas demand is forecast to reach 33.3 million tonnes at 2015, and existingmid and long term LNG supply contracts. The balance assumes that 0.4million tonnes of natural gas a year is provided from Korea’s Donghae gasfield. It also assumes that POSCO and SK Corporation import 1 milliontonnes of LNG a year from 2005, as currently planned. In addition, pipeline


natural gas supply from Irkutsk is assumed to commence from 2010 and isramped up to 7 million tonnes of gas a year by 2013.

On the basis of these assumptions, there is projected to be a natural gas supplyshortfall of 13.0 million tonnes at 2015 (table 27). The supply gap becomesmore significant after 2010, when stronger growth in natural gas demand isforecast than in the earlier part of the outlook period. This shortfall is likelyto be met by new LNG import contracts. The need for additional LNGcontracts could be greater if the Irkutsk project (or other pipeline options)are delayed beyond 2010 or are not able to supply 7 million tonnes of gas ayear (see box 9).


27 Potential natural gas demand and supply balanceKorea

2005 2010 2015

Mt Mt Mt

Projected gas demand 23.9 24.2 33.3

Assumed total gas supply 20.8 20.4 20.3– KOGAS LNG long term contracts 16.9 14.6 11.9– KOGAS LNG midterm contracts a 2.5 – –– POSCO/SK LNG contract 1.0 1.0 1.0– Donghae gas field 0.4 0.4 0.4– Pipeline natural gas, Irkutsk – 4.4 7.0

Supply shortfall/market for additional LNG 3.1 3.8 13.0

a Assumes 0.5 million tonne option on MLNG Tiga contract is utilised.

Potential natural gas demand and supply balance Korea

Mt

35

5

10

15

20

25

30

2003 2006 2009 2012 2015








Box 9: Alternative natural gas supply and demand balanceAs discussed in this chapter, some analysts express doubts that the Irkutskpipeline from eastern Siberia could begin supplying natural gas to Korea by2008–10. Such a delay could occur for a number of reasons, including uncer-tainties over the project’s economic viability, difficulty in resolving transit issues,a postponement by China in committing to the project, and delays in the construc-tion process.

Given this possibility, a less optimistic view of the Irkutsk pipeline project ispresented in the following alternative supply and demand balance (figure 36).This balance assumes that pipeline gas supply to Korea does not commenceuntil 2014. The volume of gas supplied in 2014 is assumed to be around 5 milliontonnes, ramping up to 7 million tonnes the following year

Alternative natural gas demand and supply balance Korea

Mt

36

5

10

15

20

25

30

2003 2006 2009 2012 2015







28 Alternative natural gas demand and supply balanceKorea

2005 2010 2015

Mt Mt Mt

Projected gas demand 23.9 24.2 33.3

Assumed total gas supply 20.8 16.0 20.3– KOGAS LNG long term contracts 16.9 14.6 11.9– KOGAS LNG midterm contracts 2.5 – –– POSCO/SK LNG contract 1.0 1.0 1.0– Donghae gas field 0.4 0.4 0.4– Pipeline natural gas, Irkutsk – – 7.0

Supply shortfall/market for additional LNG 3.1 8.2 13.0

In these circumstances, Korea would need to secure additional LNG contractsof around 3 million tonnes by 2005 and further term contracts to meet theprojected shortfall in the remainder of the outlook period. Failure to contractadditional medium to long term gas supplies is likely to leave Korea vulner-able to gas shortages and to exacerbate the difficulties it has experienced inrecent years.

Supplying LNG to KoreaAn additional 13 million tonnes of LNG a year or greater in the Koreanmarket would add significantly to Asia Pacific LNG trade. It would alsoprovide a strong incentive for LNG producers to invest in new productioncapacity to ensure reliable supply to an expanding market.


29 LNG trade in the Asia Pacific, 2002

Importer

Japan Korea Chinese Taipei TotalExporterIndonesia Mt 17.08 4.95 3.03 25.06Malaysia Mt 10.59 2.26 2.08 14.93Qatar Mt 6.13 5.07 – 11.21Australia Mt 7.10 0.18 – 7.27Brunei Mt 5.80 0.76 – 6.56Oman Mt 0.80 4.00 – 4.80Unites Arab Emirates Mt 4.33 0.23 – 4.56United States Mt 1.24 – – 1.24

Total Mt a 53.10 b 17.56 5.11 75.77

a Includes a cargo swap from Korea to Japan of 0.04 million tonnes. b Includes a cargo swap fromJapan to Korea of 0.11 million tonnes.Source: BP (2003)

A delay in the delivery of pipeline gas of this magnitude would increase Korea’spotential gas supply shortfall over the outlook period and would put further pres-sure on the demand for additional LNG contracts. Under the less optimisticscenario, Korea’s potential supply shortfall at 2010 could be around 8.2 milliontonnes, rising to 13.0 million tonnes in 2015. If the pipeline is delayed further,say beyond 2015, then Korea’s gas supply shortfall in 2015 could be as high as20 million tonnes.

The objective in this section is to assess LNG supply capacity to meet Korea’spotential demand and to examine some of the factors that could affect thecompetitiveness of alternative LNG suppliers in the Korean market. Issuesrelevant to this assessment are the size and distribution of gas reserves, exist-ing and planned LNG export capacities, transport and other cost considera-tions, and the reliability and security of potential suppliers.

Geographical separation and transport costs mean that LNG pricing, demandand supply in the Asia Pacific market are relatively distinct from and unaf-fected by the Atlantic basin market although there can be some spilloverbetween markets, especially in spot trades. Because Korea falls firmly withinthe Asia Pacific region, this section focuses on the dynamics of that market.

The Asia Pacific market dominates world LNG trade. In 2002, total worldLNG trade was 110 million tonnes, of which Japan, Korea and Chinese Taipeiaccounted for almost 70 per cent. Of the eight LNG exporters to the AsiaPacific market, Indonesia is the largest followed by Malaysia, Qatar andAustralia (table 29).

Natural gas reservesProved recoverable reserves of natural gas –– defined as the volumes in placethat geological and engineering information indicates with reasonable certaintycan be recovered in the future from known reserves under existing economicand operating conditions –– held by the group of eight existing LNG exportersto the Asia Pacific market areconsiderable (figure 37).

The most significant gas reservesare in Qatar. Together with thoseof the remaining Asia Pacific LNGexporting countries, the groupcollectively accounts for 22 percent of total world proved recov-erable reserves. The RussianFederation and Iran have theworld’s largest reserves (48 and 23trillion cubic metres respectively,equivalent to 35 and 17 billiontonnes), and while they do notcurrently export LNG, both have


37

trillion m3

Brunei

Oman

Malaysia

Australia

Indonesia

United States

United Arab Emirates

Qatar

0 2 4 6 8 10 12 14

Proved recoverable reserves in countries exporting LNG to theAsia Pacific market, 2002

plans to do so in the future. It should be noted, however, that not all the gasreserves identified in any country will be available for liquefaction.

LNG production capacityThere are currently twelve LNG plants in the eight countries that supply theAsia Pacific market (table 30). Indonesia has the largest operating capacityfollowed by Malaysia, Qatar and Australia. Collectively, the total capacityof all existing plants in the market is about 90 million tonnes a year.Approximately 80 million tonnes a year or 89 per cent of this capacity is tiedup in medium or long term contract commitments to established buyers. Theremaining 10 million tonnes a year capacity is sold through short termarrangements, on the spot market or remains unused.

This modest production overcapacity has, in part, been the product of contractcancellations and weaker than expected demand among Asia Pacific buyers,particularly in Japan and Korea, as a result of the effects of lower economicgrowth. Market demand is, however, expected to be robust over the comingdecades as the energy sectors of established buying countries resume stronger


30 Existing LNG plants, Asia Pacific market

Number of Operating CurrentCountry Project Customers trains capacity contracts

Mt/yr Mt/yr

Australia North West Shelf Japan 3 7.5 7.3Brunei Lumut Japan, Korea 5 7.2 6.7Indonesia Arun I-III Japan, Korea 4 6.8 6.8

Bontang A-H Japan, Korea,Chinese Taipei 8 22.1 19.5

Malaysia Bintulu MLNG I Japan 3 7.6 8.3Bintulu MLNG II Japan, Korea,

Chinese Taipei 3 7.8 6.9Bintulu MLNG III Japan, Korea 1 3.4 3.4

Oman OLNG Japan, Korea 2 6.6 4.7Qatar Qatargas Japan 3 7.7 6.0

Rasgas Korea 2 6.6 4.8United Arab

Emirates Das Island Japan 3 5.5 4.7United States Alaska Japan 1 1.5 1.2

Total 90.3 80.3

growth. New LNG buyers, including China, India and the United States westcoast, could also provide a major demand stimulus.

Compared with these strong demand projections, there are limited new gassupply projects under construction in the region. Projects under construc-tion include Australia’s North West Shelf Train 4 and the Bayu Undan projectin the Timor sea and Malaysia’s MLNG Tiga Train 2 (table 31). Togetherwith projects in the Middle East, these projects could deliver an additional18.6 million tonnes a year, with start dates from 2003 to 2006.

Other projects in the region are at various stages of planning and approval.These include Australia’s North West Shelf Train 5, Sunrise and Gorgonprojects, and others in Indonesia, Brunei, the Middle East and the RussianFederation. If these greenfields projects are to proceed, however, they willneed to be underpinned by secure long term contracts that ensure theireconomic viability and access to finance. The potential demand from Koreaif converted to contracts could provide the necessary incentive for produc-ers to proceed with some of these developments.


31 LNG plants under construction and planned, Asia Pacific market

Operating Number of StartupCountry Project capacity trains date

Mt/yrProjects under constructionAustralia North West Shelf Train 4 4.2 1 2004

Bayu-Undan 3.0 1 2006Malaysia Bintulu MLNG III Train 2 3.4 1 2004Oman OLNG T3 3.3 1 2005Qatar Ras Laffan 4.7 1 2004Total 18.6 5

Projects planned or proposedAustralia North West Shelf Train 5 4.2 1 2007

Gorgon LNG 5.0 1 2008+Sunrise 7.5 2 2007+

Brunei Lumut II 4.0 1 2008+Indonesia Bontang I 3.0 1 2005+

Tangguh 7.0 2 2007Qatar Ras Laffan 4.7 1 2005Russian

Federation Sakhalin 2 9.6 2 2007

Competitiveness of alternative LNG suppliersA range of factors will influence the competitiveness of alternative potentialLNG suppliers into the Korean market. Transport costs will be one suchfactor and these will be affected to a large extent by distance. A summary ofrelevant transport data for existing LNG suppliers to the Korean market isprovided in table 32.

Suppliers to Korea fall into three groups. The first comprises those fromBrunei, Malaysia and Indonesia, from where transport costs account foraround 10–15 per cent of delivered LNG costs. Transport costs for the secondgroup, consisting of Australia and the United States (Alaska), are higher ataround 20 per cent of landed LNG prices. Middle Eastern suppliers makeup the third group. These are furthest from the Korean market, with ship-ping costs representing 30 per cent of delivered LNG costs.

While price will be a key factor influencing the competitiveness of potentialsuppliers into Korea, nonprice issues will also be important. These includethe capacity of a supplier to negotiate flexible contracts in areas such asseasonal delivery patterns, realistic take or pay provisions and make goodand resale provisions. The ability to offer flexibility in such matters will oftendepend on a supplier’s overall contract commitments and the capacity tobalance supply commitments in different markets.

Given the seasonal nature of Korea’s gas consumption, with strong demandpeaks in the winter, flexibility and timing of delivery are also likely to influ-


32 Indicative LNG transport costs to Korea from various exporters,2001

Shipping cost,Distance, Time, share ofone way round voyage delivered price

nautical miles days %

Australia 3 633 19 20Indonesia 2 493 14 15Malaysia 2 124 12 15Brunei 2 082 12 10Oman 5 694 28 30Qatar 6 156 31 30United Arab Emirates 6 093 30 30US Alaska 4 027 21 20

ence the relative attractiveness of one source of LNG over another. Korea’srecent midterm LNG contract with North West Shelf Australia LNG, forexample, will deliver all the contracted volume in the winter period.

Less tangible factors that are likely to be important determinants of competi-tiveness in the Korean market are the reliability and security of supply, and thecapacity to contribute to overall energy security through the diversification ofenergy supply sources (see box 10). This issue has formed a key part of Korea’senergy policies and fuel procurement decisions. These factors will tend to favorpolitically stable economies, including Australia, and tend to discriminateagainst regions where instability could increase the risks associated with invest-ing in LNG infrastructure and hence Korea’s overall gas security position. Thedisruption of part of Korea’s gas supply in 2001 demonstrated the potentiallyhigh costs if reliability and security of supply are not met.


Box 10: Australian LNG supplyTo reduce its risk profile, Korea has in recent years contracted LNG suppliesfrom a more diverse portfolio of suppliers. More than 90 per cent of Korea’sLNG supply in 2002 was from four sources –– Indonesia, Malaysia, Qatar andOman. However, there are other gas producers in the Asia Pacific region, includ-ing in Australia, with the capacity, or planned capacity, to export LNG.

To date, Australia has had a limited role in supplying LNG to Korea, with traderestricted to several spot cargoes from the North West Shelf project, operatedby Woodside Energy. Recently, the gas links between Australia and Korea wereexpanded when a 7 year contract to supply 0.5 million tonnes of LNG a yearfrom late 2003 was awarded to NWS Australia LNG.

Australia has abundant reserves of natural gas, a reputation for reliable deliv-ery, is politically stable and has supportive government policies toward the exportof its natural gas resources. In addition, the North West Shelf joint venture hasdemonstrated an ability to offer flexible supply conditions, as evident in themidterm contract with KOGAS in which all cargoes will be supplied during thewinter period. The North West Shelf’s 4.2 million tonne fourth train is expectedto be online in 2004. A fifth train is planned, but would require long term commit-ment from a buyer such as Korea to underpin its development.

There are several other projects in Australia either under construction or plannedthat could potentially supply Korea’s LNG market. These include Sunrise in theTimor Sea and Gorgon LNG on the North West Shelf.

conclusions

Natural gas has played an increasingly important role in meeting Korea’srapidly growing energy demand in all sectors of the economy since importsof LNG commenced in 1986. Government policy to diversify energy suppliesaway from oil has been a key driver of growth in natural gas consumption,while strong investment in nationwide gas distribution networks has facili-tated its expansion.

Analysis in this study indicates that natural gas demand in Korea is likely tocontinue to grow strongly over the period to 2015, although at a slower ratethan in the recent past. Given current policy settings and assumptions abouteconomic growth and the fuel mix in electricity generation, natural gasdemand in 2015 could reach 33 million tonnes. This will be underpinned bythe increasing use of gas in households and by industry as well as in the elec-tricity sector. Increased use of gas would assist Korea to meet a number ofits key energy policy objectives. These include addressing the environmen-tal implications of energy consumption and ensuring a secure, reliable anddiversified energy supply base.

However, one of the major issues faced by Korea in the short and long termis how to establish effective gas procurement policies that will help to realisethe benefits of gas consumption throughout the economy. Korea is the world’ssecond largest importer of LNG after Japan and has in place medium andlong term contracts to import 19 million tonnes of LNG a year. This is insuf-ficient, however, to cover Korea’s gas requirements over the medium to longerterm. In addition, KOGAS has made extensive use of the spot market andshort term contracts to meet its current demands. The costs of this policy, asdemonstrated by Korea’s experience in the winter of 2002–03, are lack ofcertainty about access to gas supplies and prices higher than under long termcontracts.

Given the strong projected growth in LNG demand in Korea it is imperativethat cost effective, reliable and secure supplies of gas are available to elec-tricity generators and city gas companies. This is emerging as a seriousconcern for Korea, as gas supply plans have not kept pace with projected

82

7


demand and a significant gap between demand and supply is likely to ariseover the next decade.

The issue is complicated by the fact that KOGAS is delaying entering intonew long term LNG supply contracts until plans to liberalise the gas markethave progressed. However, waiting for gas reform plans to be implementedbefore committing to new LNG contracts is exacerbating the potential gapbetween demand and supply. Because gas market reform is complex andrequires good planning to implement effectively, it is not necessarily inKorea’s best interests to link the process to new gas supply contracts. Bydoing so, Korea is potentially missing the opportunity to secure favorableterms and conditions that are currently being offered under long term contractsin the international market.

An alternative form of natural gas supply that is currently being investigatedby the Korean government is the delivery of gas by pipeline from reservesin Siberia or Russia’s far east. The Irkutsk pipeline proposal is currently thesubject of a feasibility study by a consortium of Russian, Chinese and Koreangovernment and industry representatives. While the results of the feasibilitystudy are not yet known, many observers believe that it is unlikely that thepipeline will deliver gas to Korea before 2010. Even if the project proceedswithin this timeframe, the analysis in this study indicates that Korea willneed significantly more natural gas to satisfy its requirements over the periodto 2015. This could amount to around an additional 13 million tonnes a yearat 2015 and will be met almost certainly by increased imports of LNG. Ifthe pipeline is not developed by 2015 then the demand for additional LNGcould be as high as 20 million tonnes.

There is currently a number of LNG supply projects in the Asia Pacific region,backed by large gas reserves and extensive existing and planned productionfacilities, that have the capacity to meet Korea’s long term gas requirements.Indeed, the size of Korea’s projected gas demand over the period to 2015 issufficient to justify additional investment in production capacity by LNGsuppliers. However, given the time required to bring new greenfield or brown-field gas developments to the market, it will be important for Korea to committo new supply contracts as soon as possible if it is not to face an increasinglydifficult gas supply situation in the medium term. The current competitive-ness of the LNG supply industry and its responsiveness to changing marketconditions will ensure in these circumstances that Korea’s long term energysecurity objectives are met.


structure of the global trade andenvironment model (GTEM)GTEM is a multiregion, multisector, dynamic general equilibrium model ofthe world economy with a database that has a detailed representation ofproduction sectors and regions in the global economy.

A nontechnical description of the major assumptions and features of GTEMis presented below. A detailed description of the model can be found onABARE’s website (www.abareconomics.com).

DynamicsGTEM is a dynamic model that includes relationships between variables atdifferent points in time. This is in contrast to comparative static models,which compare two equilibriums, one before a policy change and one follow-ing. As a dynamic model, GTEM requires a reference case against whichthe results of policy simulations can be compared. The reference case providesprojections of growth in labor and capital in each economy or region, andthe associated growth throughout the rest of the economy in the absence ofany policy measures. The results of policy simulations are then interpretedas deviations from the reference case.

Factors of productionThe four primary factors of production in GTEM are capital, land, labor andnatural resources. The capital stock in each region accumulates by invest-ment less depreciation in each period. Both capital and labor are mobilebetween industries and, to a lesser extent, across regions through interna-tional capital flows and labor migration. Land is used only in agriculture andis fixed in each region.

GTEM explicitly models natural resource inputs as a factor of production inresource based sectors (coal mining, oil and gas extraction, other minerals,forestry and fishing). For example, the natural gas extraction industry usesthree factors of production — labor, capital and a natural resource (reservesof natural gas). The natural resource is a factor used solely in the productionof resource based commodities and is not mobile between sectors or regions.

84

A


appendix

Returns to the natural resource adjust to maintain its full employment. If, forexample, the demand for natural gas declines, returns to the natural resource(its price) fall, leading to a reduction in the supply price of natural gas.

Population and labor supply for each region are determined endogenously(within the model) over time. GTEM contains an elaborate description ofpopulation dynamics, which captures the idea that as economies move alongthe economic development path, increasing per person incomes lead to welldefined changes in fertility and mortality rates. The model uses estimates ofthe dependence of fertility and mortality rates on income and an exogenouslyimposed migratory pattern to predict age and gender specific populationchanges.

Natural rate of unemploymentIt is assumed that the imposition of any policy change does not raise unem-ployment above the so-called natural rate of unemployment for any econ-omy. Any downward shifts in the demand for labor are assumed to be offsetby reductions in real wages growth sufficient to prevent the emergence ofunemployment above the natural levels. This assumption is often known asthe ‘full employment assumption’ and its use is justified in cases where policychanges are introduced progressively, allowing time for wages to adjust tonew market conditions.

In practice, however, it could be expected that changes in patterns of produc-tion caused by a policy shock such as the implementation of trade and invest-ment liberalisation or the imposition of greenhouse gas emission constraintscould lead to the emergence of some unemployment, especially if liberali-sation has negative impacts in sectors where the skills of the labor force arenot easily transferable

PricesFor each commodity and primary factor in the model, taxes on production,sales, exports and imports are accounted for separately. As a result, the supplyprice, market price, domestic user prices and the export price (includingexport taxes) for a commodity in the producing region and the import price(including international freight), duty paid market price and user prices inthe importing region of a given commodity are clearly distinguished. In thestandard model closure, prices adjust fully to equate the supplies of anddemands for all factors and commodities in each region in each period.


Producer behaviorProducers in GTEM are assumed to operate in perfectly competitive marketsusing constant returns to scale technologies. Under these assumptions, priceswill be set to cover costs and GTEM industries earn zero profits at all times,with all returns paid to primary factors of production, including any returnspaid to owners of natural resource assets. Thus, changes in output prices aredetermined by changes in input prices of materials and returns to primaryfactors.

National income, savings and consumptionIn GTEM, a representative household in each region owns all factors ofproduction and receives all payments made to the factors, all tax revenuesand all net interregional income transfers. The representative household allo-cates its net income across private and public consumption and savings.National savings are assumed to move in line with national income.

Total consumption expenditure is calculated as the difference between currenthousehold income and savings, with the ratio of private consumption togovernment consumption assumed to be constant. Given total privateconsumption, the representative consumer maximises current period utilityby choosing consumption levels for each of the commodities in the database,from both domestic and imported sources.

TradeA key feature of GTEM is that it models bilateral trade flows of all commodi-ties between all regions. In GTEM an ‘Armington’ preference structure isadopted. This implies that a good produced in one region is an imperfectsubstitute for goods produced by the same industry in other regions(Armington 1969a,b). In other words, the same commodity from differentsources can trade at different prices.

Consumers in a region can substitute goods produced in that region with thesame goods produced in other regions. For any given consumption activity,demand for a commodity is allocated between a domestic product and acomposite imported product according to a constant elasticity of substitu-tion (CES) function. The demand by a region for each composite importedcommodity is then allocated between sources of imports according to a furtherCES function. Substitution between domestic and imported commodities


and between imported commodities from different sources will depend onmovements in relative prices and the specified elasticity of substitution —the Armington elasticity.

The Armington elasticities in GTEM vary between commodities and arederived from current literature and from empirical work undertaken by Jominiet al. (1991) in the construction of the SALTER world trade model. As withall parameters in a global computable general equilibrium model, there isuncertainty about the appropriate size and relativities of the Armington elas-ticities for various commodities. These elasticities are important determi-nants of the model results as they affect the estimated trade impacts oncommodities resulting from policy shocks.

In equilibrium, the exports of a good from one region to the rest of the worldare equal to the import demand for that good in the remaining regions. Goodsare transported between regions by an international transport industry. Thecost of international transport is added to the cost of imports to each region.GTEM does not require the current account to be in balance every year. Itallows the capital account to move in a compensatory direction to maintainthe balance of payments.

International capital mobilityGlobal investment equals global savings in GTEM. It is assumed that regionalborrowers (investors) issue bonds to global savers at a risk free, global aver-age rate of return. At the regional level, however, rates of return may differto reflect country specific differences in the risk premium required by globalsavers. For example, global savers tend to place a higher risk premium oninvesting in developing countries in GTEM to reflect greater uncertainty ofinvesting in these regions. The equilibrium rates of return in developing coun-tries are therefore higher than in developed countries.

Investment demands, in turn, are determined by changes in regional GDPand regional expected rates of return relative to expected global rates ofreturn. Thus, changes in investment flows represent changes in demand fromexpansionary or contractionary effects (changes in real GDP) and expecta-tion effects.

Any excess of investment over domestic savings for a given region causesan increase in net debt for the region. Borrowers service the debt at the globalrate of return (interest rate).


Exchange ratesThe exchange rate in GTEM is the price of converting local currency intoglobal currency. It is the price that adjusts to keep the balance of paymentsin equilibrium. For example, if trade liberalisation leads to a significantdecline in export earnings from a particular region this will, other thingsbeing equal, result in an exchange rate depreciation for that region. The depre-ciation in the exchange rate will improve the competitiveness of exportersand import competing producers in that region. Exports will increase andimports decline, restoring balance of payments equilibrium.

A change in the exchange rate will also influence international transfers asso-ciated with foreign debt or lending. For example, a region that has borrowedfrom international capital markets in GTEM that experiences an exchangerate depreciation will have a greater level of debt denominated in foreigncurrency. The debt servicing requirement (interest paid) will increase indomestic currency terms. On the other hand, a region holding foreign assetsthrough international lending will earn more interest income in domesticcurrency if its exchange rate depreciates.

Technology bundleIn the standard general equilibrium modeling approach, industries producea commodity by combining primary factors and intermediate inputs in fixedproportions. Substitution is only possible between primary factors. In GTEM,electricity generation and iron and steel production are modeled using the‘technology bundle’ approach. With this approach, different production tech-niques are used to generate a homogeneous output from each industry.Electricity can be generated from coal, petroleum, gas, nuclear, hydro orrenewable based technologies, while iron and steel can be produced usingblast furnace or electric arc technologies. Industries are able to substitutebetween technologies in response to changes in their relative costs.

By modeling energy intensive industries in this way, GTEM restricts substi-tution to known technologies, thereby preventing technically infeasible combi-nations of inputs being chosen as model solutions.

Production and interfuel substitutionFor industries other than those characterised by the ‘technology bundle’,production in each region is assumed to use only one technology. This tech-


nology requires fixed proportions of intermediate inputs, with the exceptionof energy inputs and primary factors.

Non technology bundle industries obtain a least cost combination of fourenergy commodities (coal, gas, petroleum products, and electricity) to producean energy composite and a least cost combination of the three primary factorsto produce a primary factor composite. The industry then forms a least costcombination of these two composites to obtain an energy–factor composite.Allowing for interfuel substitution and substitution between fuel and primaryfactors in this way means that industries can alter their production input struc-ture in response to price changes by substituting between energy and primaryfactors or by changing the energy mix.

DatabaseThe starting point for the GTEM database is the GTAP-4E database thatcontains 50 commodities and 45 regions, which is expanded by ABARE toinclude 55 commodities by expanding the coal producing sector to threedistinct industries (brown, black steaming and coking coal) and explicitlyidentifying bauxite, alumina and primary aluminium producing sectors. TheGTAP-4E database is based on 1995 production and trade data (expressedin United States dollars). The GTAP database required substantial alterationto form the GTEM database, particularly in the energy sector, and additionaldata (principally energy sector, greenhouse gas emissions and populationdata) were collected.

For example, the data underpinning the representation of two major fossilfuel using industries (electricity and iron and steel) were enhanced to reflectinput–output relationships in the range of known technologies. In addition,the contribution of each technology to total electricity and iron and steelproduction has been derived to reflect external data (IEA 1998; InternationalIron and Steel Institute 1996).

Also, significant demographic detail is required in GTEM to model popula-tion and labor force growth over time. Underpinning the demographic moduleare historical data showing the age and gender composition of the popula-tion in each region in one year cohorts from age 0 to 100. These are sourcedfrom United Nations (1998).


Greenhouse gas emissions accounting GTEM models emissions of three greenhouse gases — carbon dioxide,methane and nitrous oxide. Emissions of methane and nitrous oxide are repre-sented in GTEM in carbon dioxide equivalents. The carbon dioxide equiv-alent is derived by multiplying the emissions by the appropriate globalwarming potential, a measure of the relative radiative forcing of differentgreenhouse gases. The global warming potential values are 1, 21 and 310for carbon dioxide, methane and nitrous oxide respectively over a one hundredyear time horizon (IPCC 1996). At current atmospheric concentrations, anadditional tonne of nitrous oxide in the atmosphere, for example, is consid-ered to be 310 times more potent in terms of radiative forcing than an addi-tional tonne of carbon dioxide, over a one hundred year time horizon.


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Documents

South Korean Gas Imports