Report No. 8142-KO

KoreaGas Utilization Study

January 23, 1990

Industry and Energy DivisionCountry Department IfAsia Regional Office

FOR OFFICIAL USE ONLY

Document of the World Bank

This document has a restricted distribution and may be used by recipientsonly in the performance of their official duties. Its contents may not otherwisebe disclosed without VWorld Bank authorization.

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CURRENCY EQUIVALENTS

Currency Unit - Won (W)

US$1.00 - W660W1,000 - US$1.52

$ in this report refers to the US$

FISCAL YEAR

January 1 - December 31

UNITS AND EQUIVALENTS

bbl barrelbcm billion cubic meterBtu British thermal unitkw kilowattkwh kilowatt-hourskcal kilocalories (- 3.968 Btu)Gcal gigacalories (million kcal)KW megawatt (1,000 kW)ppm parts per millionPyong - 3.3 sq. meterstoe ton of oil equivalent (- 9.718 GCal)tpy ton per yearTwh terawatt-hours (billion kwh)

ABBREVIATIONS

CGA City Gas AssociationCHP Combined heat and power (generatior.)HFO Heavy Fuel OilIGCC Integrated gasification combined-cycle (systems)KDHC Korea District Heating CorporationKEEI Korea Energy Economics InstituteKEMCO Korea Energy Management CorporationKEPCO Korea Electric Power CorporationKGC Korea Gas CorporationKGSC Korea Gas Safety CorporationLHV Low Heating ValueLNG Liquefied Natural GasLPG Liquefied Petroleum GasMOER Ministry of Energy and ResourcesNPV Net Present ValueO&M Operation and maintenanceSO2 Sulfur dioxideTSP Total suspended particulates

KOOREA

GAS UTIUZATION STUDY

Table of Contents

SUMHARY AND CONCLUSIONS . . . . . . . . . . . . . . . . . . . . . i

1. TEERGY SECTOR . ...................... 1

General. ........................... 1The Gas Industry . . . . . . . . . . . . . . . . . . . . . . . . 5Environmental Issues ...................... 11Energy Price Outloo. . . . . . . . . . . . . . . . . . . . . . . 15

2. GAS UTILIZATION ...... . ................. 22

Introduction ...................... ... . 22Residevntial, Commercial and Industrial Sectors . . . . . . . . . 25Gas Utilization for Electric Power Generation . . . . . . . . . . 37District Heating ............. ..... ..... . 43Environmental Issues ......... ... .... ... .. . 46

3. SUPPLY-DEKAND SCENARIOS .................... . 53

The Residential, Commercial and Industrial Markets . . . . . . . 54Demand from the Power Sector .. ........ . 55Main Infrastructure .... . . . . . . . . . . . . . . . . . . . 59City Gas Distribution .... . . . . . . . . . . . . . . . . . . 65Economic Evaluation . . . . . . . . . . . . . . . . . . . . . . . 68

4. INSTITUTIONAL AND POLICY ISSUES ... . . . . . . . . . . . . . . 72

Strategy Formulation and System Planning . . . . . . . . . . . . 73Environmental Quality and LNG Use ... . . . . . . . . . . . . . 76Market and Regulatory Issues ... . . . . . . . . . . . . . . . 79

This report was prepared jointly by the World Bank and the Korea EnergyEconomics Institute (KEEI). Major inputs were also provided by the KoreaGas Corporation. The report was prepared following a Bank mission to Koreain S. ril/May 1989, consisting of Messrs. J-P. Pinard, R. de Silva,S. Khwaja (IBRD), P. Cayrade and R. deLucia (Consultants). The KEEI teamwas led by Dr. Shin, Shang-Kil.

This document has a restricted distribution and may be used by recipients only in the performanceof their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

Annexes

1. Energy Balance Forecast . . . . . . . . . . . . . . . . . 812. Petroleum Product Price Forecast . . . . . . . . . . . . . 863. Schedule of Domestic Petroleum Product Prices . . . . . . . 894. Coal Price Projections . . . . . . . . . . . . . . . . . . 905. LNG Price Forecast . . . . . . . . . . . . . . . . . . . . 916. End-Use Analysis: Residential, Commercial

and Industrial Markets .... . . . . . . . . . . . . . . 957. Summary of End-Use Analysis at 8X Cost of Capital . . . . . 1248. Netback Value of Gas in Power Sector. . . . . . . . . . . . 1259. Gas Demand Scenarios Forecast . . . . . . . . . . . . . . . 12910. Gas Supply/Demand Programs. . . . . . . . . . . . . . . . . 13511. Estimate of Investment Cost ............... . 14012. Net Present Value of Investment Scenarios . . . . . . . . . 15013. Air Pollution Emissions From Energy Use . . . . . . . . . . 160

Maps

IBRD 21915 - Proposed Gas SystemIBRD 21983R - Proposed Gas System

Seoul Metropolitan Area and Vicinities

KOREA

GAS UTILIZATION STUDY

SUMMARY AND CONCLUSIONS

1. Korea's energy endowment is extremely limited and its economy is, asa result, highly dependent on imported energy. Because of the magnitude ofthe amounts involved -- energy imports in 1988 totalled $5 billion or 10lof total imports -- and related strategic considerations, a centralpreoccupation of the Government of Korea has been the development of aneffective fuel import strategy. In deciding on an appropriate energy mix(essentially a choice between oil products, coal, gas and nuclear energy),the Government is focussing its attention on three critical areas: securityof supply, the relative prices of alternative fuels and, increasingly,their environmental impact.

2. In 1981, in the wake of the oil crisis, the Government decided tostart importing liquefied natural gas (LNG); actual delivery did not beginuntil 1987. With LNG now accounting for less than 4X of total primaryenergy demand, the issue faced by the Government is whether LNG should havea broader role in meeting Korea's long-term energy needs. The presentstudy was undertaken jointly with the Korea Energy Economics Institute(KEEl) and the Korea Gas Corporation (KGC) as an attempt to provide somepreliminary answers to this question. Its purpose is to (a) establish thescope for economic use of gas in Korea; (b) assess the viability ofalternative investment scenarios in gas infrastructure to meet possibleprojected demand; (c) outline the possible contribution of gas to apollution abatement strategy; and (d) review the existing institutional andpolicy framework and recommend changes needed to meet future growth in gasusage.

A. Korean Energy Strategy

3. For a long time, oil from the Middle East was the mainstay of Korea'senergy base. However, the oil crisis, and the severe implications this hadfor Korea's balance of payments, prompted the Government to revise itsapproach to energy imports. A new .3trategy was developed calling for (a)reducing dependence on petroleum by diversifying into alternative energysources, including imported coal and LNG, and nuclear energy; (b) selectinga wider spectrum of energy suppliers for oil and other energy imports, andparticipating in oil ventures overseas to secure supplies; and (c)fostering energy conservation. Korea pursued these policy changes withmuch success, and dependence on oil imports from the Middle East fell from1001 in 1978 to less than 60X today, with supplies originating from overtwelve countries.

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4. An important facet of this diversification strategy has been theimportation of LNG from Indonesia to diversify futel supplies away fromimported oil, address environmental concerns particularly in relation tothe use of charcoal briquettes for home heating in densely populated areas,and strengthen trading links with Indonesia. The current crntract is for 2million tons of LNG annually over a 20-year period, now equivalent to 3.6Xof Korea's total primary energy needs. However, KEEI's projections ofKorea's energy balance envisage that LNG could, by 2010, account for 7.5Xof total energy needs (about 10 million tons p.a.).

5. Unlike oil and coal, reliance on LNG requires commicments made wellahead of time because of the long lead time needed for upstream investmentin field development and liquefaction facilities. Another criticalcharacteristic of LNG trade is that it translates into a rather expensivegas price in end-use markets because of the high infrastructure costsinvolved. This issue is aggravated by the fact that Korea is an incipientmarket for gas and large investments in pipeline reticulation are alsorequired to bring the gas to consumers. On the other hand, natural gasoffers much flexibility in use, can be uzilized in highly efficient end-useequipment, and has a relatively benign tmpact on the environment. Fromthese several angles, the import ot LNG thus acquires strategic dimensioninasmuch as imports would have to be effected on a sufficient scale tojustify the necessary gas infrastructure by bringing down unit costs to afinancially attractive level. This would require a concerted decision onthe part of the Government, in part motivated by environmentalconsiderations, to make LNG a major fuel source and adopt appropriatepricing and other policies to bring about a sufficient level of usage.

6. KGC was established in 1983 as the government agency responsible forthe overall planning and execution of the basic in'rastructure necessitatedby the import of LNG (terminal and transmission pipelines). Responsibilityfor the distribution of gas to the final consumers (except for large-scaleusers) has been entrusted to private city gas companies.

B. Gas Utilization

7. Natural gas is a versatile fuel which can be used for residential andcommercial purposes as a cooking fuel or for space heating (and cooling).In industry, gas is used as boiler fuel, in direct heat processes, and as achemical feedstock. Gas can also be used for power generation. Thecompetitive position of natural gas vis-a-vis other fuels varies widelywith the end-use process in which it is applied; it is also considerablyaffected by the social costs associated with the fuels' relativeenvironmental impact.

8. To delineate the scope for economic use of natural gas in Korea, acomparative analysis was undertaken to assess the economic (and financial)attractiveness of using natural gas as opposed to other fuels in selected

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end-uses. This analysis is intended (a) to help build economicallyconsistent gas demand scenarios and estimate the economic value of naturalgas in alternative end-uses for the purpose of economic evaluation ofrequired infrastructure investments; (b) to provide a measure of costsinvolved in using gas rather than a cheaper but more polluting fuel inorder to reduce environment-related social costs; and (c) to provideinferene-es regarding sector organization and policy changes (e.g., pricing,introduction of specific technologies) to ensure market penetration in the,most attractive end-uses.

9. The general conclusion of the analysis is that there is a clear casefor gas use in the power sector even without consideratlon of environmentalfactors. The potential for using gas economically in other (i.e.,residential, commercial and industrial) markets is less uniform andrequires appropriate qualifications, although attractive end-uses wouldstill add to a substantial demand potential. This potential isconsiderably enhanced when the environmental advantages offered by naturalgas are taken into account. In particular, gas is seen as an economicallyattractive substitute for HFO and coal in urban areas based on even modestestimates of the social costs of these two fuels. However, fuel ..witchingwill be hindered by distortions in the pricing system which currently doesnot reflect the true relative economic cost of alternative fuels,particularly where environmental externalities are concerned.

Residential. Commercial and Industrial Markets

10. A series of representative end-use cases sere constructed to examinethe competitive position of gas from both the rational (economic) andfinancial perspectives in the markets normally supplieQ through adistribution network. In each case, natural gas was compared with an arrayof alternative fuels (e.g., fuel oil, diesel oil, liquefied petroleum gas(LPG), coal or electricity), taking into azcount differentials in equipmentefficiency and costs, and other relevant factors. The analysis indicatesthat LNG-based city gas is economically attractive based on narrowlydefined economic criteria (i.e., without consideration of environmentalfactors) in selected household, commercial, and industrial end-uses, where:

(a) competition is against a high economic-cost fuel (at theburner tip), e.g., LPG and in some cases diesel oil; or

(b) the user is willing to pay a premium based on the convenienceor guality offered by the use of gas (e.g., cookinig, directheat industrial processes); or

(c) gas is used in combination with high-efficiency end-usetechnologies which are readily available in other markets ifnot in Korea (e.g., cogeneration and combined heating/coolingtechnologies).

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11. The econsmic attractiveness of natural gas is sensitive to a numberof parameters: in the case of large-scale consumers, relative fuel pricesare the dominant element, while for the small-end of the market itt terms offuel consumption (i.e., the resident al and small-commercial markets) themagnitude of distribution and consumer costs becomes predominant. Henne,three factors are of direct relevance in characterizing the range ofeconomic uses of natural gas: (a) the social premium attributed to gasbecause of its cleanliness; (b) the scope for reducing construction costs,particularly by the city-gas companies; and (c) the introduction ofmeasures designed to improve the availability of gas-firing equipment inKorea, both in terms of volume and performance.

12. Residential Market. !n the residential market, gas use for cookingis motivated by the added convenience it brings to cornsumers compared tobottled LPG. The issue of quality and convenience is very Important ascooking is a consumptive energy use, and therefore fuel preference, andhence "willtngness to pay' (and economic benefit), is strongly influencedby qualitative factors. The question is whether the consumer's preferenceis such that the additional costs are warranted economically. In the casaof single-dwelling consumers, the distribution costs are high and areapparently not fully covered by the existing tariff which may conceal anelement of cross-subsidy. Since an environmentally acceptable alternativeexists in the form of LPG, government support to the distribution of gasfor cocking in individual housing units does not appear warranted at thisstage. Rather, market forces should be left unencumbered to arbitratebetween the two fuels.

13. In the more common case of apartment units, unit distribution costsare far lower than for single dwellings and gas distribution for cooking(and water heating) would be justified. However, an alternative hithertounexplored in Korea exists in the form of LPG delivered in bulk to theapartment building and piped internally to individual apartments. Thisalternative would be equivalent in convenience and quality with directaccess to city gas, while being probably cheaper both in economic andfinancial terus. We therefore recommend that the technical feasibility ofthis alternative be investigated.

14. Fuel choice for sRace heating varies both w.th the type of housingand income levels. The traditional Korean heating system operates withanthracite, which is heavily subsidized and, partly for this reason,remains widely used. Single-family dwellings at higher income levelsnormally rely on modern boilers burning diesel oil, while apartmentbuildings normally meet their space heating requirements with heavy fueloil (HFO) in central heating facilities.

15. In the case of individual houses, gas use is attractiveeconomically on a marginal basis (i.e., assuming it would be used forcooking and the latter would justify much of the distribution andconnection costs). On a financial basis, however, diesel remainssubstantially more attractive than gas, which points to the need for a more

disaggregated gas tariff structure to better differentiate between cookingloads and the larger space heating loads.

16. Coal-based heating systems provide a distinctly lower standard ofconvenience than oil- or gas-based systems; however, the scope for fuelswitching to pas -- which was one of the original objectives for importingLNG -- is limi ed by the high retrofit costs. While it is still theGovernment's intent to reduce the incidence of anthracite burning in urbanareas for environmental reasons, the coal-based alternative is likely toremain prevalent especially in existing buildings in the absence ofregulatory directives and/or financial incentives (para 39).

17. For apartment buildings, one needs to distinguish between centralheating facilities, individual heating systems and district heating. Whilethe individual heating system is uncommon in Korea (and is actually barredin more than seven-storey buildings), it would offer the best potential forgas use in the apartment market in the absence of government regulations onthe use (or specifications) of fuel oil for central heating. Otherwise,gas-based district heating systems appear to be the most promising optionfor effective gas use, particularly in the context of a pollution controlstrategy aimed at reducing the extent of HFO burning in urban areas.District heating, whick was recently introduced in Korea, is based on acentralized heat generating plant supplying urban areas through aninsulated steam transmission and distribution network (paras 28-29).

18. Commercial Market. Ine intensity of energy use, which impacts onthe scale of gas installations, is the most critical factor in analyzingthe scope for gas utilization for commercial space heating where HFO is thefuel normally used. For small-scale commercial consumers, LNG city gas isnot competitive with HFO, either in financial or in economic terms, despitea significant difference in boiler efficiency. The impact of gas-relateddistribution and customer costs, however, is dramatically lessened atlarger scale and higher energy consumption levels; thus, for largebuildings, HFO and gas are almost equivalent in economic terms (withoutconsideration of environmental impact) although HFO remains much cheaper infinancial terms. The comparison actually becomes quite favorable to gas atthe high level of consumption typical of large hotels. A comparison withdiesel oil is instructive in that it provides a first order, albeitimperfect, approximation of the environmantal gains that could be derivedfrom gas use compared to HFO. This indicates that for the low end of themarket diesel use might be the most cost-effective alternative, suggestingthat the Government needs to ensure that its fuel-switching directives infavor of gas should be grounded on appropriate economic ranking ofavailable alternatives (para. 38). Restaurant cooking (normally an LPGmarket) also provides an economically attractive market for natural gas.

19. Irrespective of the intensity of energy use, a direct financialcomparison with HFO in the commercial boiler market is har_.y favorable togas -- and fuel switching in this market segment would normally be posiibleonly if mandated by the Government as is already done in some areas.However, a number of high-efficiency options, meeting jointly two end-uses,

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are now available. These options, which considerably enhance theattractiveness of gas utilization from both economic and financialstandpoints, include notably gas-fired absorption technology (meeting bothheating and "ooling needs) and internal combustion engine technology (f,rthe joint production of heat and electricity). While these options arebased on technologies not yet widely marketed in Korea, they should becentral to an effective gas utilization strategy.

20. Induetrial Sector. The main advantage of natural gas in industrialapplications lies with its ease of use and, in some cases, in its qualityas a fuel. Additional benefits result from the lower operation andmaintenance costs of energy equipment, and from the fact that reliance ongas eliminates the need for users to carry fuel inventories. Despite theseadvantages, there are limited prospects for the use of gas as anunderboie_r_fuel, except for environmental reasons in densely populatedareas. This is partly due to the tact that domestic gas boilers have notyet reached the efficiency standards achieved in more advanced gas markets,and this issue requires government attention. An alternative avenue toinduce fuel switching in the industrial 3ector can be found in thecogeneratiog. of heat and electricity which provides much .pportunity foreffective use of natural gas.

21. Gas can compete effectively where its quality or some othercharacteristic is relevant to its end-use, such as in a number of directheat and drying processes where gas enjoys a clear technical advantage overliquid fuels (because of its clean combustion and better flame quality).A survey of key industries (textiles, metal, food processing, etc) showsthat, where this is the case, gas will be the fuel of choice economicallyalthough pricing could still be a barrier to the peiietration of thesemarkets. Moreover, gas will be able to make large, and economicallyrewarding, forays in the industrial fuel market only if supported by anintensive effort in gas technology development.

22. Conclusions. City-gas operations have so far focussed on thecooking, water heating and part of the space heatti,g markets. The analysisindicates that part of the commercial and industrial energy markets alsooffer attractive opportunities for LNG use (parti'ularly when takingenvironmiental factors into account as discussed it, paras 37-38).Experience elsewhere has shown that fuel demand by industries is usuallycharacterized by a high price elasticity. In Korea, however, the low priceof fuel oil in relation to other fuels, as established by the Government,has so far largely precluded gas penetration of the large boiler fuelmarket. It is also apparent that switching from HFO boilers to a moresophisticated and efficient use of energy in (gas-fired) cogenerators oradvanced heating/cooling systems in large buildings would also be ha7peredby the low price of fuel oil, albeit considerably less so than in theconventional boiler market. Conversion of HFO users to gas has so faroccurred mainly on account of fuel use regulations motivated byenvironmental concerns. Alternative (or supplementary) approachescombining fuel price adjustments (to better reflect true economic costs,including environmental costs) and financial assistance to selectedconsumers (for equipment financing) need to be developed. In this context,

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we also recommend that the Government adopt a more selective approach itlsupporting reticulation investment by the city gas companies throughsubsidized funiding. Efforts should be made to ta,:get financial incentivoszo priority market segments in lieu of the present, largely indiscriminazoapproach. The alternative of providing a greater proportion of governmnntsupport directly to priority consumers also needs to be investigated. T'liswould allow Government to focus its intervention on those categories ofconsumers for which the environmental factor is most relevant but wherefuel switching is seen to require special incentives, most particularly theresidential coal users.

23. The range of equipment and appliances presently available in Kor_aoften do not provide the comparative advantages enjoyed by gas-usingtechnologies in well-developed gas markets. Cost reductions, efficiencyimprovements and access to the most up-to-date technology would affect thecompetitive position of gas in a major way. No survey of technologyavailability in Korea has been made to date and this should be an importantitem in the development of a gas utilization strategy. We recommend thxtsuch a survey be carried out, leading to a plan of action for thedevelopment of appropriate technologies and encouragement to their bronc.eravailability in the market place.

Gas Utilization for Electric Power Generation

24. Interest in natural gas as a fuel for power generation is keenworldwide due to continued growth in known gas reserves, the cleanliness ofgas as a fuel, the debate surrounding nuclear energy and recentimprovements in the design and performance of combined-cycle power planta,particularly (although not exclusively) when fired with natural gas. Thcsefactors are of particular relevance to Korea's current energy outlook andwill have a direct bearing on itE potential use of LNG over the next 10 to20 years.

25. Combined-cycle plants benefit from low capital costs andrelatively short engineering/construction periods, and offer modular deG!gnfeatures that allow utilities to add ge-aerating capability in smallincrements with short lead-times, thereby minimizing concentration offinancial capital and better responding to uncertainties in power demandoutlook. Also, gas firing minimizes fuel preparation and handlingproblems. Finally, recent efficiency improvements in gas turbinetechnology have significantly enhanced their attractiveness as base-loadfacilities.

26. Alternative options for future power system expansions in Koreainclude nuclear plants, coal-fired and oil-fired conventional steam pow.^):plants, and gas- (or diesel oil-) fired combined-cycle plants. Acomparison of these alternatives based on the calculation of unitgeneration costs underscores the economic attractiveness of gas use inf3mbined-cycle plants (when compared to conventional coal-fired steamplants which would be the most logical alternative). Assuming a plant l,adfactor of 66.5X, the netback value of gas at the plant gate is estimate& at

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$27/GCal. A direct comparison of the netback value of gas with theexpected average cif price of LNG over the period ($17/GCal) points to apotentially large rent available to cover infrastructute costs. This rent,however, is quite sensitive both to load factor and cost of capitalassumptions because of the prominence of the capital cost differentialfactor. A reductior in the cost of capital from 131 (the Government'sofficial figure for planning purposes) to 8X brings the netback value ofgas down to $22/GCal (and the rent down from $10/GCal to $/MCal). For thesame reason, the competitiveness of gas-fired combined-cycle plantsimp-roves significantly at lower load factors.

27. The comparative economics of coal- and gas-fired power generationalternatives will remain primarily dependeut on future commoditv pricetrends. While present price forecasts (and technological factors) give thegas opt!on a significant advantage (over coal), the o,volution of worlddemand for each of the two fuels may modify the current relationships.Sinca a gas import strategy (in part predicated on substantial use of gasin the power sector) wcild commit Korea for a long period of time, wepropose that the possibility of introducing a partial link between LNG andcoal prices (in lieu of the traditional, straight indexation on oil prices)should be explored in the course of future import negotiations as a hedgeagainst unexpected price &aovements.

District Heating

28. District heating is particularly well adapted to Korea's climiticconditions and urban environment because of the combination of substat.ial,concentrated, space heating loads and relatively high urban densities.District heating is normally economical only in the context of combinedheat and power generation (CHP), where waste heat from electric powergeneration is used for district heating purposes. Its development istherefore closely linked to that of the power system. The potential fordistrict heating as a cost-effective method to meet urban space heatingloads at an acccpraLle environmental cost has improved considerably withthie recent evolution oil combined-cycle technology which -an be easilyadapted to a CHP ctinfiguratien.

29. A generic comparison of district heating schemes with traditionalspace heating methods is hardly feasible because of the multiplicity ofsite-specific factors. Generally, however, district heating systems arelikely to have a eomparative advantage where generating plants can belocated reasonably close to the areas to be supplied. District heatingplanning is still at an early stage. However, given the potentially large-scale use of gas this activity may generate, it is essential that currentstudies (by KEPCO and the Korea District Heating Corporation (KDHC)) beintegrated rapidly within KGC's current gas infrastruc.ure planningexercises. Similarly, the scope for setting up such facilities in othercities, should gas become available there, needs to be explored at an earlystage.

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Environmental Aspects

30. A comparison of Korea with other industrialized countries suggeststhat the level, of air pollutants ia quite high, with sulfur dioxide (SO2)and total suopended particulates (TSP) being the most serious sources ofair pollution. Despite significant progress since the enactment in 1981 ofregulations designed to decrease SO2 concentrations, SO2 levels in Seoul,Pusan and Ulsan still exceed the prescribed annual air quality standards.The Government is committed to a policy of curbing the deterioration of theenvironment that has resulted from rapid urbanization and industrializa-tion. Natural gas, which is free of most pollutants present in liquid andsolid fuels and generates onl- a fraction of the CO2 output of alternativefuels, can play a major role in a pollution control strategy. Accordingly,a key objective of the Government in importing LNG has been to reduce airpollution in urban and highly industrialized areas.

31. For a number of end-uses, the economics of gas utilization aremarginal when compared to alternative fuels on a strictly economic basisbecause of the high cost of LNG. In many such cases, however, differencesin environmental impact would considerably strengthen the justification forusing natural gas. These include in par.icular substantial portions of thecommercial and industrial markets. Issues of concern to the Governmentshould be (a) to determine the extent to which gas use should be encouragedbeyond the levels dictated by relative commodity prices and efficiencyfactors; and (b) to identify the most effective instruments to provide theneeded incentives (subsidies for conversion, cross-subsidy in price) anddisincentives (taxes on polluting fuels, etc) to facilitate gas penetrationof targeted markets.

32. In addressing environmental issues, the Government has so farrelied mainly on fuel allocation policies, in particular through theissuance of fuel use regulations specifying minimum fuel quality oraltogether barring the use of certain fuels in some areas. While theseregulations are well-motivated, the issue is one of cost effectiveness,specifically of the comparative advantage of promoting the use of naturalgas to address specific environmental concerns. As environmental issuesgain greater prominence in the setting of energy policies, the Governmentneeds to ensure that its gas utilization policies are rooted in an overallpollution control strategy supported by a proper assessment of availablealternatives. There are three priority areas where gas can play a criticalrole in reducing the pollution impact of energy use, althoughrationalization of government policies will be a prerequisite to theestablishment of fuel use patterns that properly account for the relativesocial costs of each fuel: (a) the use of HFO in the power and industrialsectors; (b) the use of HFO in the urban, commercial sector; (c) the use ofanthracite for space heating.

33. Power Sector and Other Large-Scale Users. For large-scale HFO orcoal users (large industries and power plants), a number of emissioncontrol techniques are available, the most effective methods (flue gastreatment) being able to reduce SO2 and NOx emissior,s by up to 80-90.

While such environmental controls assume an increasing proportion of plantcosts as regulatory requirements tighten, which would encourage gas use,mandatory fuel switching regulations should be based on a careful analysisof these alternatives. Generally, reliance on market forces to meetspecific emission targets should be given preference over administrativefuel use regulations.

34. In the case of the power sector, the availability of technologiesable to mitigate the environmental impact of conventional coal- (and oil-)fired p3wer plants may not be sufficient for these plants to gainsufficient public acceptance for KEPCO to implement its proposed expansionprogram, which calls inter alia for the installation of seven coal plantswith a total capacity of 5,100 MW over the next 12 years. A (partial)shift to gas is warranted by the encouraging results of comparativeeconomics. Two factors could over time affect this general recommendation:a drastic change in relative price trends (of LNG and coal) from currentexpectations; and further progress in power generation technology which isvery much in a state of flux in response to environmental concernsworldwide. For these reasons, the Government needs to keep abreast ofpro3ress made in the development of various advanced (coal- and oil-firing)power generation technologies, which offer the potential for importantenvironmental gains. These include notably (a) fluidized bed combustion(FBC) systems; and (b) integrated gasification combined-cycle (IGCC)systems.

35. IGCCs provide for the conversion of coal to a highly combustiblesynthesis gas, composed mainly of carbon monoxide and hydrogen and free ofmost pollutants, which is then combusted in a combined cycle power plant.IGCC technology is a highly effective way of reducing the SO2 and NOxoutput of coal-fired stations while taking advantage of combined-cycleefficiency. As such, it probably is the most relevant long-termalternative for Korea and provides a suitable comparison for gas-firedsystems for the purpose of long-term system planning on a more or lessenvironmentally equivalent basis. On the basis of current coal gasifiercosts and efficiency, the break-even price of gas above which IGCC wouldbecome attractive is estimated at about $29/GCal, far above the expectedlong-term cost of gas (after regasification) -- but close to the netbackvalue of gas against conventional coal plants, which indicates that, as acoal technology, IGCCs would be economically attractive as soon as designshave been scaled up to standard plant sizes. One should expect significantreduction in the costs of coal gasifiers as the technology gains wideracceptance. However, the capital and O&M costs of coal gasifiers wouldhave to drop by as much as 55X for IGCC systems to become attractive for acountry like Korea which must import coal as well as gas. Gas-firedcombined-cycles are therefore expected to remain the most attractive powergeneration option for at least the next decade.

36. A separate issue relates to the choice of fuel in existing oil-fired thermal plants. KEPCO has been requested by the Government toconvert to continuous gas-firing a number of its oil-fired power plantslocated in densely populated areas, including the Incheor. plant. However,

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the issue of whether this will result in a cost-effective handling ofpollution control and LNG load balancing objectives is open to questioninasmuch as substantial pollution abatement could stAll be achieved byhaving these plants occasionally run on low-sulfur fuel oil (to help meetseasonal variations in other markets). Such an approach, which wv.uldreduce the extent of uneconomic use of gas elsewhere (e.g., at PyeongTaek), could be complemented by a contribution from KFPCO towards the costof environmental control measures in higher priority areas. We recommendthat mandatory fuel-switching policies in the power sector be reviewed toensure that they provide a cost-effective answer to environmentalobjectives.

37. Small-scale Energy Consumers. While efficient and relatively cost-effective post-combustion pollution control techniques are available forlarge power generation and industrial facilities, their costs rapidlybecome prohibitive as the scale of operations diminishes. Generallyspeaking, the only options available to reduce the emissions of smallerenergy users are to shift to higher quality fuels or to modify thecombustion process.

38. The scope for economic use of natural gas in lieu of HFO as a meansof mitigating the environmental impact of small- and medium-sizedindustries (SMIs) and commercial facilities cannot be easily characterizedand market forces should be relied on as much as possible to elicit theoptimum fuel use pattern. One approach preferable to mandatory fuelswitching regulations would be to impose a tax on polluting fuels andstrengthen the standards on acceptable fuels. For SMIs, an alternative (orcomplementary) approach would be to promote the use of gas in thecogeneration of steam and power in CHP facilities, which can achieveenvironmental as well as efficiency benefits. Cogeneration can be effectedeither in plant-specific units or in larger-scale facilities designed tosupply industrial parks. In either case, natural gas would offer the mostattractive fuel. We recommend that suitable institutional arrangements bemade to facilitate the establishment of gas-based industrial utilities inareas with large SMI concentrations. The availability of efficient small-scale cogeneration units for commercial and SMI applications also need tobe promoted.

39. Residential Consumers. One of the most vexing environmentalproblems faced by the Government is that of anthracite-burning forresidential space heating for which there is no clear economicjustification. Gas has clearly a role to play in addre-sing this issue.Aside from a reduction in the extent of subsidies on domestic coal, themost promising avenue would be to encourage fuel switching throughfinancial assistance to consume;s towards the cost of conversion. Highefficiency household-sized boilers have been developed, which wouldminimize retrofit costs and whose availability should be promoted. Thedevelopment of district heating systems could also provide part of thesolution if shown to be feasible in urban areas where traditional habitatis predominant.

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C Supply-Demand Scenaios

40. KGC has made preliminary plans to expand the supply of gas inKorea. To evaluate the economic viability of this investment program,alternative supply/demand scenarios were developed based on plausibleassumptions about future gas use. For this purpose, the country canconceptually be divided into two separate regions, i.e., the region northof Pyeong Taek (i.e., the Kyongin region), where a gas system is already inplace; and the region south of Pyeong Taek (I.e., the Chungchong, Yongnamand Honam regions) where no gas system is as yet available (except forisolated manufactured gas networks).

Demand Scenarios

41. Residential. Commercial and Industrial Markets. The basis for ourdemand scenarios for the residential, commercial and industrial markets isa Gas Demand Study completed by KEEI in 1988. The KEEI demand projectionsare based on a careful analysis of macroeconomic trends and provide areasonable starting point for a preliminary review of investments.However, they lack the underpinning of dircrete market surveys,particularly as regards industrial demand. The undertaking of suchsurveys, together with basic design studies of selected gas, distributionsystems, is a critical prerequisite to the implementation of an expandedgas strategy (para. 51). One should also note that the demand scenariosare predicated on the assumption that a policy and institutional frameworkconducive to the penetration of preferred markets will be put in place asinfrastructure construction proceeds (paras 60-62).

42. LNG demand from residential, commercial and industrial consumers inthe northern (Kyongin) region is projected to reach 1.0 million tons by1996 and 2.2 million tons by 2006. Corresponding figures for the rest ofthe country are 0.5 and 2.2 million tons, respectively.

43. Power Sector. KEPCO's latest power development program providesfor the phased erection of a 4x800 MW combined-cycle plant on the island ofIl-Do close to Incheon. KEPCO has also made preliminary plans (togetherwith KDHC) for the construction of three gas-fired CHP plants (also basedon combined-cycle technology) with total capacity of 775 MW to supply newurban developments in the metropolitan area (i.e., Il-San, Bun Dang andPyung-Cheon). Since construction of a gas grid to supply the southern partof the country is still under discussion, plans for installing new gas-fired power and CHP capacity outside the area served by the existing gassystem are naturally less advanced. However, it would be difficult tojustify the construction of a gas grid to the south without a substantialgas-based power-CHP program (para. 54). Given the relevance of powerinvestment decisions in planning future gas infrastructure, uncertaintiessurrounding power planning, particularly in the southern regions, need tobe lifted as soon as possible (para. 58).

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44. LNG demand from KEPCO in the northern region is projected to reach3.0 million tons by 1996 and 4.4 million tons by 2006. KGC's current plansdo not provide for any use of gas for power generation in the rest of thecountry. An alternative scenario developped by the mission projects thepower sector demand for the whole country to reach 3.5 million tons by 1996and about 6.0 million tons by 2006.

Infrastructure

45. When the decision to import natural gas was made in 1981, theGovernment initiated a policy of encouraging the development of city gassystems (in the Seoul area and in a few other cities). These systems wereto operate initially on manufactured gas as a means of building up marketsahead of the inception of LNG deliveries. The strategy of the Governmenthas been to license private distribution (city gas) companies to establishthe needed reticulation. To date, twenty one city gas companies have beenlicensed to distribute natural gas, seven of which have been converted toLNG in Seoul.

46. Basic Infrastracture. The existing infrastructure consists of anLNG receiving terminal (Pyeong Taek) and of a supply network serving theSeoul metropolitan area. After regasification, LNG is being supplied tothe Pyontaek power station and, through the main transmission system, tothe Incheon power station and the seven city gas companies licensed tooperate in the Seoul metropolitan area for residential, commercial andindustrial use.

47. To meet the expected increase in gas demakid, KGC proposes to expandthe Pyeong Taek terminal (in two phases) and, in parallel, to construct anew terminal at Incheon. This strategy appears reasonable. In terms oflocation, siting the second terminal in the south (instead of Incheon)would present advantages in terms of load balancing and would initiallyreduce investment in transmission pipeline. However, given KEPCO'sdecision to install a major gas-fired power plant close to Incheon, theconstruction of a (partially) dedicated terminal at Incheon is logical.A terminal at Incheon would also greatly improve the security of supply forthe Seoul area.

48. The program of pipeline construction required to meet thealternative demand scenarios includes (a) reinforcement of the existingsystem north of Pyeong Taek; and (b) constrvntion of transmission linessouth of Pyeong Taek. KGC has undertaken a preliminary concept study ofthe modifications required to expand the delivery capacity of the existingpipeline system from 2 to 4 million tons of LNG. This complements anearlier feasibility study for a national gas grid to supply tne southerndistricts.

49. For the purpose of economic analysis, four supply scenarios weredeveloped, covering incrementally the Kyongin, Chungchong, Yongnam andHonam regions. Estimazes of capital costs for each of the four scenarios

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(excluding distribution costs) are $0.93 billion, $1.03 billion, $1.3billion, and $1.6 billion, respectively. To meet projected demand,rpiticularly from the new combined-cycle plant at Incheon, a first stageextansion of the existing Pyeong Taek terminal would need to be completedhy 1993/94 and the second terminal to come on stream by 1997/98.r:eparation work would therefore need to start soon, including detailedfeasibility studies for (a) expansion of the Pyeong Taek terminal and (b)renstruction of a new terminal at Incheon, including a review of accessciannel, soil conditions, etc.

5'. City Gas Distribution. Gas sector planning has so far dealt with!-'a question of gas distribution only incidentally, presumably under theitsumption that private companies supported by cheap government financingcould be expected to handle this aspect of sector development efficiently.lowever, the gas companies appear to operate largely under a short-termrlanning horizon and their objectives do not necessarily match those of therovernment, which are clearly long-term. Thus, the city gas networks are"eing developed without the benefit of long-term plans and are in generalroorly adapted to the development of high loads over large areas, therebyiailing to provide a least-cost approach to the sales targets set by theCovernment.

'il. Since the construction costs of utilities in Korea are generally1-igh compared to those in other countries, possibly due to local factorsand regulations, there is a need to take a longer-term view of systemevelopment to rationalize tbs use of resources. Distribution costs alonenre expected to amount to $1.1-2.1 billion over the 1990-2006 period (orF5-..OZ of total sector investment on a net present value basis), and willrrobably require a continuation of government support on a significantscale. In view of the magnitude of these investments, we recommend thatconceptual master plans, backed up by discrete consumer surveys, beprepared for the largest consumer concentrations, including (a) theSeoul/Incheon area; (b) the Pusan/Ulsan area; (c) a typical medium-densitycity (possibly Taejon); (d) a typical low-density city. We also recommendthat KGC take the lead in executing these studies in close collaboration'ith the utilities concerned.

V onomic Evaluation

i7. LNG is presently priced on an FOB basis at about 90X of crude oil,1 >.iich translates into a few percentage points above crude on a CIF basis3cause of transport cost differentials. There are indications that, for a

.,umber of years, the LNG market will essentially be a buyer's market with apossible softening of prices. However, rather than attempting to forecastche evolution of contract terms over time, our (base case) analysis ispredicated on the assumption chat a similar relationship as the onecharacterizing the existing contract would prevail under future contracts.

53. The proposed investment program, including both KGC's investmentsin basic infrastructure and those of the gas companies for distribution,

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would: (a) increase the average end-use value of the quantities of gasavailable under the original contract by shifting their usage from existingthermal power plants (where they substitute low-valued HFO) to city gasmarkets; and (b) expand the overall supply of gas to meet KEPCO's increaseddemand and broaden the geographical availability of natural gas to thesouthern regions.

54. Each of the four alternative supply/demand scenarios was measuredagainst the original 1989 situation by calculating the net present value(NPV) of incremental costs and benefits. For each category of consumers,the corresponding (netback) value of gas was used as a measure of benefits.These netback values are based on the economic cost of the energy sourcebeing displaced, corrected for differentials in heating value, thermalefficiency, and the capital and operating costs of appliances and end-useequipment. The analysis indicates that Scenario A (Kyongin region only) isclearly attractive with an incremental NPV of about $1.0 billion.Scenario B (Kyongin and Chungchong regions) is an acceptable alternative,with an NPV similar to that of Scenario A. However, Scenarios C and D(Yongnam and Honam regions) would not be viable in the absence of asubstantial demand from the power sector, particularly in high-value end-uses (e.g., combined-cycle type of facility, including CHPs). For ScenarioC, it is estimated that a minimum of 800 KW of new (combined-cycle) powercapacity located in the south, as well as substantial use of gas inexisting oil-fired plants, would be required to justify the proposedtrunkline investment. Note, however, that the investment could bejustified with a lower demand from the power sector if substantial value isattached to the objective of reducing pollution in the highlyindustrialized Pusan/Ulsan area.

55. We recommend that preparation work start for Scenario B as soon aspossible, including (a) detailed feasibility studies for terminal capacityexpansion (at Pyeong Taek and Incheon); (b) detailed design of a PyeongTaek-Taejon pipeline (which could be conceived as a first phase of aneventual trunkline to the south); (c) detailed design for the strengtheningof the existing pipeline system north of Pyeong Taek; and (d) conceptualmaster plans for gas distribution (para. 51). In parallel, detailedanalysis of gas demand from the power/CHP sector in the south would need tobe undertaken jointly by KGC, KEPCO and KDHC.

56. The economic attractiveness of Scenario D is significantly moremarginal than that of Scenario C because of the lower anticipated gasdemand in the Honam region. The Government is considering far-reachingregional development plans for the western seaboard, partly through theestablishment of new industrial zor.es. These plans could have asignificant bearing on future gas demand, particularly if new industrialparks were to be equipped with centralized utility systems which wouldprovide a convenient and economic market for natural gas. We recommendthat plans to extend gas distribution to the southwestern part of thecountry be reviewed after regional development plans have been firmed upand updated forecasts of gas demand are available.

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D. Institutional and Policy Issues

57. The analysis indicates that there is clearly a significant role forLNG in the energy sector in Korea based solely on narrowly defined economiccriteria. Moreover, taking account of environmental benefits wouldconsiderably enhance the potential for economic use of gas. However, theanalysis also indicates that gas utilization needs to be carefully chartedto ensure that it leads to an efficient use of resources. To be fullyeffective, decisions on additional imports would need to be accompanied bysubstantial strengthening of the existing policy and institutionalframework to ensure that the combination of market forces with selectivegovernment intervention leads to an economicp'iy -fficient LNG consumptionpattern.

58. There is first a need to strengthen the interface between power a

planning and gas infrastructure planning. The long-term use of gas inpower plants will largely dictate the structure of the main gasinfrastructure. Details of the pattern of future consumption (e.g.,quantities, plant locations, etc.) need to be worked out at an early stagesince they will condition such major decisions as the location and timingof future terminals and bulk transmission lines. To bring about greatercoordination among the various agencies involved, we recommend that aconsultative gas planning working group consisting of representatives ofKGC, KEPCO, MOER (and possibly KDHC) should be established.

59. Secondly, there is a need to strengthen the planning capability of |the city gas companies. This could best be done by having the Governmentprepare a gas distribution master plan for the Seoul metropolitan area aswell as the financial and regulatory framework that would makeimplementation of this plan possible, using the plan as a basis fornegotiating long-term supply agreements with the gas utilities. Werecommend that KGC take the lead in commissioning such a master plan.

60. Third, a cost-effective gas utilization strategy needs to bedefined in the context of a coherent environmental strategy established onthe basis of a comparison of alternative air pollution control options. |The Government needs to strengthen its analytical capability in handlingthese issues. Current regulations on fuel use are apparently based more onadministrative ease than careful analysis of economic tradeoffs. Thus,whereas residential anthracite burning is the single largest source of airpollution, government policies have been largely focussed on HFO users andlarge users of coal (power). A strategy aimed at the anthracite marketneeds to be developed, possibly involving the use of gas, either byproviding assistance .o consumers towards the costs of retrofit, or throughthe installation of district heating systems in selected areas. Moregenerally, government priorities in the area of urban planning need to beclarified inasmuch as they affect fuel choices. Accordingly, we recommendthat the Government establish a working group on energy use in theresidential and commercial sectors, which would be in charge of preparing

!

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an "energy zoning Rl j", together with the necessary regulations. Possibleuse of compressed natural gas (CNG) as a transport fuel also deservesconsideration; conversion of city buses wotld be a first priority.

61. Fourth, gas penetration of the most attractive end-uses from aneconomic standpoint will require careful handling of pricing, equipmentfinancing and regulatory issues. In particular, regulatory interventionssuch as the introduction of end-use technology efficiency and otherstandards need examination. Also, uses of alternative market mechanisms tobring financial prices in line with economic prices that reflect someenvironmental externalities deserve some consideration.

62. Fifth, implementation of an expanded gas strategy will requirespecial efforts to foster the introduction of additional end-usetechnologies (in particular small-scale, high-efficiency technologies) intothe Korean marketplace. A detailed technology supply review is required,leading to an action plan for technology development. We recommend thatKGC, through its training and research center, take the lead in thisexercise, possibly in collaboration with the Korea Energy ManagementCorporation (KEMCO) and the Association of Gas Companies. There is also acomplementary need to assist end-users adopt these technologies (throughfinancial and technical assistance).

E. Conclusion

63. This review of gas utilization prospects indicates that KEEI's andKGC's target of some 10 million tons of LNG to be imported annually by 2010(or 7.5X of total primary energy in that year) appears reasonable. Thereis indeed a significant role for LNG as part of both a least-cost energysupply strategy and a least-cost pollution control strategy for Korea.There is a risk however that, because of the magnitude of infrastructurecosts involved, government attention would be focussed on investmentimplementation to the detriment of policy development. There is indeed acomplementary need for policy formulation to ensure that an economicallyefficient LNG consumption pattern and rapid buid-up are achieved to fullyjustified the proposed investment. Meeting the objectives sketched by KEEIand KGC will require the involvement of a number of entities, both withinand without the public sector. To ensure the necessary coordination of allinvestment planning and policy development activities the Government shouldestablish a clear and comprehensive agenda of actions required of all theparties concerned, as compatible with economic and financial efficiency.

1. THE ENERGY SECTOR

A. General

1.1 Korea is almost devoid of indigenous commercial energyresources. Since its Ihigh-growth, industrializing economy is highlyenergy-intensive - the second highest among major countries in Asia afterJapan, it is growing increasingly dependent on imported fuels. Korea'scommercial energy endowment consists of hydroelectric power (2,000 NW) andcoal (750 million tons). Korea is still able to produce about half thesolid fuels it consumes, but coal reserves are becoming depleted and arehigh cost. Liquid fuels, on the other hand, are wholly imported anddependence on oil import has been kept in check only by a policy ofdiversifying away from oil. Because of the magnitude of the amountsinvolved -- energy imports in 1988 totalled $5 billion or lOX of totalimports -- and related strategic considerations, a central preoccupation ofthe Government of Korea (GOK) has been the development of an effective fuelimport strategy.

Past Developments

1.2 The mainstay of the Korean economy during the 1950s wasagriculture; firewood was then the principal energy source. As thedestruction of forests during the Korean war led to shortages of fuelwood,energy planners turned vo the development of anthracite coal as analternative energy supply. During the 1960s, a stable source of energybeyond domestic coal became needed as industrial development picked up andplans were made for the construction of power plants and oil refineriesbased on imported oil.

1.3 The following decade saw a sharp increase in imports ofpetroleum fuels, which made the Korean economy increasingly vulnerable toprice fluctuations in the international market although supplies remainedabundant and dependence on imported oil was not perceived as a source ofconcern. The oil crisis during the 1970s, however, caused a severerecession and large balance of payment deficits, with Korea having toborrow heavily to meet its Increased oil import bills. These developmentsprompted the (overnment, in the early 1980s, to revise its approach toenergy imports. A new strategy was developed calling for (a) reducingdependence on petroleum by diversifying into alternative energy sources,including imported coal and liquefied natural gas (LNG) and nuclear energy;(b) selecting a wider spectrum of energy suppliers for oil and other energyimports, and participating in oil ventures overseas to secure supplies; e.nd(c) tostering energy conservation partly through industrial restructuring.

1.4 Korea pursued these policy changes with much success. On thesupply side, heavy investments were made in nuclear energy. As of end-1988, total installed nuclear capacity was 6,666 MW with 9 units inoperation. To divei-stfy and secure sources of oil supply, Korea has alsoentered into joint-verture exploration agreements overseas with foreign oil

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companies. Exploration in Korea's offshore areas by the Korea PetroleumDevelopment Corporation (PEDCO) has recently led to the discovery ofapparently significant gas deposits east of Pusan (earlier gas shows offthe southern coast proved disappointing). These deposits are being furtherinvestigated to ascertain the possibility of commercial development.

1.5 Korea also diversified its sources of oil supply. Oil importshave been gradually shifted from long-term contract to spot marketpurchase. Consequently, dependence on the Middle East fell from 100% in1978 to less than 60% today, with supplies originating from over twelvecountries. Import of LNG from Indonesia, which started in 1987, has beenanother important facet of this diversification strategy.

1.6 On the demand side, the energy intensity of the economy wasreduced partly through efficiency gains in the use of energy and partlythrough a reduction in che relative share of energy-intensive industries tothe advantage of light manufacturing. The energy elasticity of GDP growthis currently close to one, although it was much higher in the 1960s and1970s when heavy industries were expanding, and well below one in the early1980s when the emphasis shifted to higher technology manufacturing.

Energy Balance

1.7 Korea's total primary energy consumption in 1988 amounted toabout 75 million tons of oil equivalent (toe). Of these quantities,domestic production, including hydro and nuclear power and anthracite,accounted for 31% (23 million toe). Oil consumption during the year was251 million barrels (35 million toe). Imported LNG accounted for another2.7 million toe or 3.6% of total primary energy demand.

Petroleum

1.8 Crude oil imports in 1988 accounted for 86% of total petroleumimports, which indicates that the structure of the domestic refineryindustry is relatively in line with the pattern of demand althoughhistorical data show a slight reduction in self-sufficiency. Importedproducts included LPG (15 million bbl), diesel oil (8 million bbl) andheavy fuel oil (HFO) (11 million bbl).

Coa'

1.9 Korea is the second largest coal importer in the x7orld (afterJapan). It imports its coal from Australia (40X), South Africa (25%),Canada (16%) and the United States (141). Total imports amounted to 24million tons in 1988 (15 million toe). Use of coal in the power sector (9million tons or 19% of total coal consumption) is expected to quadrupleover the next 12 years. Domestic anthracite, which is used mostly in thefabrication of briquettes for space heating, is the main source of energyfor an estimated 7.5 million, mostly low-income households. Anthraciteproduction, which benefits from protection against cheaper imports, hasremained so far stable at about 25 million tons (12 million toe). The

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Government is presently investigating ways of encouraging the abandonmentof uneconomic mines, including compensation to industries and re-employmentprograms for workers. Anthracite production is expected to decline from 26million tons (12 million toe) in 1988 to less than half this amount by2010.

Power Sector

1.10 Total electricity generation capacity was almost 20,000 MW atthe end of 1988, of which nuclear energy accounted for 33% and hydro, 11.Gross electricity generation during the year was 85.5 terawatt-hours (TWh),almost half of which originaLted from nuclear plants. Oil-fired thermalcapacity amounts to 7,300 MK. Part of this capacity, however, has beenshifted to gas-firing to absorb the cargoes of imported LNG which have beencontracted for, pending development of more attractive markets for the gas(para 1.18).

1.11 Power demand is expected to grow rapidly in the future: the 1988Power Development Plan (PDP) of the Korea Electric Power Corporation(KEPCO) envisages an average annual growth rate of 7.2% between 1989 and2001. To meet the increase in load, KEPCO proposes to bring on streamabout 15,700 MW of additional capacity over the next 12 years. Theproposed mi, of plants features notably a number of coal-fired thermalplants (9,000 MW) and nuclear plants (5,600 MW). Doubts as to thefeasibility of implementing this plan on schedule, however, have emergedrscently as KEPCO experiences increasing difficulties in siting new nuclear..Ld coal plants because of strong environmental concerns voiced by localpopulations. In the case of coal plants, these concernis arise in spite ofthe fact that all new plants are to be equipped with scrubbers to controlemissions of sulphur dioxide (SO2). In response to these difficulties, andto compensate for possible delays in its coal/nuclear program, KEPCO hasbeen reviewing its investment program to include the phased construction ofa (3,200 MW) gas-fired (combined-cycle) plant to be located at Incheonclose to Seoul.

Future Trends

1.12 The Korea Economics Energy Institute (KEEI) prepares regularupdates of its projections of Korea's energy balance. The latest set ofprojections (Annex 1) forecasts an average annual growth rate for primaryenergy demand of 5.2% between 1988 and 2000. This is to be compared to anexpected growth rate of GDP of 8X p.a., as the economy is expected toslacken because the manufacturing sector is reaching full capacityutilization. The implied energy/GDP elasticity of 0.65 is in line withwnat was achieved during the mid-1980s but may be somewhat optimistic as along-term parameter in view of the sharp growth in energy demanderperienced during the last two years as the impact of previous energyconservation programs started to erode. Petroleum is expected to maintainits predominant position, accounting for 45-50% of total requirements. Asindicated above, current power development plans anticipate a major rolefor imported bituminous coal, which would increase its share of Korea's

energy balance to almost 30X by the year 2000. Within this generalcontext, the potential contribution of imported LNG remains the subject ofmuch debate. The latest projections prepared by the KEEI foresee anincrease in LNG impoits from their present level of 2 million tons (2.6million toe) to 6.3 million tons by 2000 and 10.4 million tons by 2010.These levels would be equivalent, respectively, to 6.01 and 7.5X of totalprimary energy demand in these two years. KEEI's projections aresummarized in the following table:

Table 1.1: Korea's Energy Balance (1988-2010)(in million toe)

Average1988 1995 2000 2010 Growth Rate

p.a. (X)

Petroleum 35.5 56.9 66.0 77.5 3.6LNG 2.7 5.5 8.2 13.5 7.6Coal 24.6 33.1 39.5 51.9 3.4Hydro/Nuclear 10.9 15.5 21.8 31.5 4.9Renewables 1.2 2.2 2.8 5.6 7.3

Total Primary Energy 74.9 113.2 138.3 180.0 4.1

Source: KEEI

Government Policies in the Energy Sector

1.13 The main elements of the Government's present strategy in theenergy sector, as they are reflected in the Sixth Development Plan (1986-91), are to: (a) improve the institutional erficiency of the sector throughthe improvement of public enterprise performance; (b) gradually deregulatepetroleum product prices and trade, and emphasize market forces in theestablishment of economically efficient energy utilization patterns; (c)manage the growth in electricity demand through efficient pricing policiesand load management techniques; (d) monitor investwent planning to ensurethat capital expenditures are based on a least-cost development approach;and (e) promote cost-effective energy alternatives such as cogenerationschemes in the industrial and commercial sectors. Much progress hasalready been achieved towards these objectives. An area of concern is thatenergy prices have remained by-and-large regulated, with possiblydeleterious implications on the efficiency of energy use as discussedfurther in this report.

BL lbe Gma Iadusti

1.14 The Korean gas industry encompasses the import, regasificationand domestic transportation and distribution to consumers (through city gasnetworks) of imported LNG; the production and distribution (also throughpipeline reticulation) of manufactured gas in areas where LNG is (not yet;available; and the distribution of liquefied petroleum gas (LPG) in tanksor bottles. In many applications, pipeline gas and LPG are close albeitless than perfect substitutes. For households, both represent a greaterdegree of convenience compared to traditional fuels and their growingutilization over the years is a si&nifier of higher disposable incomes.Pipeline gas actually brings a higher degree of convenience compared to LPGand its use in urban areas reflects the high level of incomes achieved bypart of the urban population.

City Gas

1.15 The Korean city gas industry has a long, if geographicallyrestricted, history, dating back to the construction of a gas plant inSeoul in 1935. Manufactured gas, produced through coal gasification, wasavailable for home cooking until the plant was destroyed in 1950 during theKorean war. In 1972, the Seoul Metropolitan Government reinitiated a citygas service, providing naphtha-based manufactured gas and LPG-air mix ashousehold fuels in support of government efforts to meet the growingshortage of charcoal briquettes and help mitigate the emerging airpollution problem in Seoul.

1.16 City gas distribution was subsequently expanded to other cities,starting with Pusan in 1982. There are now 19 city gas companies operatingin Korea, seven of which are located in the Seoul metropolitan area. Thenumber of hol'3eholds supplied with city gas increased from 164,000 in 1982to 466,000 bj end-1986. With the introduction of LNG as city gas feedstockin the Seoul metropolitan area in 1987, the number of household consumersfurther increased to more than 500,000 in 1988. Because the introductionof LNG results in a reduction in gas cost, the pattern of city gas usewhere LNG is available is showing a gradual shift from its traditional roleas a cooking fuel to become a possible energy source for residential andcommercial space heating and selected industrial applications.

Liquefied Petroleum Gas (LPG)

1.17 Domestic consumption of LPG remained limited until about 1979.Starting with the construction of the first domestic oil refinery in 1964,and throughout the 1970s, Korean refiners exported most of their LPG toJapan. From 1980. this situation started to change rapidly as the use ofLPG as a cooking fuel began to grow, partly as a result of administrativemeasures. Consumption promptly exceeded the capacity of domestic refiners,resulting in large quantities of LPG having to be imported. A significantdevelopment has been the encouragement given to the use of LPG as anautomotive fuel, which led virtuallF the whole taxi fleet to switch to LPG

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between 1980 and 1983. LPG consumpLion reached 2.2 million tons in 1988,of which 531 was for residential and commercial use (including city gasfeedstock), 411 for transport, and the balance (6X) for small and medium-sized industries. Imports now account fot 581 of LPG consumption, most ofwhich comes from Saudi Arabia. The KEEI energy projections forecast LPGuse to grow at an average rate of 5.91 p.a. over the next two decades,reaching 6.4 million tons in 2010 (i.e., 561 of the expected LNGconsumption on an energy equivalent basis). The competitiveness of LNGvis-a-vis LPG will condition the penetration of natural gas in a number ofkey markets. Based on present price forecasts, KEEI's market shareprojections appear reasonable, although they may underestimate thepotential for LPG use in areas beyond the reach of gas infrastructure or atincome levels which would not justify the costs of gas distribution.

Natural Gas

1.18 In 1979, KEPCO initiated a study to establish the feasibility ofimporting LNG into Korea. A decision to negotiate with Indonesia forsupplies was taken by the Government in 1981 and a contract between KEPCOand Pertamina was signed in 1983, covering imports of two million tons ofLNG per annum for 20 years, starting in 1987 (with a potential additionalone million tons starting in 1989/90). The objective pursued by theGovernment in initiating this venture was essentially threefold: (a) todiversify fuel supplies away from imported oil; (b) to addressenvironmental concerns related to the use of charcoal briquettes for spaceheating in densely populated areas; and (c) to strengthen trading linkswith Indonesia. Use of natural gas was also seen as a means of improvingthe quality of service to consumers by providing a clean, convenient fuelat a competitive cost. Accordingly, the initial focus was on the eventualsubstitution of gas for char..oal and fuel oil in residential markets -- anobjective, however, which could only be achieved over time through theprogressive extension of distribution networks. To absorb the largequantities of gas required to trigger a gas import scheme, Korea had toresort to the expedient of burning gas in power stations originallydesigned for oil-firing. This has been done at a significant cost sinceLNG has been used to substitute lower cost HFO, although gas use in thermalplants has brought about significant environmental benefits.

1.19 When the decision to import natural gas was made in 1981, theGovernment initiated a policy of encouraging the development of city gassystems (in the Seoul area and in other cities). These systems were tooperate initially on manufactured gas as a means of building up marketsahead of the inception of LNG deliveries. The strategy of the Governmenthas been to license private distribution (city gas) companies to establishthe needed reticulation. LNG supplies started in 1987. Gas utilization in1988 was broken down into 1.9 million tons for power generation and 0.2million tons for city gas.

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1.20 Institutional Arrangements. In 1983 the Government establishedthe Korea Gas Corporation (KGC) as the agency responsible for the overallplanning, operation and management of the infrastructure necessitated bythe import of LNG, including in particular the receiving terminal at PyeongTaek and the transmission pipelines required to serve the Seoulmetropolitan area. KGC's main objective is to promote the use of LNG inaccordance with government policies and to plan the gradual expansion ofthe gas system accordingly. KVC has established a research and traininginstitute, in collaboration with Sofregas of France, for performing basicand applied research on gas technology and for training the necessarytechnical manpower. KGC falls under the jurisdiction of the Ministry ofEnergy and Resources (MOER), which directs policy making and overseesproject implementation in the energy sector.

1.21 As already indicated, an interesting feature of the governmentstrategy is that responsibility for the distribution of gas to the finalconsumers has been entrusted to private companies. To date, twenty onecity gas companies have been licensed to distribute natural gas, seven ofwhich have been converted to LNG. These companies are grouped under theumbrella of a City Gas Association (CGA), which acts as intermediarybetween the companies and the Government, KGC, local authorities andindividual equipment manufacturers. CGA is responsible for coordinatingthe preparation of the annual three-yeat investment plans prepared by thecompanies at the request of the Government, and for data collection,publicizing the availability of LNG, ad hoc advice to customers, etc. Moregenerally, CGA acts as the official spokesman for the city gas companies.

1.22 Another important agency in the gas sector is the Korea GasSafety Corporation (KGSC), which is responsible for the preparation of allsafety codes and regulations for gas distribution and utilization to beenacted by the Government. The scope of KGSC's activities is fairly broad,covering equipment and appliance testing, safety control research, and on-site inspection of gas plants, pipelines and customer equipment. Finally,the Korea Energy Management Corporation (KEMCO), which was established in1980 to assist with government efforts at rationalizing energy utilization,is involved in a number of projects having a direct bearing on gasutilization, including cogeneration and district heating schemes.

1.23 Infrastructure. Construction of the LNG receiving terminal acAsan Bay (Pyeong Taek), 60 km south of Seoul, and of the supply network tothe metropolitan area was completed in 1986 at a total cost of about W 440billion ($600-650 million at historical exchange rates). The terminal,which is built on a 420,000 sq m landsite, is equipped with four tank unitsof 100,000 cu m each capable of handling annually two million tons of LNG.Major facilities include piers, unloading, storage, boil-off gas treating,pumping, vaporizing and metering facilities and other auxiliaries.

1.24 After regasification, LNG is being supplied to the (4x350 MW)Pyong Taek power station located close to the terminal and, through themain transmission system, to the (2x250 MW) Incheon power station and theseven city gas companies licensed to operate in the Seoul metropolitan area

8

for residential, commercial and industrial use. The transmission systempresently consists of a 98-km high-pressure pipeline linking Pyong Taek toIncheon and a medium-pressure, 128-km long circular network, branching offfrom the main line and connected to the city gas systems through sevengovernor stations. There are no interconnections among the seven city gasnetworks which have been developed independently of each other within theirrespective areas of jurisdiction. KGC's entire facilities are managed froma central control station in Pyeong Taek city which assures a safe andstable supply through remote control and monitoring devices.

1.25 In December 1984, KGC commissioned Daelim Engineering Co., Ltd.,in collaboration with Sofregas, to undertake a feasibility study for anationwide gas supply system. The study, which was completed in March1986, recommended the construction of a national gas grid together withexpansion of the Pyeong Taek terminal a-id, at a later stage, constructionof a second terminal on the southern coast. The proposed investmentprogram featured in particular the construction of a 500-kn trunklineacross the peninsula to reach potential industrial base-load consumers inthe south (Ulsan, Pusan) while tying in isolated city gas networks en route(Taejon, Daegu, etc.). The study envisaged increased imports of LNG (5million tons p.a. by 2005) and a continuation of gas use in thermal powerplants both to smooth out the seasonal fluctuations in non-power demand(essentially because of the winter peak of space heating needs) and absorbthe step increases in gas supply that would result from new contracts. Thestudy forecast the stabilization of LNG use in power plants in the earlyl990s at about 40-50X of total projected supply on the average.

1.26 To establish the financial justification for this investment,KCC commissioned KEEI to undertake a gas demand and feasibility study basedon the original KGC technical study. The KEEI demand study was completedin April 1988. It forecasts that the use of natural gas would reach 2.3million tons by 1996 and 4.7 million tons by 2006. Or, the basis of theseprojections, the study provided a positive endorsement of KGC's investmentproposals. These proposed investments are still under review by theGovernment, mainly due to the large capital costs involved (W 530 billionor $800 million for the gas grid to the south only). A particular sourceof concern is the uncertain capability of the city gas companies to expandtheir networks and develop sales at a pace commensurate with the demandprojections assumed in the feasibility study.

1.27 A major recent development is KEPCO's significant revision oftheir future needs for natural gas. This review has been prompted by anumber of factors, including recent technological developments related tothe use of gas for electricity generation, and growing environmentalconcerns over alternative options (nuclear and coal). These two factorscombined have led to a significant reassessment of the role of the powersector as a gas consumer, which is now expected to shift from that of aswing consumer to that of a base-load consumer with its own economic andfinancial justification (which does not imply that gas-based generationcapacity would necessarily be operated as baseload facilities in a powersystem sense). These developments are discussed further in the followingchapters.

- 9 .

1.28 Gas Distribution. Until 1987, the city gas industry consistedof independent gas systems fed by gas plants and supplying gas mostly toresidential consumers, many of whom appear to be located in now developmentareas. The import of LNG and construction of a loop around theSeoul/Incheon area has made it possible to start supplying natural gas tothe city gas systems located in the Seoul metropolitan area. This in turnhas allowed them to deliver gas in much larger quantities, not only toresidential but also to commercial and industrial consumers. On the demandside, the introduction of natural gas has lowered the cost to consumers andtherefore expanded the potential market. For gas distribution, the mainissue is therefore how to capture markets for which gas has a comparativeadvantage, at least cost. As discussed further in this report, thepotential markets are large, although they are being continuously affectedby rapid changes in the urban environment (e.g., large housing developmentprograms, air pollution control measures affecting fuel choices).Capturing these markets, however, will require considerable expansion ofcity gas networks while maintaining the comperitiveness of gas vis-a-visalternative fuels, at least in those areas where gas use is not protectedby environmental regulations. As of the end of 1989, close to 1,900 km ofdistribution lines had been constructed in the Seoul metropolitan area.

Government Objectives and Main Issues

1.29 The focus of government policy when LNG imports were firstconsidered in the late 1970s was on the security of supply. Reflectingconcerns that arose as a result of the oil embargo and the oil price shock,GOK's main objective was to effect the displacement of oil as the mainsource of energy through diversification of both the type and origin ofenergy supplies. LNG supply was, and still is, regarded as offering areasonably guaranteed long-term energy supply source, isolated frompossible political disruptions in the Middle East. However, to thisforemost concern over security of supply, the element of energy quality hasrecently become an added motivation in considering LNG import on a largescale.

1.30 An important drawback to an energy strategy predicated in parton the import of LNG is that LNG trade is rather inflexible, with purchasecommitments having to be made well ahead of time because of the long leadtime needed for upstream investment in field development and liquefactionfacilities. This places the onus on the Government (as the direct orindirect contracting party) to undertake a careful assessment of thepotential demand for natural gas, and of the feasibility of theinfrastructure required to meet the expected level of usage, beforeentering into import contracts which will be binding over a long period.Another critical characteristic of LNG trade is that it translates into arather expensive gas price in end-use markets because of the highinfrastructure costs involved, and therefore in a narrower window ofopportunity than is the case in large gas markets supplied directly bypipeline. This issue is aggravated by the fact that Korea Ls an incipient

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market for gas and large investments in local distribution networks arealso required to bring the gas to consumers.

1.31 From these several angles, the import of LNG thus acquiresstrategic significance ir.asmuch as import would have to be effected on asufficient scale to justify the necessary gas infrastructure by bringingdown unit costs to a financially acceptable level. This will require aconcerted decision on the part of the Government, in part motivated byenvironmental considerations, to make LNG a major fuel source. Should theGovernment decide to embark on an expanded LNG import strategy, it willneed to develop an array of policies designed to bring about a sufficientlevel of usage and ensure that the available gas quantities are channelledto appropriate end-uses (taking into account the relative economicadvantage of alternative fuels as well as their relative environmentalimpact) so as to fully justify the large investments required. Thesepolicies will need to cover pricing issues and, possibly, fuel allocationregulations. Also, as the Government is keenly aware, gas penetration inthe economy will only be effective, or indeed feasible, if it isaccompanied by a concomitant development of the end-use equipmentmanufacturing industry, both in terms of output and quality. Actually,suitable pricing policies, fuel use regulations and the encouragement ofend-use technological development will have to be developed concurrently asself-supporting elements of an overall gas utilization strategy.

Cost of Capital

1.32 An essential aspect of the gas sector (from import toconsumption) is its high capital intensity. When comparing natural gas toalternative, less environmentally benign energy sources, which may be lessexpensive but would also involve far less capital investments by importers,transporters and consumers alike, the issue arises of an appropriatemeasure of the economic cost of capital in Korea. The official figure usedby GOK, and the one used for the base case analysis in this report, is 13%.However, given Korea's large foreign exchange surplus and easy access tointernational capital markets, this figure may overestimate the actual costof capital to the economy. As discussed further in this report, the impactof the cost of capital on the overall economics of LNG use may not be verylarge because gas use for electricity generation would entail considerablereductions in the capital requirements of the power sector, which wouldcompensate for higher costs elsewhere. Yet, variation in the cost ofcapital is likely to affect the preferred pattern of gas consumption, aswell as the potential contribution of each consumer category to commoninfrastructure requirements (which would have obvious pricingimplications). Accordingly, we have tested the sensitivity of investmentreturns to a drop in the cost of capital to 8%, which appears as areasonable lower bound (and actually is the figure used by KEPCO in its ownplanning exercises).

D 11 -

C. Environmental Issues

Background

1.33 Energy use is one of the major sources of environmentalpollution and, in Korea as in many other countries, the energy sector isincreasingly influenced by environrental concerns. Due to its highpopulation density and rapid industrialization and urbanization,environmentel concerns are actually probably greater in Korea than in manyother countries. Choice of energy directly affects air quality, especiallyin urban and industrialized environments, and to a lesser extent, waterquality and solid waste disposal; it can therefore be an importantdeterminant in reducing pollution.

1.34 venerally, ambient concentrations of S02, total suspendedparticulates (TSP), non-methane hydrocarbons (HC) and, to a lesser extent,carbon monoxide (CO) and nitrogen oxides (NOx) give rise to air pollution.Major sources of air pollution in Korea consist of emissions fromresidential heating and cooking, industrial processes, electric powerplants and automobiles. Air pollution in industrial areas arises from thehigh concentration of light and heavy manufacturing industries andprocessing industries, together with the increased generation ofelectricity required to support these industries. In general, residentialareas adjacent to industrial comr±exes both in the Seoul metropolitan aree.and on the south and southeast coasts bear the full impact of theenvironmental consequences of industrial activity without the protection ofdesirable buffer zones. Unfavorable topographical conditions aggravatethese impacts.

1.35 Another major cause of air pollution in densely populated areasis to be found in the combustion of fuels in stationary and mobile sources.In individual housings, b_Aquettes made of low-grade anthracite coal with arelatively high ash content are the predominant fuel for space heating.Domestic heating is estimated to account for about one third of total SO2emissions and almost three fourths of the CO emissions in the country. Theaverage height of the typical Korean house of 5-8 meters and thecomparatively low level of flue gases which have limited buoyancy combineto produce high ground level concentrations of air pollutants. The problemis particularly acute in high-pcpulation density areas such as the severalareas in Seoul and Pusan where density exceeds 50,000 residents per squarekilometer, and is aggravated by the fact that coal in the traditionalKorean home-heating system is burned at relatively low temperaturesgenerating high CO emissions. Another source of SO2 emissions in urbanareas is due to the common use of fuel oil for space heating in commercialand apartment buildings.

1.36 Overall, SO2 and TSP are the most serious air pollution sourcesin Korea. The average annual concentration of these pollutants in majcrcities as of 1987 is shown in the following table:

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CitiesPollutants Units Standards Seoul Pusan Kwangju Daegu

S02 ppm 0.05 0.056 I 0.039 | 0.014 I 0.055TSP I mg/m3 150 175 197 105 146

i.37 Since the enactmi3nt in 1981 of regulations designed to decreaseS02 concentrations, the annual mean S02 concentration in the city of SeoulNas decreased to 0.056 ppm from 0.084 in 1978. However, S02 levels inSeoul, Pusan and Ulsan still exceed the prescribed annual air qualityc'tandards. Moreover, daily standards are exceeded in many cities for alarge number of days each year. S02 concentrations in major cities areseen to vary remarkably as a function of the season, increasing sharplywith the winter heating season, but seem to remain relatively constant inpurely industrial areas. This pattern again indicates that SO2concentrations are strongly influenced by coal consumption for spaceheating in urban areas. A comparison with other industrialized countries.uggests that, with the exception of NOx, the level of air pollutants inKorea is quite h5gh. Further, continued urban and industrial growth willno doubt lead to greater pollution. With the rapidly growing vehicle fleetsize and concentration, the levels of NOx will also increase.

Governrnmt Reguaons

1.38 The Environment Conservation Law of 1977 as amended in 1986provides the general framework for government actions in environmentalprotection. The law was enacted to broaden the scope of pollution control,and a number of special laws were introduced subsequently to deal withspecific environmental issues, including the Air Pollution Control Law of1980. The National Environmental Protection Institute (NEPI) wasestablished as the entity responsible for the introduction and operation ofa rountry-wide pollution control system. NEPI maintains a dense network ofair and water quality monitoring stations: about two dozen automatic;tations have been installed in five major cities capable of monitoringtive air pollutants, and a large number of semi-automatic stations areoperating in other cities and in industrial complexes.

1.39 Ambient environmental quality criteria are provided inministerial regulations framed under the Environment Conservation Law.Standards for SO2 were set in 1980 and for five other pollutants, namely,TSP, CO, HC, NOx, and oxidants (ozone), in 1983, as follows:

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Classification Standards

SO2 Annual Average : below 0.05 ppm24 hour Average : below 0.15 ppm (should not be exceeded

more than 3 .imes a year)

CO Monthly Average : below 8 ppm8 hour Average : below 20 ppm (should not be exceeded

more than 3 times a year)

NOY. Armual Average : below 0.05 ppm1 hour Average * below 0.15 ppm (should not be exceeded

more than 3 times a year)

TSP Annual Average : below 150 mg/m324 hour Average : below 300 mg/m3 (should not be exceeded

more than 3 times a year)

Oxidants Annual Average : below 0.02 ppm(as 03) 1 hour Average : below 0.1 ppm (should not be exceeded

more than 3 times a year)

HC Annual Average : below 3 ppm1 hour Average : below 10 ppm (should not be exceeded

more than 3 times a year)

Alternative Measures

1.40 The principal scope for improvements in urban air quality isthrough a reduction of emissions from the use of anthracite for residentialheating, and to a lesser extent, from that of fuel oil for heatingapartment and commercial complexes. Industrial pollution in adjacent areasalso offers substantial potential for emission control. In the case ofHFO, emission reductions can be achieved through reductions in the sulphurcontent of the fuel. Control of the characteristics of coal briquettes,however, is hardly feasible and the only feasible alternative in this caseis to substitute a cleaner energy source such as diesel oil or natural gas.To date, measures for SO2 reduction have focussed on the use of HFO IJ andhave included (a) the installation of desulfurization units at petroleumrefineries; (b) the steady increase in imported supplies of oil with low

1/ In 1981, the maximum acceptable S-content of heavy fuel oil used inlarge urban areas was reduced from 4X to 1.6X. Moreover, KEPCO's powerplants located in the Seoul metropolitan area have to use 0.3XS HFO.

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sulfur content; (c) energy conservation including heat insulation; (d)introduction of central district heating systems as an alternative tocentral heating units for apartment buildings burning HFO; and (e) long-term contractual arrangements for natural gas import and its progressiveuse in residential, industrial and commercial markets. So far, however,gas use for space heating has been essentially restricted to commercialbuildings (HFO users) and to a lesser extent high-income individualhousings (diesel oil users), while largely missing the coal briquettemarket because of price. Regulations have been introduced that precludethe use of liquid fuels in some areas V, thereby providing a ready marketfor natural gas. Oil-fired power stations located in the metropolitanareas have also been instructed to convert their operations to gas,starting in 1991. Further tightening nf HFO characteristics is beingconsidered by the Government.11 This ipproach, however, is going to bemade increasingly difficult by the anticipated reduction in worldwideavailability of sweet crudes. The trend towards heavier crudes, which isalready apparent particularly in the Asia region, is going to lead to adeterioration in residual fuel oil quality, making it increasinglydifficult to guarantee a large and continuous supply of quality fuel oil.

1.41 While use of coal briquettes is estimated to represent the mainsource of urban pollution in absolute terms, little progress has beenachieved towards moderating its environmental impact. Facing difficultaffordability issues, the Government looks at rising incomes as the onlyfeasible solution to a seemingly intractable problem. However, the issueof the cost-effectiveness of the Government's approach to environmentalcontrol is open to question. In an earlier study, the Bank recommendedthat cost-effectiveness analysis of alternative environmental controlstrategies be undertaken before taking further steps to tighten emissionstandards. A good environmental data base was considered critical if suchcost-effectiveness comparisons were to be meaningful and reliable. In thisperspective, further improvements in the operation of the monitoringnetwork and the quality of data were recommended, together with a closerinvolvement of the academic community in NEPI's monitoring effort. Theseearlier recommendations probably still stand today. The issue of costeffectiveness in establishing environmentel policies (including theprescribed use of gas under certain circumstances) is further discussed inthis report.

. Starting in September 1988, all large commercial buildings (i.e.,with boiler capacity above 2 tons of steam per hour) located in specificareas were required to convert to LNG. This measure was first applied tothe downtown area in Seoul and is progressively being broadened as gasavailability expands. This measure, however, does not affect apartmentbuildings most of which continue to rely on (1.6XS) HFO for space heating.

./ Use of HFO in Tokyo is restricted to 0.2%S HFO.

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D. Energ Price Outlook

1.42 Relative prices of alternative sources of energy are an obviousfactor in assessing the merits of an LNG import strategy. GOK's earlierdecision to enter into a long-term LNG import contract was probablymotivated more by a perceived need to diversify sources of energy supplythan by pricing considerations per se. Similarly, pricing factors may notbe the foremost issue in future negotiations for additional import volumesas new considerations enter the picture, including trade balanceconsiderations, the opportunity for Korean industry to participate inupstream gas development in the supplier's territory, and more generallythe desire to strengthen specific bilateral relationships. Moreover, Japanhas so far acted as the price setter in the Far Eastern LNG market and islikely to remain so to a large extent in view of the large additionalimport quantities under consideration by Japanese utilities. The extent towhich Korea will be able to establish its own rationale in pricenegotiations therefore remains largely untested. This notwithstanding,price factors remain central to the establishment of a gas strategy forKorea, both as a determinant of the long-term demand for LNG and in theestablishment of a rational (optimum) gas utilization strategy (to maximizethe benefits of LNG use from a national standpoint).

The LNG Market

1.43 Following years of relative stagnation, there are indicationsthat the LNG market is poised for a period of renewed expansion. Twofactors are seen as having a direct bearing on this change in markettrends: first, increased uneasiness with nuclear energy and greaterawareness of the onerous effects of oil ar.d coal burning andcorrespondingly of the advantages enjoyed by natural gas in this respect;and secondly, recent technical advance in gas technology for use in boththe power sector and residential/commercial markets. Other relevantfactors in the LNG industry itself include greater decentralization with alarger number of producers and consumers; and increased flexibility in theway LNG contracts are being structured.

1.44 The decline in the energy needs of industrialized countriesduring the 1984-86 period in the face of moderate economic activity andcontinuing conservation efforts had a dawpening effect on the LNG marketwhich showed a relative stagnation during this period. Since 1987,however, energy demand has picked up as opportunities to reap additionalenergy savings through conservation become increasingly scarce partly dueto lower oil prices. This has led to a surge in natural gas pipelineimports in Europe and in the United States and a re-emergence of LNGtrading during the past 18-24 months. The bulk of the present and expectedincrease in natural gas demand is in the electric utility sector, spurredby the development of low capital cost combined-cycle units and the recentunprecedented growth of non-utility power generation, most of which isfueled by industrial gas-fired cogeneration units. The latter development

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has been particularly true of the U.S. market which is characterized byrelatively low-priced gas. The issue for Korea is to determine under whatconditions similar trends can be expected to develop under generally higherprice scenarios since gas has to be imported in the form of high-cost LNG.

1.45 Only about 13X of all marketed production of natural gas istraded internationally and LNG makes up 22X of this volume (or about 43million tons in 1988). There are presently seven LNG exporters and sevenimporters. The LNG trade is dominated by the Far East, particularly Japanwhich currently consumes almost three-quarters of the world's LNGproduction, and Indonesia which heads the list of exporting countries withalmost 40X of the trade. This concentration of LNG trade in the Asiaregion reflects in part geographical factors which preclude gas trade otherthan in the form of LNG, in sharp contrast with other international gasmarkets where pipeline tre.da is predominant. Japan is the region's biggestuser of gas, with 1987 sales amounting to 12.3 bcm, equivalent to 4.4X ofthe country's total energy demand. Japan sees gas as a promising andsecure long-term energy source, and it has played and will likely continueto play a leading role in LNG development. As more gas is being discovered Iin the region, only a portion of which is exploited, prospects for asignificant increase in traded quantities are good, with some projectionsactually forecasting a doubling in trade volume by the turn of the century,partly in response to a softening of contract terms (para. 1.47). The mainLLNG consuming market would remain the Far East, with 73X of the cargoesdestined to Japan, Taiwan and South Korea./

LNG Contract Terms

1.46 The inherent lumpiness of LNG technology has traditionallyresulted in rigidly set trade arrangements. LNG flows have usually beenorganized in discrete, vertically integrated projects consisting ofliquefaction plants, dedicated vessels for marine transport, anistorage/regasification facilities at the receiving terminal. Because ofthe large capital investments involved and the need for economies of scale,LNG contracts have traditionally featured largely inflexible (take-or-pay)delivery clauses (with no provision for resale) and rigid price formulasproviding for linkage to official crude prices. LNG deliveries at highload factors were seen to be required to ensure the viability of long lead-time upstream investment. Such lack of flexibility, however, has proved acritical impediment to the development of the industry. LNG trade hasrecently shown signs of maturing: during the last two years, criticalmodifications were made to contract terms uvder existing contracts and evenmore drastic changes are being considered for new contracts.

i/ Growth in LNG trade may actually be constrained by tanker capacity,which could clearly develop as an interesting export line for Korea(spearheaded by its own vessel needs, should it decide to expand LNGimports).

- I/ -

1.47 The oil price slump during the mid-80s was indirectlyresponsible for bringing about basic changes in LNG pricing. Followingcontract renegotiations in 1988-1989, linkages in price formulas wereshifted from official crude prices, which were often kept artificially highby producing countries (for taxation purposes), to realized export prices.While take-or-pay clauses in existing contracts have by and large beenmaintained, future contracts are likely to be more flexible and reflectmore closely the competitive position of gas in the market place. Newcontracts forms are already emerging: arrangements for new Algerion salesto the U.S. are based on a netback formula related to the actual end-usemarket value of gas, and take-or-pay clauses are generally become far lessstringent. One may expect this trend towards more flexible contract termsto continue, with prices eventually being set on a delivered basis andvarying with market conditions. In this context, a (partial) indexation ofLNG prices to coal prices may emerge in some cases as an attractiveopLion.11

1.48 The oil price slump also sfiW the onset of spot trading. Spotsales were initiated by Indonesia toward the end of 1986, followed byAlgeria and Libya. Spot trading was triggered by excess capacity both atliquefaction facilities and receiving terminals. Spot sales have so farbeen limited, partly owing to the improved flexibility of supplyobligations in long-term contracts. Future contracts are expected tofeature less constraining delivery provisions than the formerly bindingtake-or-pay terms although supplier'; will probably continue to expect someassurances from buyers of reasonable sales volumes. Moreover, analternative to spot sales has emerged in the form of winter-peaking salesat a premium (e.g., in recent Algerian contracts with U.S. and U.K.utilities). In view of these developments, the market share to be assumedin the future by spot sales is unclear, and the extent to which they couldbe relied on for long-term supplies is probably limited.

Price Outlook for Alternative Fuels

1.49 Import of LNG can be construed as a substitute for the use of arange of alternative fuels. These include a number of petroleum products(heavy fuel oil, diesel oil, kerosene, LPG), coal (imported and domestic)and, to a small extent, electricity. Most of these commodities are alsoimported by Korea, either directly (e.g., coal and LPG) or indirectly(e.g., domestically refined petroleum products). Expectations regardingfuture crude prices will affect a gas strategy inasmuch as (a) they willaffect the overall demand for energy; and (b) they will affect petroleumproduct prices. They are not, however, as central to the overall set ofissues as one might think since LNG contract terms have so far been and arelikely to remain linked to a large extent to crude prices in one way or

2/ Several gas contracts already provide for a partial indexation tocoal prices, including a recent Canadian pipeline export contract to theU.S.

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another. Still, future crude prices will impact on the competitiveposition of LNG vis-a-vis coal, which is central to the issue of LNG use asa fuel for power generation.

1.50 The forecasts of crude oil and coal prices used in this studyare close to the Bank forecasts. Moderate economic growth worldwide isexpected to lead to a slight increase in oil demand, creating theconditions for a moderate price increase, although the possibility of sharpshort-term disruptions (as shown in KEEI's own projections) isacknowledged. The proiections used in the study envisage a rise in crudeprices from $18.5/bbl in April 1989 (Arabian light reference price) to$22/bbl in 1994 and $27/bbl in 2002 (in constant 1989 prices). Coal priceprojections are discussed in para. 1.54.

1.51 Petroleum product prices traditionally show considerablevolatility because they are a function both of developments in the crudemarket and of future refinery invei4tments which in turn are a function ofthe industry's own price expectations, both regarding crude prices andproduct price differentials. For this reason, product prices, particularlythe price of HFO, often follow cyclical patterns which make short-termpredictions hardly relevant to a long-term energy strategy. The averageprice differentials between diesel oil, HFO and crude oil are the mostrelevant factors for our purpose since they condition the viability ofsecondary conversion investments in the refinery sector, and can serve asan indirect measure of benefits from the use of LNG as a substitute for oilproducts. The price of HFO is currently depressed because the maraetcannot absorb all the surplus fuel oil available in the market; over timethis should be expected to trigger investments in refinery upgrading whichmay in turn reduce the price differential between diesel and HFO. Yet,strong demand for middle distillates in the Far East are expected tocontinue to exercise upward pressure on diesel prices. The price forecastsused in this study (Annex 2) reflect a fairly conservative view of futureproduct price differentials: they show a slight increase over time in thediesel-HFO price differential (and a steady increase in the gasoline-HPOprice differential).

1.52 LEG Plices. The major use of LPG worldwide is as apetrochemical feedstock, substituting for naphtha. As a result, LPG priceshave historically tracked naphtha prices closely on a feedstock-equivalentbasis (about 90Z of naphtha CIF prices on a weight basis). (Due to hightransport costs, LPG prices (FOB) are far lower, and approximately in linewith crude oil export prices.) LPG prices have recently been somewhatdepressed mainly on account of the coming on stream of large additionalcapacity in the Middle East. While the additional exports are not reallyall that large compared to world LPG use, and can be substituted fornaphtha in the petrochemical industry without major modifications, theoutlook is for a continuation of surplus LPG production as the output ofnatural gas increases worldwide. A return to traditional pricerelationships between naphtha and LPG is therefore not expected over theperiod covered by this study, and our price projections incorporate theexpectation of somewhat depressed LPG prices compared to historical trends.

19

1.53 The domestic prices of petroleum products are subject to importtariffs and similar levies, excise and consumption taxes, and priceregulations at the refinery, wholesale and retail levels.PJ Due to theseregulations, the structure of domestic product prices does not followinternational price movements closely. As discussed further in the report,distortions in the petroleum price structure may impede the penetration ofgas in otherwise economically attractive markets. The current schedule ofposted prices is in Annex 3.

1.54 Coal Prices. Demand from power utilities in the Asia andPacific region in 1987 was about 233 million tons. This is expected toincrease to about 600 million tons by 2000 as most utilities in the regionmove towards increased use of coal. Of these quantities, about one quarterwould be supplied by imports. The coal reserves of Australia and othercoal-exporting countries seem to be sufficient to meet this increase incoal use. However, rapid increase in demand in the near term may create atight market in the 1990s because of production and shipping constraints.The coal price projections used in the study (Annex 4) follow the Bank'sforecast which envisages a growth rate of about 1% p.a. in real terms.These projections, however, may understate the relative price of coal tooil over the next ten years.

LNG Price Projections

1.55 The Asian LNG market is poised for significant alterations overthe next few years both in its volume and structure; however, the outlookfor future prices and contract terms is still somewhat blurred at thisstage. The most reliable prediction is that regional demand will go upsignificantly over the next 5-10 years, particularly due to the evolvingattitude of Japanese power utilities. Total LNG exports to Pacificcountries may reach 50-70 million tons by the end of the century ascompared with 40 million tons in 1988. Yet, the market is also becomingfar more competitive, with a number of potential suppliers considering thepossibility of increasing their market share or entering the LNG business.For Korea, a non-exhaustive list of possible suppliers includes Indonesia,Malaysia, Brunei, Australia, the U.S. (Alaska) and Qatar. Generally, thereis an expectation that the Asia basin will remain a buyer market for LNGfor a number of years until the incremental impact of new contracts startsbearing on the availability of gas reserves in the region. The short- tomedium-term outcome, however, is likely to entail some relaxation of cake-or-pay terms (in the form of an increase in the annual delivery swing ongas cargoes from 3% currently to possibly 10 or more). Price reductionsare also a distinct possibility. Further negotiations to allow discountsfrom crude price parity could provide signs of future market directions.

ii Ex-refinery prices are calculated on the basis of import prices,refining costs and a return on investment (10 after tax on equitycapital).

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1.56 Long-term price trends are if anything more difficult toforecast although one can safely assume that future gas prices would betied less mechanically to oil prices, with the price levels at which theregional Asia market will clear depending on the structure of gas demand aswell as on supply conditions. Note that, because of transport costs, therehas been so far little interference from the Europe/U.S. gas marketsdespite at times significant price differentials. This also couldconceivably change, especially if spot sales acquire greater prominence.

1.57 An important factor is that the strengthening of the LNG tradewill progressively lead to a commensurate tightening in the LNG shippingindustry. The previous availability of laid-up vessels has already beenessentially eliminated and a significant number of new vessels will have tobe ordered to handle additional LNG volumes. In the case of Korea, anyincrease in LNG imports would call for additional shipping capacity as thetwo vessels employed under the existing contract already operate at fullcapacity.

1.58 For the purpose of this study, we bave developed a number ofscenarios for the price of LNG under possible new contract(s), including abase-case scenario and three variants. LNG is presently priced on an FOBbasis at about 90% of crude oil, which translates as a few percentagepoints above crude on a CIF basis because of transport cost differentials.Our base-case scenario is posited on the same general characteristics asthe existing contract with the exception that transport costs are expectedto be linked to fuel oil prices rather than adjusted by a constant annualfactor. GOY has indicated that it might consider promoting the domesticmanufacturing of LNG vessels, should additional contracts materialize.This, however, would not necessarily result in a reduction in shippingcosts from their present levels ($0.65/mmbtu) which, if anything, mightrepresent an underestimation of long-term costs.

1.59 To allow for the testing of investment recommendations underalternative LNG price conditions, we have also developed three variantsthat encapsulate possible developments in the LNG market: under the firstvariant, FOB prices are pegged at 85% of crude which translates at close toparity on a CIF basis; under the second variant, the ratios are 80% and94%, respectively. Finally, a third variant reflects the possibility thatfuture LNG prices could be pegged partly on crude and partly on coal prices(to better reflect its value in some important end-use sectors,particularly the power sector); under this variant, the base price is setat 90% of crude (FOB) and the index is based on a 50-50 average of crudeand coal prices. Details of LNG price assumptions are shown in Annex 5 andsummarized below.

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Table 1.2: Energy Price Forecast a/($/GCal)

Net Present1991 1996 2001 2006 Value b/

LNGScenario I 15.5 17.8 20.1 20.5 17.0(base case)Scen.rio II 14.9 17.0 19.2 19.6 16.2Scenario III 14.2 16.2 18.3 18.7 15.5Scenario IV 14.9 16.6 18.3 18.5 15.6

Crude Oil 15.1 17.2 19.5 19.9 16.4

Heavy Fuel Oil 9.5 14.0 16.0 16.3 13.0Diesel Oil 18.8 21.6 24.0 24.4 20.4LPG (bulk) 16.3 19.1 20.8 21.1 17.1

Coal 7.8 8.4 9.1 9.1 8.3

a/ CIF prices in constant 1989 pricesb/ 1989-2007 period at 13% discount rate

1.60 The following chapters provide (a) an economic assessment of gasutilization in the residential, commercial and industrial markets and inthe power sector; (b) an assessment of possible long-term use of gas, basedin part on a review of the dema.-.d projections prepared by KEEI; (c) aneconomic evaluation of the investments required to meet this potentialdemand; and (d) a brief discussion of the institutional issues involved indeveloping the gas industry in Korea together with a number of generalrecommendations.

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2. GAS UTILIZATION

A. Introduction

2.1 Natural gas is a versatile fuel which can be used in a varietyof applications by residential, commercial and industrial users. In theresidential and commercial markets, gas is used mostly as a cooking fuel orfor space heating (and cooling). In industry, it can be used as a boilerfuel, in direct heat processes, or as a chemical feedstock. Gas can alsobe used for electricity generation. The competitive position of naturalgas vis-a-vis other fuels varies widely with the end-use process in whichit is applied; it is also considerably affected by the social costsassociated with the fuels' relative environmental impact. Because LNGcosts are generally bigher than those of gas supplied by pipeline eitherfrom a domestic or an export source, the potential economic uses of gas inKorea, which is entirely dependent on LNG supplies, are more limited thanin most other gas markets. Thus, use of gas as a chemical feedstock iscurrently excluded on the basis of current prices.

2.2 Although natural gas currently accounts for only a small part ofKorea's energy balance, it is already being used in a wide range of end-useapplications. Some of this use is based on the financial price of naturalgas; in other cases, the added convenience or quality offered by gas is themost relevant factor from the customer's perspective. But in largemeasure, current gas use is often dictated by regulation or othergovernment fiat. Thus, much of the gas use in downtown Seoul is dictatedby government regulations related to air quality concerns. Also, much ofthe gas network construction to date has been made possible by theavailability of subsidized government funding. Similarly, while KEPCO ispresently the major consumer of LNG, this is mostly as a result of its1ihavlng been instructed t pla;y the role of the "Cwing" consumer until gcecan penetrate other end-use markets, so as to insure full use of contractedLNG quantities. Finally, again out of environmental concerns, all powerplants in the metropolitan area initially designed for oil-firing wouldhave to run on gas starting in 1991. Notwithstanding the rationale andmerits of these government interventions in the process of gas allocation,a comparative analysis of gas utilization is in order to better underpinthe rationale for government policies in the sector.

End-Use Analysis

2.3 The purpose of this chapter is to delineate the scope foreconomic use of natural gas in Korea. This is done by way of a comparativeend-use analysis designed to assess the economic (and financial)attractiveness of using natural gas as opposed to other fuels while, in afirst step, ignoring differentials in environmental impacts.

23 -

2.4 The end-use analysis is intended to serve multiple objectives:

(a) to help build economically consistent gas demandscenarios and estimate the economic value of natural gasin alternative end-uses for the purpose of economicevaluation of the required infrastructure investments(Chapter 3);

(b) to provide a measure of costs involved in using gas ratherthan a cheaper but more polluting fuel in order to reduceenvironment-related social costs; and

(c) to provide inferences regarding sector organization andpolicy changes required of private firms and govermentbodies to ensure market penetration in the mostattractive end-uses (Chapter 4). In particular, caseswhere economic priorities are not supported by thecomparative analysis in financial terms suggest neededchanges in pricing policies or other regulatorymechanisms to alleviate distortions between economic andfinancial rankings.

Methodology

2.5 The methodology used for the comparative end-use analysis isdiscussed in Annex 6 (together with details of the analysis). It is doneon an annualized basis measured in terms of the ainnual energy requirementsof each given type of consumer (GCal/year). The analysis is done both infinancial and economic terms. The economic analysis is based on 20-year(discounted) averages of price forecasts, i.e. $17/GCal for LNG, $13/GCalfor HFO, $20/GCal for diesel oil and $17/GCal for LPG (cif values in 1989prices). The costs are built up from the point of energy production orimport to the point of end-use.V This allows the calculation of theimplicit Onetback value' of gas at that point in the system (i.e., thebreak-even price of gas that would equate the two cost streams from the

2/ Actually, for residential, commercial and industrial consumers, thepoint of comparison is set at the service connection. The costs associatedwith the service line, regulator and internal piping are therefore nettedfrom the netback value of gas. This reflects the current marketingstrategy of the city gas companies whereby consumers are required tofinance their own service line ('Including meter and regulator) as well asall internal piping requirements.

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consumer's perspective).PJ Further netting the actual import cost of gasfrom the netback value yields the consumer's potential contribution(available rent) to system investment, including basic infrastructure(terminal, trunk and city ring lines, and main grids) and distributionnetworks.

2.6 Korea is an incipient market for natural gas. The realizationof residential, commercial and to a lesser extent industrial demandtherefore hinges on the construction of new gas systems to serve theseusers. In that sense, Korea is at a disadvantage compared to maturemarkets where such systems already exist. Since gas prices are mainlydetermined by supply and demand in mature markets, the issue is whether gasprices would make the construction of high-cost gas systems attractive inan incipient market such as Korea. Since gas infrastructure is highlycapital intensive, the answer to this question is largely a function of thecost of capital. The end-use analysis is predicated on a 13X economic costof capital assumption. The extent to which a lower (8X) rate would affectthe conclusions is discussed in para 2.40

2.7 In the case of the Seoul metropolitan area, the existingterminal and trunk line infrastructure can supply significantly greaterquantities of household, commercial, and industrial consumption with cilyan incremental distribution system and customer investment. In thosecases, the existing terminal, trunk and city ring line should therefore betreated as sunk costs. In other areas, however, substantial additionalinvestment in basic infrastructure will be required to make gas availableand it is useful to estimate the potential contribution of each category ofconsumers to such investments. An attempt has been made to allocate theestimates of gas distribution costs by category of consumers in order toprovide for a more meaningful comparison of the attractiveness of each end-use. This kind of allocation, however, suffers from methodologicallimitations and is also subject to much uncertainty; conclusions drawntherefrom should consequently be considered at best as indicative.

End-Use Technology

2.8 Imptrtant inferences on institutional issues can be drawn fromthe comparative end-use analysis. The total economic cost of meeting anyparticular energy end-use is the sum of the economic cost of the energycommodity at the point of importation or production and the costs of takingthe commodity to the point of energy consumption. Cost comparisons betweennatural gas and a competing fuel must also include the costs associatedwith the end-use technology (stove, boiler, etc.) with appropriateadjustments to reflect differing end-use efficiencies, if any. In many

L/ In the case of residential consumers, the comparison is made on a'new' selection basis (as opposed to the retrofit of existing appliances),reflecting the present policy of city gas companies to focus on supplyingnew housing developments.

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cases, differentials in end-use costs and efficiency are found to be acritical part of the comparative calculus in determining whether gas iscompetitive. In the United States (and to a lesser extent in other large,well-developed natural gas markets) the end-use technology is veryimportant to gas's competitive position. This is because gas end-usetechnology is often lower in cost and higher in efficiency than similartechnology utilizing liquid fuels (and much lower in cost and higher inefficiency than the same technology for coal). In addition, in some cases,technology options are available for gas use but not for other fuels.

2.9 The issue of technology availability is therefore central to thewhole question of gas-use economics although it is not easy to address.In Korea, the energy technology market, at least as it pertains togas-firing equipment, in; not fully developed: some gas end-use technologiesare not available; others are available, but at costs and efficienciessignificantly less favorable to gas use than in other, more advanced gasmarkets. Finally, some technologies are not as readily available from asgreat a diversity of suppliers, or the technolrgies are not available insizes to match large ranges of scale of end-use. The comparative end-useanalysis allows an estimation of the importance of technology availabilityand inferences regarding changes needed (such the need to promote specifictechnologies) to facilitate penetration of the end-use market segmentswhere gas would be most economic. The incidence of technologicaldevelopment on the success of a gas utilization strategy (both in terms ofthe pace of market penetration and the access to the most attractive marketsegments) is further discussed in Chapter 4.

Coverage of Analysis

2.10 A series of representative end-use case analyses wereconstructed to examine the competitive position of gas from both thenational (economic) and financial perspectives. The relevance of manyconsumer-specific factors (e.g.. end-use technology efficiency, unitconsumption, etc.) calls for a sufficiently disaggregated analysis. Inaddition to the specific case of electric power, some 17 distinct caseanalyses were undertaken. These cases cover selected domestic, commercial,and industrial end-uses which differ in various ways and could thereforeimpact the comparative calculus. The results of this analysis aresummarized below; further background data are in Annex 6.

B. Residential, Commercial and Industrial Sectors

2.11 The strategy pursued by the Government has been to promote thedevelopment of city gas distribution networks so as to build up gas marketsprior to LNG becoming available. Seventeen city gas companies have overthe years been licensed to construct and operate gas networks. Thesenetworks were initially, and for those outside the Seoul metropolitan areastill are, operated with manufactured gas (either from naphtha cracking or

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LPG-air mix). LNG-based city gas thus needs to be compared to either oneof these two forms of city gas, in addition to a range of fuels includingkerosene, diesel oil (light fuel oil), LPG, HFO, and coal, as well as toelectricity in some applications.

2.12 The general conclusion of the analysis is that LNG-based citygas is economically attractive based on narrowly defined economic criteria(i.e., without consideration of environmental factors) in selectedhousehold, commercial, and industrial end-uses where:

(a) competition is against a high economic-cost fuel (at theburner tip). This category will likely always include LPGand city gas based on naptha and/or LPG; in some instances,light fuel oil (diesel) consumers also fit this category; or

(b) user is willing to pay a premium based on the convenience oraualitv offered by the use of gas. Cooking falls in thiscategory for most households; many industrial processapplications also fall in this category; or

(c) gas is used in combination with high efficiency end-usetechnologies which are readily available in other markets ifnot in Korea. Certain cogeneration and combinedheating/cooling technologies fit this category.

2.13 The case-specific conclusions are summarized in Table 2.1. Theresults are sensitive to a number of parameters: in the case of large-scaleconsumers, relative fuel prices are the dominant element, while for thesmall-end of the market in terms of fuel consumptio.i (i.e., the residentialand small-commercial markets) the magnitude of distribution and consumercosts becomes predominant. Hence, three factors are of direct relevance incharacterizing the range of economic uses of natural gas: (a) the socialpremium attributed to gas because of its cleanliness; (b) the Korean gasutilities' past experience of relatively high construction costs (para.3.34)W; and (c) the presently insufficient availability of gas-firingequipment in Korea, both in terms of volume and performance, compared tomore mature gas markets. Policy decisions and correcting measures relatedto these areas will have a direct bearing on the magnitude and pattern ofeconomically-justified gas use.

i/ As discussed in paras 3.36-3.37, our estimates of futuredistribution costs, and even more so our allocation of distribution costsby category of consumers, is subject to much uncertainty (both because ofmethodological limitations and insufficiencies in the data base). Thedemand scenarios on which the consolidated economic analysis presented inChapter 3 is predicated may therefore not be perfectly economicallyefficient in that they may conceal some implicit cross-subsidies amongcategories of gas users.

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Table 2.1: S=mmary of End-Use Analysis($/GCal)

Netback Available Average AvailableAlternative Value Rent at Distribution Rent at

End-Use Fuel of Gas Cons. Gate Costs City Gate a/

Residential

CookingIndiv. Houses LPG 49 b/ 32 105 (73)Apartments LPG 49i 32 29 3

Space HeatingIndiv. Houses Diesel 53 c/ 36 13 23Apartments HFO 22 5 6 (1)

%ommercial

Space Heating HFO 9-18 (8)-i 6-1 (13)-(0)Heating&Cooling HFO&elec 51 34 1 33

HotelsSp. Heat. HFO 20 3 (0) 3Htg&Cool. HFO&elec. 38 21 (0) 21

RestaurantCooking LPG 44 27 15 12

Space Heating w/Cogeneration HFO&elec. 27 10 2 8

Diesel 25 8 2 7

Industrial

Boiler Fuel HFO 20 3 0-3 0-3Direct HeatNew Diesel 22-23 5-6 0-3 3-6

LPG 25-26 8-9 0-3 5-7

Retrofit Diesel 18-23 1-4 0-3 1-6LPG 20-25 3-8 0-3 3-8

a/ Assuming an average price of gas of $17/GCal (CIF).b/ Based on lower-bound estimate of willingness-to-pay in city gas

networks.c/ Assumes gas is used both for cooking and heating.

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(1) Residential Market

2.14 Residential consumption is often referred to as a premium marketfor natural gas. However, if the substituted fuels are generally of highvalue, and gas brings an undeniable element of convenience to theconsumers, the unit investment costs are also high, with a large number ofcustomers each consuming relatively small amounts of gas. Moreover, thespace heating demand is highly seasonal, which aggravates the unit costelement. A close review is therefore needed in order to establish whethercontinued government intervention (through subsidized funding ofreticulation investment or other means) is justified to promote the use ofgas in this market segment.

Domestic Cooking

2.15 In the absence of pipeline gas, LPG is the fuel of choice fordomestic cooking. Compared to LPG, city gas (from LNG or manufactured gas)brings added convenience although at a significant added cost, and itspenetration of urban markets over the last 5-10 years reflects thesignificant increase in domestic income achieved by the urban population.LPG is thus the fuel with which gas needs to be compared.1V The issue ofquality and convenience is very important as cooking is a consumptiveenergy use, and therefore fuel preference, and hence 'willingness to pay'(and economic benefit), is strongly influenced by qualitative factors,particularly as household incomes rise.

2.16 While the introduction of LNG as a city gas feedstock results ina reduction in the cost of pipeline gas, city gas remains more costly,albeit more convenient, than LPG. The difference is very substantial forindividual housing, less so in the case of apartment dwellings. Thequestion is whether the consumer's preference is such that the additionalcosts are warranted economically ProfitAble city gas operations haveestablished that single-dwelling consumers are willing to pay a price forconvenience higher than LPG-equivalent. However, this (financiallyrevealed) lower bound of the consumers' willingness-to-pay ($49/Gcal) issignificantly lower than the estimate of economic costs of gas, includingdistribution ($122/GCal) (suggesting some cross-subsidy in the existing gastariff structure). Absolutely clear-cut inferences as to the economicviability of gas use for cooking in individual housings are thus notpossible based on the available data base. Although there is a possibilitythat gas distribution costs are somewhat overestimated, the issue iswhether domestic consumers are willing to pay for quality the full extent l

of economic costs of gas distribution. A detailed assessment of possibleembedded subsidies (or cross subsidies) in the current tariffs would

1I/ Although coal-based domestic cooking remains prevalent amonglower-income classes, it is not equivalent to a gas-based alternative on aquality and convenience basis and is therefore not considered.

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therefore be required before the Government decides to promote LNG as acooking fuel in individual housing units more aggressively, particularlysince an acceptable alternative exists in the form of LPG.

2.17 In the more common case of individual apartment uni;s, anadditional alternative would consist of LPG delivered in bulk to theapartment building and piped internally to individual apartments. Thisalternative would be equivalent in convenience and quality to direct accessto city gas, while being probably cheaper both in economic and financialterms (despite unit costs of gas distribution for apartments beingsubstantially lower than for single dwellings). If confirmed to befeasible, this alternative would undermine the rationale for city gas-basedcooking by apartment dwellers (unless coupled with gas use fc.r spaceheating as argued below). We therefore recommend that the technicalfeasibility of this alternative be investigated.

Space Heating

2.18 The choice of heating fuel by households varies both with thetype of housing and income levels. The traditional Korean heating systemoperates with anthracite, which is heavily subsidized and partly for thisreason remains widely used. Single family dwellings at higher incomelevels normally rely on modern boilers burning light oil (diesel).Apartment buildings which represent an increasing proportion of urbanhabitat, and indeed account for most new developments, meet their spaceheating needs by way of central heating facilities which usually operate onHFO. Individual heating systems in apartment buildings are rather rare(and are indeed barred for more than seven-storey buildings). Districtheating systems are now given increased attention in city planning. Twosuch systems are already in operation in Seoul and additional ones are atthe planning stage. District heating, which is often considered in thecontext of (heat/power) cogeneration facilities, is discussed separately(paras 2.54-2.62). Since gas, contrary to other fuels, can be used bothfor cooking and space heating, the inter-fuel comparisons discussed in thefollowing paragraphs assume that gas, if used for space heating, would alsonaturally be used for cooking.

2.19 Domestic Single Family. Comparing the use of gas (for cooking band heating) with a combination of LPG for cooking and diesel for heatingunderscores its lack of (economic and financial) competitiveness in theindividual housing market because of high unit costs of distribution,unless the convenience element in cooking is taken into account. On anincremental basis, however, gas use for heating is shown to be economicallyattractive if one assumes that gas would be used as a cooking fuel in anycase. Moreover, if one applies the lower bound of the consumer'swillingness-to-pay (as established by the ongoing gas tariff) as a measureof benefits derived from the use of gas for cooking, the combinedutilization of gas for cooking and heating is only slightly lesseconomically attractive than the gas/diesel alternative. On a financialbasis, however, diesel remains substantially more attractive than gas (by

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about 10), which points to the need for a more disaggregated gas tariffstructure to better differentiate between cooking loads and the largerspace heating loads which offer scope for substantial economies of scale insystem designW.

2.20 Coal-based heating systems provide a distinctly lower standardof convenience than oil- or gas-based systems. Yet, a gas/coal comparisonis also instructive since it is the Government's intent to reduce theincidence of anthracite burning in urban areas for environmental reasons.The comparison indicates, however, that the coal-based alternative, coupledwith LPG cooking, is likely to remain prevalent in the absence ofregulatory directives and/or special incentives to compensate for the highretrofit costs involved in a switch t' J cleaner fuel. For lack ofreliable information on the economic cobt of domestic anthracite, thefinancial price was used in the economic analysis, which overestimates theattractiveness of anthracite use. Yet, even on this basis, anthracite isshown, for new systems, to bls less attractive (both economically andfinancially) than diesel oil and not significantly more attractive thangas. For existing consumers, however, the retrofit costs would beprohibitive and have in effect prevented a more massive shift from coal todiesel. For the same reason, coal users are less likely to be willing topay the high costs of pipeline gas for cooking, which would have improvedthe case for gas substitution (for both cooking and space heating). Thefinancial argument against fuel substitution away from coal is thus quitecompelling and a coal substitution strategy motivated by environmentalconcerns will call for substantial government intervention (para. 2.76).

2.21 For apartment buildings, one needs to distinguish betweencentral heating facilities (usually HFO-fired, but also possibly burninglight oil or gas), individual heating systems (light oil or gas) anddistrict heating. The planning practice of city gas companies is to assumethe availability of gas for cooking. As mentioned in para 2.17, thepossible alternative of piped LPG needs to be investigated. Also,consideration of the individual versus central heating options is importantfor multiple reasons: as incomes rise, households will increasingly wantthe control and convenience of regulating their own space heating, while,at lover incomes, a family may not want the burden of common heatingstandards if these are higher than their own. Examination of theindividual versus central system also allows consideration of importantinstitutional issues related to first costs, including whc bears the cost,available financing, etc., all of which can be expected to impact directlyon fuel and technology choices.

2.22 A comparison of options available, including the central andindividual gas alte.:natives, a diesel (light fuel oil) individual optionand a central heating Bunker-C (HFO) option shows the Bunker-C option to beleast-cost both economically and financially for new buildings. However,

11/ Unit consumptions are in a ratio of about 1:7 on an average basis;taking the seasonal variations in heating loads and the daily variations incooking loads into account, the relevant ratio is probably about 1:3.

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in economic terms, the individual gas option is hardly distinguishable (andactually becomes the most competitive option when using a lower discountrate of 8x). This suggests that, for new construction, individual gasheating may be attractive, particularly since the individual convenienceelement would increase its attractiveness to the consumer. Distortionsbetween financial and economic prices, however, will be a barrier to suchuse: in financial terms, Bunker-C for central heating is much cheaper thangas. Although an individual gas option will be hindered by the question offirst cost financing, as well as by government regulations preventingindividual heating facilities in buildings of more than seven stories, werecommend that this approach be considered as a possible component of acost-effective pollution abatement strategy.

2.23 Gas use in central heating facilities would only become feasibleif the Government decides to further tighten existing regulations on HFOuse in urban areas. The comparison shows the eccnomic premium between HFOand gas for a typical (600 units) apartment building to be equivalent toabout S4/GCal of HFO (or $42/ton) IV; this is significantly less than thediesel/HFO differential but higher that the premium currently applicable tolow-sulfur fuel oil on international markets, which would therefore seem tobe the most logical first step to improve the environmental impact ofapartment heating loads. In the absence of specific governmentregulations, it would appear that gas may be in a better position topenetrate the apartment heating market through its use in district heatingschemes (paras 2.54-2.62) than as a central heating fuel.

(2) Commercial Market

Space Heating

2.24 The intensity of energy use, which impacts on the scale of gasinstallations, is the most critical factor when analyzing the scope for gasutilization for commerciRl spAee beating where HFC 's the fuel normallyused. Two bounding cases were considered to characterize thisrelationship.lM The case of combined heating/cooling facilities wasconsidered separately, as well as that of hotels (because of their greaterenergy needs per unit of space).

2.25 Alternative fuel options include diesel-, Bunker-C- andLPG-based boiler systems. For small-scale commercial consumers, LNG citygas is clearly not competitive with Bunker-C fuel oil, either in financialor in economic terms, despite a significant difference in boiler

12/ On a marginal basis (i.e., ignoring any contribution toward thecost of basic gas infrastructure but including gas distribution costs).

13/ The range of floor space considered goes from 3,300 sq m (1,000pyong), which represents the lower end of commercial buildings served byKukdong City Gas Co. in downtown Seoul, up to 39,600 sq m (12,000 pyong).

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efficiency. This is because, for smaller commercial buildings, gas-relateddistribution and customer (boiler, service connection, piping) costsaccount for most of the expenditures. However, the impact of thesedistribution and customer costs is dramatically lessened at larger scaleand higher annual gas uses. Thus, for commercial consumers with floorspace of about 40,000 sq m, Bunker-C and gas are almost equivalentalthough Bunker-C remains much cheaper in financial terms. This suggeststhat at larger scales, natural gas may be an economic alternative forcommercial space heating, although such a choice will not be made based oncurrent financial prices.

2.26 Government regulations now preclude the use of liquid fuels in -commercial buildings in downtown Seoul. Given the environmental benefit ofusing gas, this policy appears appropriate for large buildings. However,for smaller buildings, additional examination would be useful to determinewhether such fuel-switching, environmental regulations are grounded onappropriete economic rankings, taking into account in particular that atthe low end of the market, (low sulfur) diesel would appear to be moreeconomical than gas while offering a reasonable environmental impact.

2.27 In the case of hotels, which exhibit a much higher (per unit ofspace) energy use, Bunker-C is again the least-cost option in financialterms, but in economic terms LNG gas is now lower in cost. This reinforcesthe conclusion that at larger scale and/or higher usage where the impact ofinfrastructure anw customer costs are lessened, natural gas may be aneconomic alternative for commercial space heating. But again, such choicewill not be made based on current financial prices.

Restaurant Cooking

2.28 Comparative analysis also shows gas to be quite attractiv'e inthe restaurant cooking market. This is due to the fact that competition inthis market segment is essentially against fuels which also start out withhigh energy commodity (as opposed to delivery and end-use technology)costs, in particular LPG. The attractiveness of gas use increases with thesize of the restaurant as the weight of the capital cost components (intotal costs) decreases with the level of usage.

High End-Use Efficiency Options

2.29 The commercial market offers the potential for a number of end-use options which achieve high end-use efficiency by meeting jointly twoenergy end-uses, thereby considerably enhancing the attractiveness of gasutilization from both economic and financial standpoints. These optionsare based on technologies not yet widely marketed in Korea although theyshould be central to an effective gas utilization strategy.

2.30 Combined Heatina and Cooling Systems. These systems, which arebased on gas-fired absorption technology, would make gas quite competitive

33

in economic terms (compared to the HFO/electricity alternative). Moreover,increased gas use in summer to fuel air-conditioning systems would helpimprove system load factors. Financial pricing, however, could be a marketbarrier that may impede gas penetration of this attractive market segment.

2.31 Cogeneration of Elec Xicity and Steam. Commercial offices canalso make use of internal combustion engine technology for the jointproduction of electricity and heat.1W A review of such cogenerationoptions is complicated by the range of technical alternatives availablewhich vary in their mix of electricity, steam, and heat outputs and can beused to meet a wide variety of end-uses: lighting, shaft power, spaceheat, process heat, space cooling and dehumidif£zation. Furthermore, theoperating procedures can vary from thermal to power load following and caninvolve power sales to the grid or only in-house use.

2.32 The economics of cogeneration are sensitive to the transferprice of electricity which accounts for more than one-half of total costs.Valuing electricity at $0.10/kwh, gas-based cogeneration schemes is shownto be economically attractive for a wide range of sizes.U/ Thus, incomparison to a boiler-only option (i.e., for steam only), the marginalcost of cogenerated electricity in a typical (gas-fired) commercial unit isestimated at about $0.07/kWh. Cogeneration technology (both for commercialand industrial applications) holds much potential for cost-effective gasuse and its availability needs to be promoted, particularly among lower-scale users.

(3) Industrial Sector

2.33 The potential use of gas in the industrial sector falls underthree major headings: process heating (e.g., in furnaces, kilns, dryers,etc.), steam generation (i.e., in boilers and cogenerators) and feedstockuse. Interfuel competition between natural gas, oil and coal in the boilermarket is largely determined by fuel prices, including handling and storage

I4/ Cogeneration is a technology whereby electricity and heat a-eproduced together, the heat being used to heat and cool buildings (ty meansof absorption chillers) or in some other (industrial) processes requiringheat. The advantage of cogeneration is that, under certain conditions,joint production of heat and electricity offers economies of scope comparedwith the generation of electricity in a central station and the productionof heat in a separate boiler. Gas-fired cogeneration systems have becomequite common in well-developed gas markets such as the U.S. Such systemscan also be operated with distillate oil; the other alternative for thepurpose of economic evaluation is that of producing heat in a separateboiler (gas or fuel oil-fired) with electricity purchased from the grid.

DJ However, diesel cogeneration would be the least-cost option on thebasis of financial prices.

costs, and environmental regulations. In contrast, the relative merits ofeach fuel for process heating vary .-tth each specific application.

2.34 The main advantage of natural gas in industrial applicationslies with its ease of use and, in some cases, in its quality as a fuel.Additional benefits result from lower operation and maintenance costs ofenergy equipment (particularly compared to coal), and from the fact thatgas-firing eliminates the need to carry fuel inventories. Despite theseadvantages, there are limited prospects for the use of gas as anunderboiler fuel, except for environmental reasons in densely populatedareas; gas should then be targeted to those industrial applications callingfor higher operating temperatures which cause greater emissions of nitrogenoxides. The poor competitiveness of gas in the boiler market is partly dueto the fact that domestic gat boilers have not yet reached the efficiencystandards achieved in more Pdvanced gas markets. However, gas can competeeffectively where its quaitty or some other characteristic is relevant toits end-use, such as in a number of direct heat and drying processes wheregas enjoys a clear, albeit difficult to quantify (generically), technicaladvantage (because of its clean combustion and better flame quality due toits paucity of impurities, easy heat control, and other factors).

2.35 Industrial utilszation is characterized by high unitconsumption. Five separate cases of direct heat applications were examinedto allow for a sufficient range of assumptions for gas utilization andconversion (retrofit) costs, covering the glass industry, metal industry,food processing industry, textiles industry, and electronics industry. Inall cases, the assumed substitution is either LPG or diesel or some mixtureof the two fuels. To reflect the salvage value of equipment in place, alOX salvage value (retrofit) case and a lOOX value (new/whole replacement)case are used for bounding characterizations of the conversion costsinvolved. In all cases, gas is shown to be the fuel of choice althoughdistortions in the financial rankings indicate that pricing could be asevere barrier to gas penetration in the sector. This points to asubstantial potential for economic use of gas in the industrial market.However, gas will be able to make large forays in the industrial fuelmarket, and thereby achieve significant economic gains, only if supportedby an intensive R&D effort in gas technology development.

2.36 The chemical feedstock segment of the industrial gas market doesnot appear to hold much potential in Korea, at least based on presentprices. At this point, international prices of ammonia and other methane-based chemicals (e.g., methanol), which are driven by low-cost producerselsewhere, would not justify LNG-based production in Korea. In that sense,the situation of Korea is ratbar different from that of most other gasmarkets where, under certain conditions, use of (methane) gas as a chemicalfeedstock may be justified.

35

(4) Conclusions

2.37 The above comparative end-use analysis suggests that gascompetes effectively with other fuels (both economically and financially)only in selected end-uses. These include special high-efficiencytechnologies, and cases where its quality or other characteristics allow itto compete with all fuels, including those with low commodity costs such asBunker-C, on a non-price basis. In the residential market, gas willcontinue to penetrate the cooking market because of the added convenienceit brings to consumers compared to bottled LPG. Except as dictated byenvironmental and other regulations, retrofit customers are largely ruledout (with the possible exception of LPG for cooking or other use where theconvenience element would be predominant). As shown in Table 2.1, thecapacity of each category of consumers to generate sufficient surplus fromfuel-switching to cover part of the cost of the main gas infrastructure(over and above their estimated share of distribution costs) varies widely.Moreover, there are frequent distortions between economic and financialrents. The analysis thererore suggests the need for a more selectiveapproach by the Government in supporting reticulation investment by thecity gas companies through subsidized funding (from the Oil Fund). Effortsshould be made to target financial incentives to priority market segmentsin lieu of the present, largely indiscriminate approach. The alternativeof providing a greater proportion of government support directly to theconsumers also needs to oe investigated. This would allow Government tofocus its intervention on those categories of consumers for which theenvironmental factor is most relevant but where fuel switching is seen torequire special incentives.

2.38 City-gas operations have so far concentrated on the cooking,water heating and part of the space heating markets. The analysisindicates that part of the commercial and industrial energy markets alsooffer attractive opportunities for LNG use (particularly if one takesenvironmental factors into account as discussed in paras 37-38).Experience elsewhere has shown that fuel demand by industries is usuallycharacterized by a high price elasticity. In Korea, however, the low priceof fuel oil in relation to other fuels, as established by the Government,has so far largely precluded gas penetration of the medium- to large-sizedboiler fuel market. It is also apparent that switching from HFO boilers toa more sophisticated and efficient use of energy in (gas-fired)cogenerators or advanced heating/cooling systems in large buildings wouldalso be hampered by the low price e. fuel oil. Conversion of HFO users togas has so far occurred mainly on account of fuel use regulations motivatedby environmental concerns. Alternative approaches combining priceadjustments (to better reflect true economic values) and financialassistance to consumers (for equipment financing) need to be developed.Such combinations of incentives and disincentives should be set both on anend-use basis and a regional basis.

2.39 Our base case scenario assumes that LNG (under the existing aswell as future contracts) would continue to be priced close to crude oilparity on a CIF basis. On this basis, the competitiveness of natural gas

36

in the large commercial/industrial boiler market would be justified onlywhen connections to the grid would involve small additional costs. Areduction in the price of LNG of say 10 would not significantly affect theoverall pattern of gas use, but it would ease the case for gas utilizationin the boiler market where interfuel competition is the most severe. Theimpact of LNG price reductions on the economics of infrastructureinvestments is discussed in Chapter 3.

2.40 The end-use analysis was tested to a lower estimate of the costof capital (8X). Results are summarized in Annex 7. As for the impact ofthe price of LNG, a lower cost of capital would not affect the overallpattern of gas use (as justified economically). It would, however, improvethe economics of gas use, particularly for cases where either the costs ofgas distribution or those of end-use equipment are significant. Thus, areduction of capital charges would considerably strengthen the economicprospects of residential distribution, although the netback value of gas(as derived from the consumers' willingness-to-pay revealed by the currenttariff) would still remain insufficient to cover the full costs ofdistribution. Cogeneration projects would also see much improved returns.

2.41 Need for Additional Case Coverage. While attempts were made toinclude a reasonable coverage of potential users to provide the foundationsfor a general assessment of the economics of gas imports, additional caseswill be needed to further structure the government strategy in the sector.Examples of additional needed cases are ones examining low-cost high-efficiency end-uses such as space conditioning with cogeneration and/orgas-fired absorption systems, using technology not yet, or only recentlybecoming, available in Korea, and the many industrial process applicationsthat benefit from the quality or other characteristics of gas use.

2.42 Costs and Efficiencies of End-Use Technologv. Our case studyanalysis is based largely on costs and efficiencies of end-use technologyas is presently available in Korea. However, equipment and appliancesavailable domestically often do not provide the comparative advantagesenjoyed by gas-using technologies in well-developed gas markets such as theU.S. Cost reductions (either capital or non-fuel operating costs) orefficiency improvements would affect the competitive position of gas in amajor way. Access to the proper technology would also help redresspossible market barriers due to fuel price distortions. To our knowledge,no survey of technology availability in Korea has been made to date andthis should be an important item in the development of a gas utilizationstrategy. A review of gas technology available in the United States wascarried out by consultants commissioned by the Bank in preparation for thisstudy;z1 the results of this review could provide the starting point for anassessment of technology availability in Korea. We recommend that such asurvey be carried out, leading to a plan of action for the development ofappropriate technologies and encouragement of their broader availability inthe market place.

16/ 'Korea Gas Sector - Review of End-Use Technology,' deLucia andAssociates, 1988.

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C. Gas Utilization for Electric Power Generation

Introduction

2.43 There is keen interest worldwide in natural gas as a fuel forpower generation. Recent projections by the American Gas Associationanticipate that increased gas consumption by power utilities will accountfor most of the growth in overall U.S. gas demand, increasing from 80 bcmin 1988 to 175 bcm by 2010 (i.e., a 3.6Z p.a. growth rate). Japan hasactually pioneered the large-scale use of gas for power generation,allocating most of its LNG imports to this end (as much as 831 in 1987),and the growing needs of its power utilities are behind much of the largeincrease in Japan's LNG demand anticipated over the next ten years.Similarly, the U.K. is now allocating a large share of its gas to privatepower projects. A number of factors have caused this keen interest in gas-based generation, in particular continued growth in disca,vered gas reserveswhich are now perceived as sufficient to support large-scale powerdevelopmentiLJ; the cleanliness of gas as a fuel; the debate surroundingnuclear energy; and recent technological advance which has led to criticalimprovements in the design and performance of combined-cycle power plants,particularly (although not exclusively) when fired with natural gas. Thesefactors are of particular relevance to Korea's current energy outlook andwill have a direct bearing on its potential use of LNG over the next 10 to20 years.

2.44 The alternative technological options available to KEPCO forfuture power system expansions include nuclear plants, coal-fired and oil-fired conventional steam power plants, and combined-cycle plants which arenormally gas-fired but can also be operated on distillate oil (and are alsonow integrated in recent coal gasification processes; para 2.71). Gas-fired combined-cycle plants have for some time been considered as anattractive option to meet peak and intermediate loads because of their lowcapital costs, short construction period and high efficiency. Furtherefficiency improvements in gas turbine technology have significantlyenhanced their attractiveness as base-load facilities. In particular,their reliability and availability ratios have increased markedly and theyare now routinely and reliably used in baseload cycles.121 A combination offactors somewhat specific to Korea has further enhanced the potentialcontribution of gas-fired combined-cycle plants towards meeting part ofKorea's future electricity needs, including (a) the increasing difficultiesexperienced by KEPCO in identifying suitable coastal sites for new nuclear

1/ In the past decade alone, proven gas reserves in the Asia/Pacificregion have doubled to nearly 235 trillion cubic feet (tcf) in 1988, i.e.,about a third more than oil reserves. At current rates of production,known gas reserves would last 60 years, compared to 12 years for oil.

1]/ Firing temperatures in excess of 12500C are now achievable withgood expected availability (over 90S).

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and coal-fired plants (while combined cycle plants can be installed inlandor at sites otherwise unsuitable for nuclear or coal-fired units, inparticular close to urban centers); (b) the public's increased uneasinessvis-a-vis further nuclear expansion; and (c) stricter guidelines for airpollutant emissions, water discharge and solid waste disposal.

2.45 Clearly, environmental considerations explain much of thecurrent interest in gas-fired combined cycle technology throughout theworld. Combined-cycle plants also benefit from low c'spltal costs andrelatively short engineering/construction periods, and offer modular designfeatures that allow utilities to add generating capability in smallincrements with short lead-times, minimize concentration of financialcapital and better respond to uncertainties in power demand outlook. Also,gas firing minimizes fuel preparation and handling problems. One wouldexpect that similar considerations would apply to Korea at a time when anextensive expansion of the power system is being considered in response tothe anticipated growth in power demand.

Economic Comparison of Alternative Generating Options

2.46 The correct method to select a least-cost expansion path forelectric systems is through an optimization of system development to serveforecasted loads with given reliability criteria. Such an exhaustivesystem analysis, based on WASP or other system simulation methods, fallsbeyond the scope of this study although it would clearly represent alogical follow-up. KEPCO is using WASP simulations on a routine basis tooptimize its power development program. It would be useful to update theseanalyses based on recent data on combined-cycle efficiency and reliabilityperformance, as well as with broader assumptions as to the possible futureavailability of natural gas (i.e., outside the Seoul metropolitan area) soas to facilitate the planning of gas infrastructure.

2.47 A common simplified approach to the evaluation of alternativegenerating units consists in the calculation and comparison of unitgenerating costs (busbar energy costs), i.e., annual capacity charges(including O&M) and fuel charges at a given load factor, divided by theannual kWh generated during the year.WL The capital costs can be adjustedto capture three issues: (a) construction times and the correspondingopportunity cost of capital; (b) effective capacity differences due tounplanned outage rates; and (c) differences in accompanying transmissioncosts. This simplified analysis is sufficient to establish the need forserious consideration of combined-cycle plants in future sector planningefforts. Details of the calculations are in Annex 8.

12/ As for the end-use analysis of other gas markets, the approach isagain one of average or levelized cost analysis. Comparisons are made onthe basis of the average projected price of alternative fuels over a 20-year horizon.

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2.48 As for previous end-use analysis, the netback value of zas is ameasure of potential economic benefits to be derived from the use of gas ina given application.3EM This netback analysis estimates the breakeven costof gas delivered at a combined-cycle power plant gate vis-a-vis other fuelsand generation technologies. The netback value is thus a function of thealternative technology against which combined-cycle plants are beingmeasured. Because capital cost differentials are such an important factorin the comparison, the estimated netback values are also highly dependenton the assumed load factor of the plant and the cost of capital.

2.49 Capital Costs. It is difficult to make precise estimates of thecapital cost of alternative generation options because of the preponderanceof local factors. Thus, the capital costs of coal units depend to a largeextent on the environmental regulatory framework in which they operate.While nuclear plants are also clearly affected by environmental controls,their unit costs largely reflect the degree of equipment standardizationachieved by the utility. One also needs to differentiate between new sitedevelopment and capacity additions at existing sites where one would exjpecteconomies of scale in the use of offsites. The mission endeavored todevelop a consistent set of cost estimates (for new site development) basedon worldwide experience but integrating as much as possible pastconstruction experience in Korea. The basic assumptions, which arcsummarized in Table 2.2, refer to 1989 prices and are considered typical.W,

2.50 Efficiency. Availability and Reliability. The net efficiency ofthe latest gas-fired combined cycle plants is around 48X (based on low heatvalue [LHV]); further efficiency gains (of about 5 percentage points)widely expected to be achieved over the next ten years through continualoptimization of gas turbine designs are ignored in the analysis. Incomparison, the efficiency of conventional (steam turbine) plants isestimated at about 38X for coal-fired plants and 39Z for oil-fired

201 Note that netback values could be quite different if calculated inthe context of a WASP-type model.

j1/ Combined cycle plant costs should be corrected to reflect thesavings in transmission costs due to the fact that they can be locatedclose to the main load centers; annual savings in transmission expenditureswere estimated by KEPCO to range up to US$15/kW/yr for a Seoul plant thatwould substitute for a coal plant located on the southern coast. Combined _cycle plants that would be located in cities in the southern part of thecountry (assuming gas availability) would generate somewhat smallersavings.

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plants.W Combined-cycle and conventional steam technologies also differsignificantly in their availability (probability of planned and unplannedoutage) and reliability (probability of unplanned outage), especially whennatural gas and coal are compared. While in the past the performance ofcombined cycles was limited because of problems associated with gasturbines, the latest combined-cycle plants which incorporate recenttechnological advances are reported to operate with availabilities of over902, compared to about 70X for conventional coal units.WV Dependin.g onsuch system characteristics as demand seasonality and the ratio ofindividual plant size to system size, the difference in scheduledmaintenance periods may or may not lead to major system cost differences.At any rate, however, the difference in outage rates will ca&l foradditional reserve requirements for steam coal facilities ir. order toprovide the same quality of service.

Table 2.2: Plant Cost and Performance Data

Plant Cost Heat Rate Efficiency Availability O&M c/(S/kWM a! (Btu/kWh) (X) (X) b/ (Sc/kWh)

Convent. SteamCoal 1,100 d/ 8,980 38 70 1.15Oil 900 8,750 39 80 0.65

Combined-CyclesGas 650 7,200 47 93 0.36Light Oil 650 7,600 45 85 0.40

a/ overnight costs.b/ 100l less probability of planned and unplanned outage.c/ at 65X load factor.d/ including flue gas scrubbers.

D2/ While the efficiency of a combined cycle plant drops under partialload operating conditions, it always remains above that of conventionalplants with similar rating. Moreover, in the case of multi-turbinecombined-cycle plants, broad use of the high efficiency of individual gasturbines under full load conditions can be made when operating the overallplant under partial load conditions by isolating one or more gas turbinesand operating the remaining ones close to full load conditions. Also, acombined-cycle plant equipped with a fully fired boiler would be able tomaintain its highest efficiency even under partial load conditions. Ingeneral, therefore, combined-cycle plants compare very favorably with mostother generating alternatives in their ability to follow the utility loadcurve easily, i.e. to operate under changing load factor conditions withfairly consistent efficiency.

D/ For a unit in the 450 MW range, the implied cost differential isestimated at about $45m (or $100/kW of installed capacity).

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Netback Value of Gas

2.51 Our base case comparative analysis underscores the economicattractiveness of gas-fired combined-cycle plants when compared with (new)coal-fired stations. Based on an assumed (discounted) average price ofdelivered coal (including harbour and handling charges) of $55/ton($8.8/GCal), the base case netback value of gas is $27/GCal (at 66.51 and58.21 load factor for gas and coal plants, respectivelyW). Differences inefficiency, capital costs and OM costs between the two technologies can betranslated as premiums to gas (compared to coal) on a calorific unit basis($/GCal), as shown in Table 2.3. Note that combined-cycle plants usingdistillate oil would also be an attractive alternative to coal-firedstations albeit significantly less so than gas-fired plants; yet, thisindicates that diesel oil could provide a convenient backup in the case ofgas supply interruption.W Use of gas is also shown to be attractive inpeaking combustion turbines.

Table 2.3: Gas-Coal Value Differentials($/GCal)

Cost of Canital13X 8X

Average Discounted Coal Price 8.8 8.9

Fuel Efficiency Differential 2.2 2.2O&M Cost Differential 4.4 4.4Capital Cost Differential a/ b/ 11.5 6.6

Netback Value of Gas 26.9 22.1

a/ at 66.5X load factor for combined-cycle plantsand 58.2X for coal-fired plants to reflectdifferential in availability.

b/ ignoring differential in transmission requirements.

_/ The differential in load factors is used as a proxy to account forthe difference in availability between the two technologies.Alternatively, the capital costs for the coal alternative could be markedup to reflect the additional capacity reserve requirements necessary toprovide a similar level of reliability as the gas alternative.

2/ If one assumes that in actual operating conditions, thealternative to a combined-cycle plant capable of load following performancewould be a mix of coal steam turbine operating as base-load capacity anddistillate combustion turbine as peaking unit, the netback value of gaswould be about $2/GCal higher than in the base case.

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2.52 While the analysis underscores the potentially large economicbenefits to be realized from the use of gas in generating electricity, theestimated economic rent (i.e., the difference between the netback value ofgas and its economic cost) (a) will be a function of plant location and (b)is sensitive to the assumptions made in regards to key parameters. Inparticular, actual demand for gas can only be determined through a powersystem optimization program that incorporates, inter alia, estimates of thecost of gas at various locations (para. 3.12). While direct comparison ofthe netback value of gas with the expected average cif price of LNG overthe period ($17/GCal) points to a potentially large rent available to coverinfrastructure costsUJ, this rent is quite sensitive both to load factorand cost of capital assumptions, as shown in Table 2.4. This tableillustrates in particular the impact of a reduction in the cost of capitalfrom 13X (GOK's official figure) to 8% (the figure actually utilized byKEPCO). At 8%, the available rent is reduced (from $10/GCal) to $5/GCal;the impact of this lower bound of the netback value of gas in the powersector on the viability of gas infrastructure investment is discussed inChapter 3. Table 2.4 also illustrates the impact of load factor and coalprice assumptions. The competitiveness of gas-fired combined-cycle plantsis seen to improve significantly with a lower load factor as the impact ofcapital cost differential increases. On the other hand, alternative coalprice scenarios have a limited effect on the viability of gas-fired plants.

Table 2.4: Netback Value of Gas($/GCal)

Cost of CapitalLoad Factor 13X 8%Gas Coal

80% 70% 24 2066.5% 58.2% 27 2266.5% 66.51 24 20501 501 28 23

Coal Price

$55/ton 27 22$45/ton 25 20

Z/ The economic rent available between the netback value of gas andthe cif price of LNG is to be related to the cost of the infrastructurerequired to make gas available to the power plants, includingregasification facilities and pipelines. This integration of benefits andinfrastructure costs is being dealt with in the economic analysis presentedin chapter 3. The proposed Il-Do combined-cycle plant will be located nextto the proposed second LNG terminal and close to the end-point of theexisting pipeline from Pyong Taek; the only relevant additional cost willtherefore be that of the new terminal (about US$2/GCal).

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2.53 Additional sensitivity tests were conducted. They indicate (a)that comnbined-cycle technology is attractive as long as its capital costsare about $200/kW less than those of steam coal; and (b) that itsattractiveness is relatively insensitive to changes in relative fuelefficiency parameters. The comparative economics of coal- and gas-firedpower generation alternatives, however, will remain primarily dependent onfuture price trends. While present price forecasts (and technologicalfactors) give the gas option a significant advantage, the evolution ofworld demand for coal and gas (primarily as fuels for power generation) maymodify the current relationships. Since a gas import strategy (in partpredicated on substantial use of gas in the power sector) would commitKorea for a long period of time, the possibility of a partial link betweenLNG and coal prices should be explored in the course of future gas importnegotiations. Also, the strategy being followed by other countries facingsimilar circumstances, viz. to base power development on a combination ofcoal and gas plants (as well as nuclear facilities), would appear logicalas a way of reducing risks from fuel price uncertainty.

D. District Heating

2.54 District heating is a space heating method based on acentralized heat generating plant supplying urban areas with continuousheat through an insulated transmission and distribution network in lieu ofthe traditional, individual facilities. Due to relatively highdistribution network costs, district heating applications are limited tocountries with substantial space heating loads and relatively high urbandensities. These conditions are met in a number of cities in Korea anddistrict heating could, over time, provide for a substantial portion of thespace (and water) heating needs of the urban population.

2.55 In general, district heating is deemed -:o be economical only inthe context of combined heat and power generation vCHP), which offers thepossibility of reducing space-heating costs by utilizing waste heat fromelectric power generation. By making use of relatively low temperaturewaste heat for district heating, CHP provides for a more efficient use ofprimary fuel inputs. Generally, a CHP plant will consist of an electricpower plant located close (10-25 km) to urban areas W , and as such itsviability will require that it fit well into the long-term electric powerdevelopment program, especially with respect to choice and siting ofintermediate load plants.

2.56 A number of district heating feasibility studies have beencarried out in Korea over the past few years, and two sites (Mok-Dong andSouthern Seoul) are already under development. An industrial estatecogeneration project has also been developed at Daegu. A district HeatingMaster Plan for the Greater Seoul area was completed in December 1986.

j.Z/ Industrial cogeneration or waste heat sources are also possible.

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The plan proposes three additional sites to install district heatingfacilities. The new systems would be linked progressively to the twoexisting ones to form an integrated district heating network.

2.57 CHP systems can be supplied from an existing heat source (i.e.,a single purpose electrical power plant retrofitted for district heatingpurposes, or a refuse burning plant) or, in the absence of an availableheat source, from a dedicated cogeneration power plant where heat andelectricity are produced simultaneously. The two ongoing district heatingprojects in Seoul are supplied, in the case of Mok-Dong, from a dedicatedoil-fired cogeneration facility linked to a refuse incineration plant and,in the case of Southern Seoul, from a rehabilitated (oil-fired) powerplant. The Mok-Dong plant could be converted to gas-firing in the futureout of environmental considerations.

2.58 The 1986 district heating master plan compares three fuelalternatives and two technology alternatives for future CHP systems: coalvs. HFO or gas; backpressure turbines vs. condensing extraction turbines.In all cases. steam from the turbine would be used to produce heat iln theform of hot water for district heating. Coal-fired CHF plants were foundin the study to be both environmentally acceptable and to give the highestrate of return, compared both to oil and gas-fired plants. The study,however, fails to take account of (a) increased environmental concernsregarding the emission of pollutants in the Seoul area with correspondinglygreater resistance towards the burning of coal (the study emphasizescorrectly, however, that centralized CHP operations would lead to improvedenvironmental standards compared to the burning of coal briquettes or fueloil in individual facilities); and (b) the introduction of combined-cycletechnology as a basis for new CHP systems, which leads to much higherreturns on gas use. CHP systems based on a combined-cycle configurationhave already been installed in Finland (city of Tampere) and in Holland(Den Haag, Leiden, and Pegus). Similar CHP systems for industrial use havealso become widely used, particularly in the US. The comparativeadvantages of combined-cycle plants in generating electricity (based onpresent and anticipated LNG, oil and coal prices), which were discussed inthe previous section, would equally apply to CHP systems.

2.59 The mission recommends that plans for future extensions ofdistrict heating facilities, in Seoul or elsewhere, take the gas-firedcombined-cycle option into account in making configuration choices. KEPCOhas already made tentative plans along these lines, together with the KoreaDistrict Heating Corporation (KDHC), for CHP units that would supply newurban developments in Il-San, Bun Dang and Pyung-Cheon outside Seoul.These plants would be dedicated primarily to the supply of steam (or hotwater) for heating, with surplus power being essentially a by-product to betransferred to the grid (as under standard cogeneration sale agreements).An assessment could also be made of the feasibility of retrofitting thecombined-cycle power plants KEPCO proposes to install at Incheon to supportlocal district heating schemes. This could be done without significantreduction in operating flexibility if the plant is equipped with auxiliary

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boiler(s). This approach could provide an economically attractive, ifpartial, solution to residential heating requirements in the Incheon area.2.60 From an economic standpoint, the exact configuration of CHPplants should be a function of the relative values of steam andelectricity. In practice, however, institutional issues will probably havea direct bearing on the choice of plant configuration, with electricityproduction or steam production being given greater emphasis depending onwhether the plant is managed by the power utility or by a district heatingutility. If CHP plants are designed as extraction-condensing power plants,they would automatically produce their maximum electricity output duringthe time of minimum heat demand. Electric power would be the main productand the heat in the wintertime a byproduct. As such this type of plantswould be better suited for KEPCO's direct operation and ownership withsteam sold to a separate district heating entity for distribution.

2.61 Apartment house complexes provide the main potential fordistrict heating schemes. Based on future construction plans in sevenmajor cities, the future total heat load of apartment complexes which couldbe hooked to a district heating system has been estimated at 5,260 MW(th)(4,540 Gcal/h) in 1990 and 8,000-11,000 MW(th) (7,000-10,000 Gcal/h) by theyear 2000. Two thirds of this potential is expecced to be in theSeoul/Incheon area alone. It is difficult to anticipate the rate ofpenetration district heating systems will be able to achieve towards thispotential. A number of factors will affect the outcome, including (a)institutional issues related to the integration of CHP systems in powersystem planning on a large scale; (b) technical factors such as theproportion of apartments equipped with individual heating systems (asopposed to central heating); (c) the relative cost efficiencies of districtheating systems with individual systems based on gas or other fuels.Environmental issues are also likely to become increasingly prominent andmay eventually lead to a comparison between individual gas-based heatingfacilities and gas-fired CHPs presumably based on combined-cycleconfigurations.

2.62 Two avenues are therefore available to introduce or expand therole of natural gas to meet space heating loads: as a fuel source forindividual heating facilities (in individual dwellings, apartments orcommercial buildings) or, alternatively, as a fuel source for centralizedCHP/district heating systems. A generic comparison of the two options is

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hardly feasible because of the multiplicity of site-specific factorsinvolved. Tentative calculationsW indicate however that district heatingsystems are likely to have a comparative advantage, at least in such caseswhere generating plants can be located reasonably close to the areas to besupplied. District heating planning is still at an early stage. However,given the potentially large-scale use of gas this activity may generate, itis essential that current studies (by KEPCO and KDHC) be integrated rapidlywithin KGC's current gas infrastructure planning exercises.

E. Environmental Issues

2.63 A key government objective in promoting the use of LNG is toreduce air pollution in urban and highly industrialized areas. Thisapproach parallels similar trends in many other countries whereenvironmental concerns have become a major determinant in the choice ofenergy options and increasingly influence the direction of energyinvestment programs. As discussed in Chapter 1, major current issuesassociated with the burning of fossil fuels include SO2, NOx, particulatesand carbon oxide emissions. CO2 emissions are also receiving increasingattention in relation to global warming concerns. Natural gas, which isfree of most pollutants present in liquid and solid fuels and generatesonly a fraction of the CO2 output of alternative fuels, can play a majorrole as part of a pollution control strategy. In particular, natural gashas no sulfur content and gas burning minimizes emissions of NOx and ozone.Accordingly, a key government objective in importing LNG has been to reduceair pollution in urban and highly industrialized areas. Following similarmeasures elsewhere, stricter emission standards have been set in Korea,particularly for SO2 emissions. By adding to energy costs, suchenvironmental control measures influence the competitive position ofalternative energy sources. One may therefore expect the tightening ofenvironmental controls to progressively improve the competitive position ofgas, both from an economic and financial standpoint.

2/ In general, district heating distribution costs would be about 3-5times higher than gas distribution network costs for a typical, largeapartment complex, partly because two pipes are usually required (supplyand return) and the pipes need to be insulated and are usually of largerdiameter. Costs are about $250-500/m for sub-distribution lines. Forapartment blocks of the density typical in Korea, distribution networkcosts are about $80-90,000/MW(th), which would translate into unit costs ofabout $7-8/MWh(th) ($6-7/GCal), including maintenance and pumping costs (1MW(th) - 1.16 Gcal/h). Transmission costs are a function of distance andquantities. For distances of less than 10 km between the CHP plant and theconsumption area, the cost of the transmission lines, together with that ofthe main distribution grid, is estimated to add about 10-20X to thedistribution costs. At a transport distance of 30 km, this ratio wouldincrease to about 1:1. By way of comparison, average gas network costs fora typical, new apartment complex are estimated at about $6/GCal.

2.64 'n several countries, adoption of measures designed to regulatecoal and HFO use are seen to have led to changes in gas utili7ationpatterns, particularly itn the power sector. Thus, in Japan, the risingcosts of coal-fired plants because of new environmental regulations havefigured prominently in the power utilities' decision to turn to LNG. Inthe United States, the repeal of the Fuel Use Act makes investments in newgas-fired generating plants possible and there is a widespread expectationthat a large share of future capacity additions will consist of gas-firedplants. Similarly in Europe, pressure is mounting to amend EC regulationsthat restrict the construction of new gas-fired pow'er plants. AlthoughKEPCO has so far been little affected as yet by formal governmentregulations as regards fuel choices, the situation is changing and publicpressure vis-a-vis coal-fired plants is also felt increasingly acutely.

2.65 For a number of end-uses, the economics of gas utilization aremarginal when compared to alternative fuels on a strictly econom4c basisbecause of the high cost of LNG. In many cases, however, differences inen-7ironmental impact would considerably strengthen the justification forusing natural gas. This includes substantial portions of the commercialand industrial markets. The main issues for the Government are (a) todetermine the extent to which gas use should be encouraged beyond thelevels dictated by commodity prices and efficiency factors; and (b) toidentify the most effective way of providing the needed incentives(subsidies for conversion, cross-subsidy in price) and disincentives (taxeson polluting fuels, etc) to facilitate gas penetration of targeted markets.

2.66 GOK has so far relied mainly on fuel allocation policies inaddressing environmental issues, in particular through the issuance of fueluse regulations specifying minimum fuel quality or altogether barring theuse of certain fuels in some areas (e.g., liquid fuels by commercialconsumers in downtown Seoul).W While these regulations are well-motivated, the issue is one of cost effectiveness and, for our specificpurpose, of the comparative advantage of promoting the use of natural gasto address specific environmental concerns. As environmental issues gaingreater prominence in the setting of energy policies, the Government needsto ensure that its policy decisions are rooted in an overall pollution

2W Currently much of the demand for LNG-based city gas is driven byenvironmental regulations. In Seoul, new power, industry and commercialfacilities can no longer use coal. And in the downtown area of Seoul, whenand where city gas is available, all commercial heating end-users of boilersize (output) greater than 2 MT/hour are required to switch to LNG citygas. The assumption is that these facilities would be switching fromBunker-C (or coal). The regulations on household use are unclear, butapparently Bunker-C (as well as diesel) can still be used in residentialapplications. Apparently coal can be used in residential applications aswell, although it appears that for apartments this is only true forexisting users; with respect to single family users, it is unclear whethercontinued use of coal is only for existing uses while not allowable for newconstruction.

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control strategy supported by a proper assessment of availablealternatives. While the analysis conducted as part of this study providesa number of relevant indications, more analytical work will be required todevelop a comprenensive set of policies on environmental issues.1V Thereare three priority areas where gas can play a critical role in reducing thepollution impact of energy use, although rationalization of governmentpolicies will be a prerequisite to the establishment of fuel use patternsthat properly account for the relative social costs of each fuel: (a) theuse of HFO in the power and industrial sectors; (b) the use of HFO in theurban, commercial sector; (c) the use of anthracite for space heating. Asdiscussed further below, each area will call for a specific set ofmeasures: for large-scale energy users, a number of alternatives areavailable; hence, user-specific regulations on allowable emissions wouldprobably be the most efficient approach, leaving each user the choice ofthe preferred means of meeting set emission targets. For commercial users(and apartment buildings), a tax on polluting fuels, combined with atightening of standards on acceptable fuels, would be preferable tomandatory fuel switching regulations; taxes could be used to reflect theactual economic costs of alternative fuels, thereby relying on market Pforces to elicit the optimum fuel use pattern. Finally, in the case ofanthracite users, more direct government intervention, in the form ofincentives to promote fuel switching, will be required (para. 2.77).

2.67 In comparing available energy options from an environmentalstandpoint, it is appropriate to differentiate between large-scalefacilities for which emission control measures are both technicallyfeasible and often cost-competitive, and smaller facilities for which costissues rapidly become the most constraining factor. A number of techniquesof emission control are commercially available for coal and HFO-burningfacilities, with the most effective methods (flue gas treatment) being ableto reduce SO, and NOx emissions by up to 80-90. Flue gas desulfurisation(FGD) is the most widespread method of SO emission control. The mostcommon techniques for NOx control are low-NOx burners and combustioncontrol measures; selective catalytic reduction (SRC) offers a moreeffective but also more costly approach.

IQ/ In particular, there is a need to relate the additionLl cost ofgas compared to cheaper but more polluting fuels with the cost of reducingthe environmental impact of these fuels through other means, including fuelswitching to a less polluting fuel (e.g., from HFO to low sulfur fuel oilor diesel oil), even though gas would still be a far cleaner fuel.Ideally, for each relevant end-use, an economic analysis would need to beconducted to assess whether similar environmental goals can be achieved atless expense.

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Power Sector and Other Large-Scale Users

2.68 Environmental controls assume an increasing proportion of thecost of power plants, the ratio being a function of fuel quality and localregulatory requirements. To bring S02 emissions within environmentalstandards, new coal-fired plants in Korea are now equipped with FGD units.Because of the availability of low-sulfur coal at little or no premium overhigh-sulfur coal, FGD used to be considered an unnecessary addition to coalunits; they now are included in KEPCO's planning as a matter of routine.

2.69 As discussed earlier, one of the most significant advances inelectricity generation technology in recent years has been the introductionof gas-fired combined cycle processes. Besides their added efficiency, asignificant advantage of these processes is that it provides for the highenvironmental performance of natural gas over alternative fuels: SO2 andparticulates emissions are essentially eliminated while NOx (and C0O)emissions are reduced significantly. Moreover, while gas-fired combined-cycle plants may eventually require SCR for NOx control, SCR costs would besignificantly lower than for a coal plant (about $15/kW vs $55/kW).!,/

2.70 Despite the availability of technologies to mitigate theenvironmental impact of conventional coal- (and oil-)fired steam plants, itis unclear whether such plants will gain sufficient public acceptance forKEPCO to implement its proposed expansion program, which calls for theinstallation of seven coal plants with a total capacity of 5,100 MW overthe next 12 years. A (partial) shift to gas is warranted by theencouraging results of comparative economics. Two factors could over timeaffect this general recommendation: a drastic change in relative pricetrends (of LNG vis-a-vis coal) from current expectations; and furtherprogress in power generation technology, which is very much in a state offlux in response to environmental concerns worldwide. For these reasons,the Government needs to keep abreast of progress made in the development ofvarious advanced (coa:- and oil-firing) power generation technologies,which offer the potential for important environmental gains going beyondthe protection offered by FGD/SCR in conventional plants. These include

DJ NOx emissions can also be reduced (at a lower cost) through steaminjection in the gas turbines. So far only Japan and Germany have enactedNOx control legislation making SCR necessary.

notably (a) fluidized bed combustion (FBC) systems R/; and (b) integratedgasification combined-cycle (IGCC) systems.1V

2.71 IGCCs provide for the conversion of coal to a highly combustiblesynthesis gas, composed mainly of carbon monoxide and hydrogen, and free ofmost pollutants, which is then combusted in a combined cycle power plant.IGCC technology, which is already available on a commercial scale,tM is ahighly effective way of reducing the SO2 and NOx output of coal-firedstations while taking advantage of combined-cycle efficiency. As such, itis dfemed one of the most promising advanced technologies for the future.IGCC technology probably is the most relevant long-term alternative forKorea and provides a suitable comparison for gas-fired systems for thepurpose of long-term system planning on a more or less environmentallyequivalent basis. On the basis of current coal gasifier costs andefficiency iV, the break-even price of gas above which IGCC would becomeattractive would be 1.25 times the price of coal, plus a mark-up of about

I/ FBC systems comprise (i) atmospheric fluidized bed combustion(AFBC), which is growing in commercial use although facilities are stilllimited in size; and (ii) pressurized fluidized bed combustion (PFBC),which is entering the commercial demonstration stage. FBC systems havebeen developed primarily to burn substandard fuels and are expected toemerge as an economical alternative for high-sulfur coal. After a tenuousstart in the early 1980s, FBC technology is now being used in some 12,000KW of capacity worldwide where its main advantage lies with its very broadfuel flexibility. It is based on the use of dry limestone, which resultshowever in a large solid-waste problem, especially with high-sulfur fuels.

jL/ A number of other technologies are also being developed such asfuel cell systems. At this point of time, however, these technologies havenot yet reached sufficient levels of efficiency in relation to capitalcosts to make them an attractive option for Korea at least within the timehorizon being considered here.

34/ Efficiencies of 42X are currently achievable (at capacity of up to250 MW). The technology offers significant improvement prospects over thenext decade, both at the gasifier stage (which would improve itscompetitive position vis-a-vis gas-fired ccmbined cycle plants), and in thegeneration cycles. Overall (gasification-combined cycle) efficiencies ofabout 45X could be attainable in the next few years.

12/ The capital costs of coal gasifier are currently about $1,000/kW(of final generation capacity), for an efficiency of 80X. O&M costs areabout UScO.9/kWh (in addition to USc0.4/kWh for the combined-cycle portionof the plant). However, plant parameters vary from coal to coal. While,from a technical viewpoint, all types of coal can be gasified, theeconomics of gasification will vary from coal to coal. Moreover, IGCCshave a substantially lower availability than gas-fired combined cycles(about 701 vs. 931).

51

$17/GCal (assuming a 70X load factor). On the basis of our (discounted)average price of (delivered) coal of $8.5/GCal, this would place the break-even cost of gas at about $29/GCal. This is significantly higher than theforecast average cost of gas (after regasification) -- but close to thenetback value of gas measured against conventional coal plants, whichindicates that, as a coal technology, IGCCs would be economicallyattractive as soon as designs have been scaled up to standard plant sizes.One should expect significant reduction in the costs of coal gasifiers asthe technology gains wider acceptance (initially in low-cost coal producingcountries). However, the capital and O&M costs of coal gasifiers wouldhave to drop by as much as 551 (all other parameters remaining the same)for IGCC systems to become attractive for a country like Korea importingboth coal and gas.AV Gas-fired combined-cycles are therefore expected toremain the most attractive option for at least the next decade.

2.72 A separate issue relates to the choice of fuel in existing oil-fired thermal plants. KEPCO has been requested by the Government toconvert a number of its oil-fired power plants located in densely populatedareas, including the Incheon plant, to continuous gas-firing. However, theissue of whether this would result in a cost-effective handling ofpollution control and LNG load balancing objectives is open to questioninasmuch as substantial pollution abatement could still be achieved byhaving these plants occasionally run on low-sulfur fuel oil (to help meetseasonal variations in other markets), even though gas clearly provides afar cleaner fuel. As discussed further in para. 3.17, we recommend thatmandatory fuel-switching policies in the power sector be reviewed to ensurethat they provide a cost-effective answer to environmental objectives.

Small-Scale Energy Consumers

2.73 Emissions from small-scale energy consumers, including small-and medium-sized industrial (SMI) facilities, commercial facilities forspace heating, ane residential consumers, are generally more difficult tocontrol than emissions fro- large energy users. While efficient andrelatively cost effective p;st-combustion pollution control techniques areavailable for large power generation and industrial facilities, their costsrapidly become prohibitive as the scale of operations diminishes, whichlimits their use for smaller energy users. Generally speaking, the onlyoptions available to reduce the emissions of small-scale users are to shiftto higher-quality fuels, modify the combustion process, which, however, isnot as environmentally effective as the use of FGD and SCR, or centralizecombustion in common facilities to facilitate emission control.

.26 Combined-cycle plants can later be combi..zd with a front-end coalgasifier to produce an Integrated gasifier-combined cycle (IGCC) system,should the relative prices of coal and gas and the capital cost of coalgasifiers justify it.

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2.74 The fuel of choice forkboiler use by industries or forcommercial and community space heating is HFO with normally a maximumsulfur content of 1.6Z, which is available from local refineries. Use ofnatural gas as a direct HFO substitute in boiler applications would ineffect eliminate (or sharply reduce) all toxic emissions but may not be themost cost-effective method of reducing the environmental impact of small-and medium-sized industries -- and would be impractical under the existingprice structure. Following similar trends elsewhere, the Government is nowcontemplating imposing further reductions in the sulfur content of fueloil. This would probably induce a shift toward light fuel oil asrefineries may find it difficult to produce large quantities of HFO with asignificantly lower sulfur content than presently, especially in view ofthe rising trend toward heavier crudes worldwide, particularly in the Asiaregion. Alternatively, low-sulfur crude oil can be used in lieu of heavyfuel oil, as by some utilities in Japan, since the costs of desulfurizationof heavy fuel oil currently outweigh the additional cost of light crude.In any case, a tightening of HFO specifications would result in higher fuelprices and probably a diminution in available supply. Industrial userswould therefore be faced with the choice of using more expensive low-sulfurfuels or switching to natural gas, In such circumstances, one would expectthe trend towards increased gas use in the industrial sector to accelerate.

2.75 An alternative approach to the use of gas as a straight boilerfuel would be to promote its use in the cogeneration of steam and power inCHP facilities, which can achieve environmental as well as efficiencybenefits. Cogeneration can be effected either in plant-specific units orin larger-scale utility systems designed to supply industrial parks (in anapproach similar to that of district heating systems). In either case,natural gas would be the most attractive fuel. Compared with separatepower and steam production, decentralized cogeneration units (in SMI andcommercial applications) would generate substantial fuel savings, therebyjustifying more easily a switch to natural gas as the preferred approach topollution control. The availability of efficient small-scale cogenerationunits for commercial and SMI applications also need to be promoted.

2.76 In general, centralization of combustion facilitates the controlof emissions. This is an important justification for setting upcentralized CHP plants to supply industrial parks or district heatingsystems in urban areas. In the case of CHP plants located in urban orhighly industrialized areas and burning coal or oil, current environmentalregulations would in effect make the use FGD and possibly SCR technologymandatory. At any rate, reliance on coal- (or oil-)based CHP plants fordistrict heating, as was recommended by earlier feasibility studies, wouldappear to run counter to current government thinking on acceptable fuelchoices. However, the alternative offered by gas-fired combined-cycleplants retrofitted for dual power/heat production is both economically andenvironmentally attractive (compared to standard coal- or oil-fired CHPplants). Such plants combine the advantages of combined power/heatproduction, the efficiency of combined-cycle configuration and reliance ona clean fuel suitable to an urban or highly industrialized environment.They probably are the most efficient way to mitigate the environmentalimpact of SMI in areas with sufficient concentration of production

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capacity. As such, centralized CHP facilities in industrial parks couldgain greater prominence in the Kotean industrial sector and in turn providea substantial and attractive market for gas. We recommend that suitableinstitutional arrangements be identified to facilitate the establishment ofgas-based industrial utilities in areas with large SKI concentrations.

2.77 Residential Consumers. One of the most vexing environmentalproblems faced by the Government is that of anthracite-burning forresidential space heating for which, as discussed in para. 2.20, there isno clear economic justification. Gas has clearly a role to play inaddressing this issue although substantial government intervention would berequired. The most promising avenue would be to encourage fuel switchingthrough financial assistance to consumers towards the cost of conversion.High-efficiency household-sized boilers have been developed, which wouldminimize retrofit costs and whose availability should be promoted. Thedevelopment of district heating systems could also provide part of thesolution, although the technical feasibility of such systems in urban areaswith traditional habitat at a reasonable cost is unclear and would need tobe assessed. If technically feasible, CHP/DH systems could be expected toprovide an effective way of mitigating the environmental impact of energyuse while also bringing about a more rational fuel utilization.

3. SUPPLY-DEMAND SCENARIOS

3.1 KGC has made preliminary plans to expand gas supply in Korea.To evaluate the economic viability of this investment program, alternativesupply/demand scenarios were developed based on plausible assumptions aboutfuture gas use. For this purpose, Korea can conceptually be divided intotwo separate regions, i.e., the region north of Pyeong Taek (i.e., theKyongin region), where a gas system is already in place although many areasare not yet supplied (nor would it be necessarily economic to supply them);and the region south of Pyeong Taek where no gas system is as yetavailable. The southern area can be further divided between the central(Chungchong) region, the southeast (Yongnam) region, which includes thehighly industrialized Pusan/Ulsan area, and the less developed southwest(Honam) region (See the attached map). Supply-demand scenarios weredeveloped for each region separately.

3.2 As is clear from the gas utilization analysis, the developmentof combined-cycle technology for power generation, associated with theavailability of a reliable supply of gas, have introduced new dimensions tothe future of the LNG industry in Korea. The original focus on coalreplacement in large cities has been superseded by the possibility for LNGto make a major contribution to overall energy supplies, with the powersector assuming a central role in the definition of LNG facilities:overall, gas use is expected to be divided between power and non-powerusers approximately in a 60-40 ratio.

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A. The Residential, Commercial and Industrial Markets

3.3 A pertinent evaluation of potential gas demand must reflect botheconomic and financial end-use analysis. In actual fact, however, futuredemand will be largely supply driven (by the pace of construction of gasinfrastructure); demand will be also strongly influenced by housingdevelopment schemes and by whether or not needed regulatory andinstitutional action takes place. The basis for our demand projections isthe KEEI Gas Demand Study (para. 1.26). The results of this study, whichis based on a careful analysis of macroeconomic trends, were crosscheckedand modified as required in the light of the end-use analysis reported inChapter 2. Also, correlations with anticipated programs of housingconstruction and industrial activity were elicited. In general, thesedemand projections appear reasonable as a starting point for a preliminaryreview of investments.

3.4 The KEEI demand projections, however, lack the underpinning ofdiscrete market surveys, particularly as regards industrial demand. Asdiscussed in para 3.38, the undertaking of such surveys on a selectedbasis, together with basic gas system design studies, is a criticalprerequisite to the implementation of an expanded gas strategy. Marketsurveys for industry should focus on the textiles, food processing andmetal industries which should provide for a high-value gas market.

3.5 The end-use analysis also underscores the potentially criticalrole to be played by CHP plants to supply district heating systems andindustrial utility systems. It was not possible, however, to disaggregatethe possible contribution of these two categories of gas users from thebroader categories of residential space heating demand, on the one hand,and industrial deaand, on the other. From a system planning point of view,however, a detailed survey of these discrete consumers is in order.Finally, much uncertainty remains in regard to future government policiesin the area of fuel use and related energy pricing, which would have adirect bearing on future demand. While the demand projections are based onplausible assumptions regarding gas penetration of each market, much needsto be done to establish the policies and institutional mechanisms necessaryto enable gas penetration of preferred markets, as discussed in Chapter 4.

3.6 Forecasts of gas demand in the residential, commercial andindustrial markets are shown in Annex 9 and summarized in Table 3.1.

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Table 3.1: City-Gas Demand Forecast(in million cu m)

1989 1991 1996 2001 2006

Residential 144 215 412 733 1,070Commercial 126 212 373 591 806Industrial 157 265 460 590 716

Subtotal 427 692 1,245 1,914 2,592ChungchongResidential - - 61 153 285Commercial - - 56 127 217Industrial 45 71 96

Subtotal - - 162 351 598YongnamResidential - - 98 242 439Commercial - - 98 215 347Industrial - - 131 304 524

Subtotal - - 327 761 1,310HonamResidential - - 22 118 220Commercial - - 23 105 174Industrial - - 45 148 262

Subtotal - - 90 371 656

Residential 144 215 593 1,246 2,014Commercial 126 212 550 1,037 1,544Industrial 157 265 681 1.114 1.598

Total 427 692 1,824 3,397 5,156

(m. tons of LNG) (0.4) (0.6) (1.5) (2.9) (4.4)

Sources: KEEI, KGC and mission estimates.

B. Demand from the Power Sector

3.7 The comparative economics presented in Chapter 2 indicate that,while current use of gas in existing thermal power plants is hardlyjustified except out of environmental concerns, its choice as a fuel fornew power plants is economically attractive both on efficiency andenvironmental grounds. Actually, electricity generation is the main avenueby which LNG is expected to make a major contribution to Korea's overallenergy supplies. In addition to (or in lieu of) its current role as a"swing" consumer, KEPCO is now considering a major expansion in LNG-based.Besides the large economic benefits this will generate, continued highdemand from the power sector is important as it will facilitate thehandling of seasonal variations in gas demand by matching the city gas

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companies' and KEPCO's mutually exclusive load curves -- summer peak forpower and winter peak for gas.

3.8 Future gas demand from the power sector falls under three broadcategories:

(a)plants acting as swing consumers to absorb anysurplus quantities of LNG that would have beencontracted at any point of time (particularly duringsummer months);

(b)existing oil-fired plants to be converted to gas outof environmental concerns; and

(c)new gas-dedicated (combined-cycle) plants.

HFO Substitution in Existing Power Plants

3.9 Gas use in thermal plants originally designed for oil-firing isexpected to remain substantial, mostly on account of environmental controlobjectives. Since LNG deliveries started in 1987, regulations on the typeof fuels for power plants located in the Seoul metropolitan area (includingIncheon) have been tightened and the Incheon plant, which was converted togas in 1987 to absorb the initial quantities of LNG, is now expected toremain on gas-firing on a continuous basis. Similarly, the Seoul and.-yongin thermal power plants would be converted to gas starting in 1994.In addition, one of the four units of the Pyeong Taek power plant will alsohave to remain on gas on a continuous basis because of the need to utilizeboiler gas from the terminal's vaporizer, which cannot be fed into thetrunkline.

3.10 KGC's demand forecast for the southeruk regions envisages theconversion to gas of the Ulsan power plant (units 3,4 and 5) and theYoungnam power plant, under the assumption that environmental policies inforce in the Seoul area would equally apply to the highly industrializedPusan/Ulsan area, should gas be made available there in the future.

3.11 Our base-case demand projections are predicated on the aboveunderstanding of KEPCO's conversion plans. To capture the environmentalbenefits derived from the use of gas in lieu of HFO in urban areas, theprice of low-sulfur fuel oil is used as a proxy (which underestimates theextent of pollution control achieved through fuel switching).

New Combined-Cycle Power Plants

3.12 As discussed in Chapter 2, gas-fired combined-cycle plants offerthe best opportunity for economically efficient use of imported gas in thepower sector. This general assessment, however, is based on a generic

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comparative analysis of alternative generation options, and the scope forthis type of facility in Korea can only be established through a systemplanning analysis. The present situation of the power system ischaracterized by rapidly growing demand in the Kyongin region where 40X oftotal electricity demand already originates, and surplus power supply inthe south, particularly the Honam region; by comparison, the powersupply/demand situation in the Yongnam region is pretty much in balance.Since most of the available sites for future coal and nuclear plants arelocated along the southern and southeastern coastlines, the need totransfer large quantities of electricity from south to north will goincreasing unless generation capacities can be installed in the northernpart of the country. This is an Laportant reason for KEPCO to consider thepossibility of installing large combined-cycle capacity close to its majorSeoul market. The need for similar facilities in the south is clearly notas compelling, at least for now, but would need to be reviewed carefully ina power system planning context (particularly to assess intermediate loadrequirements).

3.13 KEPCO's latest power development program provides for the phasederection of a 4x800 MW combined-cycle plant on the island of Il-Do close to1-icheon. The first phase is expected to come on stream in 1992, with thesubsequent phases following in 1996, 2000 and 2004, respectively. KEPCOhas also made preliminary plans (together with KDHC) for the constructionof three gas-fired CHP plants (also based on combined-cycle technology)with a total capacity of 775 MW to supply new urban developments in theSeoul metropolitan area (i.e., Il-San, Bun Dang and Pyung-Cheon).

3.14 Since construction of a gas grid to supply the southern part ofthe country is still under discussion, plans for installing new gas-firedpower and CHP capacity outside the area served by the existing gas systemare naturally less advanced. However, as discussed below, it would bedifficult to justify the construction of a gas grid to the south withoutthe support of a substantial power-CHP program. To help provide aframework for the evaluation of trade-offs, the mission developed analternative power demand scenario for the southeastern (Yongnam) region;this scenario is meant to illustrate the minimum demand from KEPCO thatwould be required to justify the construction of a national gas grid.

3.15 The capacity and location of power plants will have a majorimpact on the timing, sizing and location of LNG facilities (terminals andmain transmission lines). Given the relevance of power investmentdecisions (including CHP facilities) in planning future gas infrastructure,uncertainties surrounding power planning should be lifted as soon aspossible. Accordingly, we recommend that the Government consider theestablishment of a consultative gas planning working group to strengthenthe coordination between the planning activities of KGC, KEPCO and KDHC(para. 4.4).

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Swing Consumers

3.16 The role of swing consumer is now assumed by the Pyeong Task andIncheon power plants, which together accounted for 911 of LNG consumptionin 1988. This ratio will decrease as city-gas markets develop. The needfor swing consumers will remain, however, in order to handle (a) seasonalvariations in non-power demand; and (b) the quantum jumps in LNG deliveriesas additional import quantities are being contracted out. The magnitude of"swing" consumption will depend on several factors, including the size offuture LNG contracts, KGC's ability to offset the seasonality of power andnon-power demand, and the extent to which future LNG contracts wouldprovide for added flexibility in the schedule of LNG deliveries (or whetherspot purchases of LNG can be effected to meet winter peaks).

3.17 As indicated in para 2.71, KEPCO has beea requested by theGovernment to convert a number of its oil-fired power plants (located in orclose to densely populated areas) to continuous gas firing. Accordingly,KGC's (and KEPCO's) supply/demand forecast assumes that these (converted)plants could therefore not be considered as swing consumers (i.e., theeventuality of a gas supply interruption is not an acceptable planningassumption). However, such use of gas on a continuous basis would entail asignificant economic cost which probably exceeds the additionalenvironmental benefit of not using low-sulfur fuel oil even on a teporarybasis. The issue arises as to whether some of these "converted' powerplants could not assume part of the swing function required by the system.Such an approach, which would be highly cost effective by reducing theextent of uneconomic gas utilization elsewhere (e.g., at Pyeong Taek),could be complemented by a contribution from KEPCO towards the cost ofenvironmental control measures in higher priority areas (reflecting thetemporary fuel saving achieved by shifting from natural gas to low-sulfurfuel oil). We recommend that mandatory fuel-switching policies in thepower sector be reviewed to ensure that they provide a cost-effectiveanswer to environmental objectives.

Gas Demand Scenarios

3.18 Projections of gas demand from the power sector are summarizedin Table 3.2. The table shows both the projections currently assumed byKGC whose plans do not provide for any use of gas for power generationoutside the Kyongin region, and an alternative scenario developed by themission, which provides for a broader-scope power/CHP construction program,together with use of gas in some existing plants, in the Yongnam region.

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Table 3.2: Power Sector Demand Scenarios(in thousand tons of LNG)

1989 1991 1996 2001 2006

KyonginExisting Plants 1,639 1,414 1,694 1,579 1,054Combined-Cycles - 1,252 1,902 3,203

Yongna a/Existing Plants - - - 48 1,026Combined-Cycles - 585 910 910

Existing Plants 1,639 1,414 1,694 1,627 2,080Combined-Cycles - 1.837 2.812 4.113

Total 1,639 1,414 3,531 4,439 6,193

a/ Alternative Mission Scenario

C. Main Infrastructure

3.19 The existing basic gas infrastructure, which consists of thePyeong Taek terminal and of a main trunkline from Pyeong Taek toSeoul/Incheon, is sufficient to accommodate the LNG deliveries provided forunder the existing contract. This basic infrastructure could bestrengthened and/or expanded to accommodate a measured increase in gasdeliveries. However, very substantial investments would be required if thedecision is taken to expand LNG imports much beyond the original contract.

3.20 In terms of future demand, KGC is faced with the followingcircumstances:

(a) a growing city gas market in the Seoul/Incheon area,which will require strengthening rf the Seoul loop overtime;

(b) additional demand from KEPCO for the new combined-cycleplant at Il-Do;

(c) a potential city gas market south of Pyeong Taek (i.e.,in areas hitherto not serviced by KGC's existing gassystem); and

(d) possible demand from KEPCO for existing or new powerunits south of Pyeong Taek.

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Taking these possible market developirents into account, KGC has prepared apreliminary "LNG Supoly Study." This study provides a conceptual approachto system development with preliminary implementation schedules and costestimates. These data provide the basis for the following discussion.

Terminals

3.21 No detailed feasibility studies have been conducted as yet tofully substantiate a strategy for LNG terminal capacity expansion. Thebackground information assembled by KGC to assess the potential forexpanding the existing Pyeong Taek terminal and the feasibility ofconstructing a new terminal on Il-Do island at Incheon are thereforefragmentary and would need to be supported by detailed feasibility studies.They are sufficient, however, to express a judgment on the possiblealternatives and chart a tentative strategy for future investment. The KGCstudy proposes the expansion of the Pyeong Taek terminal in two phases and,proceeding in parallel, the construction of a new terminal at Incheon. Theneed for a third terminal is not envisaged until the end of the studyperiod (2007).

3.22 The existing terminal at Pyeong Taek is equipped with fourstorage tanks (4xlOO,000 cu m) and has a nominal capacity of 2 million tpy.It could apparently be upgraded to 3 million tpy capacity at relativelylittle cost. Further extensions would involve substantial expenses due tothe need to install additional storage tanks. However, the site could notaccommodate capacity expansions beyond 5.5-6 million tpy because of limitedjetty capacity and lack of space for more than a total of six LNG tanks.

3.23 Construction of a second terminal, from the planning/designstage to start-up, is expected to take about seven years. On the basis ofexpected demand growth, a second terminal would be required by the mid- tolate-1990s, depending on the demand scenario being considered. Preliminarypreparation work would therefore need to start soon. In terms of location,the basic alternative is between a northern location (i.e., close to Seoul)and a southern location (close to the Pusan/Ulsan area). If the decisionis taken to construct a national gas grid covering the southern regions, asouthern site would present obvious advantages in terms of load balancingand could possibly reduce pipeline investment by lowering the long-termthroughput between north and south. At least three factors, however, wouldargue against a southern site for the second terminal: first, demand in thesouthern districts is expected to grow more slowly than in the Seoulmetropolitan area and, even under the most optimistic scenario, about 70Xof total sales would still be realized in the north by 2007. A secondfactor is KEPCO's decision ta install a major gas-fired power plant closeto Incheon. Given the magnitude of this plant's long-term fuelrequirements (3-4 million tons of LNG), the construction of a .partialiy)dedicated terminal at Incheon is logical. A final consideration relates tothe security of supply for the Seoul area, which is now entirely dependenton one single terminal and trunkline. Construction of a second terminal atIncheon would considerably alleviate security concerns and greatly improve

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the stability of supplies to Seoul which will remain the largest gas marketin Korea.

3.24 Present demand scenarios indicate that a third terminal wouldnot be required before the end of the study period. Presumably, a southerncoast location would by then be justified, assuming the earlierconstruction of a gas grid covering the southern districts. Thealternative of an autonomous terminal in the south dedicated to thesouthern market was also considered but is not deemed cost effective mainlybecause it would not obviate the construction of additional terminalcapacity in the north and of substantial pipeline in the south.

Pipeunes

3.25 The program of pipeline construction required to meet thealternative demand scenarios includes (a) reinforcement of the existingsystem north of Pyeong Taek; and (b) construction of trunklines south ofPyeong Taek. KGC's LNG Supply Study provides a preliminary conceptanalysis of the modifications required to expand the delivery capacity ofthe system, assuming that expansion of terminal capacity would proceed asdescribed in para 3.21. KGC had earlier commissioned a feasibility studyfor a national gas grid designed to supply the southern districts withnatural gas (para 1.25). This study recommended the phased construction ofa pipeline system that would successively reach the cities of Taejon(1993), Daegu (1993), Pusan (1994), Masan (1994) and Kwangju (1996).Completion of the loop between Kwangju and Masan was proposed for a later:date together with the construction of a new terminal on the south coast.

3.26 Regional (national) gas distribution can take the form of apipeline grid (such as exists in North America and Europe) or,alternatively, of "nodes' of gas distribution systems with local LNGregasification facilities supplied from the main receiving terminal by(road or possibly marine) tankers (as is also done in parts of the U.S. andEurope and in Japan). This alternative approach was studied by KGC andfound less attractive than a pipeline grid as indicated in the previousparagraph. We recommend that the viability of delivering LNG to satelliteterminals by tanker as a complementary approach to the stepwistconstruction of a grid be reassessed once key decisions on the basicinfrastructure construction program have been taken. Detailed studies mayindicate that temporary supplies of LNG by tanker could be attractive tothose city gas systems which are not planned to be tied to the main griduntil a later date. Early access to LNG would allow those companies tostart expanding their sales beyond the traditional manufactured gas marketsand plan the development of their network accordingly, which would reiucelong-term investment costs and facilitate the overall penetration of LNG inhigher-value markets.

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Supply Scenarios

3.27 Four alternative supply scenarios were developed in accordancewith the geographical breakdown introduced in para 3.1:

Scenario A would consist essentially of the strengthening andexpansion of the existing system to accommodate the expected increase indemand from KEPCO at Incheon and other sites in the Seoul metropolitanarea. This scenario would cover the northern area only (Kyongin region)and would require:

(a) the extension of the Pyeong Taek receiving terminal to 3.5-4million tpy capacity (5 tanks) by 1994 and 6 million tpy (7tanks) by 2006;

(b) the construction of a new terminal at Incheon with an initialcapacity of 2 million tpy (3 tanks) by 1997 and an ultimatecapacity of 3 million tpy (4 tanks) by 1999; and

(c) the strengthening of KGC's existing pipeline system toaccommodate the increase in gas flow and feed the new powerand CHP plants.

Scenario B would add to scenario A the (first-phase) constructionof a trunkline to the south (Pyeong Taek - Taejon). This scenario wouldcover the northern and central areas (Kyongin and Chungchong regions) andwould require:

(a) the extension of the Pyeong Taek terminal to 3.5-4 milliontpy capacity by 1994 and to 6 million tpy by 2006;

'b) the construction of a new terminal at Incheon with a capacityof 2 million tpy by 1997 and 3 million tpy by 1999;

(c) the strengthening of KGC's existing pipeline system; and

(d) the construction of a main transmission line from Pyeong Taekto Taejon (by mid-1993).

u

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Scenario C, which would cover the northern and southeastern areas(Kuongin. Chungjhorg and Yonfanm regions), would consist of:

4) the extension of the Pyeong Taek terminal to 3.5-4 million _tpy capacity (5 tanks) by 1994 and 6 million tpy by 2004 (7tanks);

(b) the construction of a new terminal at Incheon witn initialcapacity of 2 million tpy (3 tanks) by 1996 and ultimatecapacity of 3 million tpy (4 tanks) by 1998;

(c) the strengthening of KGC's existing pipeline system; and

(d) the construction of a main transmission line from Pyeong Taekto the s:!an/Ulsan area (via Taejon).

Scenario D would provide for the phased construction of trunklinesboth to the southeastern and southwestern regions. This scenario (coveringthe Kyongin. Chungghong. Yongnam and Honam regions) would require:

(a) the extension of the Pyeong Taek terminal to 3 5-4 milliontpy capacity by 1994 and 6 million tpy by 2004;

(b) the construction of a new terminal at Incheon with initialcapacity of 2 million tpy by 1996 and ultimate capacity of 3million tpy by 1998;

(c) the strengthening of KGC's existing pipeline system; and

(d) the construction of transmission lines from Pyeong Taek tothe Pusan/Ulsan area (via Taejon) and from Taejon to theKyongju area.

3.28 Details of the supply/demand profiles for the four scenarios arein Annexes 9 and 10; they are summarized in Table 3.3 below. An additionalfifth scenario (Scenario Cl) is also presented, which has been designed asan alternative to Scenario C to accomodate the alternative power sectordemand scenario introduced in para 3.14.

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Table 3.3: Gas Supply Profiles(million tons of LNG)

Scenarios A B C Cl a/ D

Total supply:

1989 2.0 2.0 2.0 2.0 2.01996 4.0 4.2 4.4 5.0 4.52001 5.1 5.5 6.1 7.0 6.42006 6.5 7.1 8.2 10.0 8.9

Power Sector Demand:

1989 1.7 1.7 1.7 1.7 1.71996 3.0 3.0 2.9 3.5 3.02001 3.5 3.5 3.5 4.4 3.52006 4.3 4.4 4.4 6.2 4.5

of which Combined-Cycle Plants:

1989 - - - - -1996 1.3 1.3 1.3 1.8 1.32001 1.9 1.9 1.9 2.8 1.92006 3.2 3.2 3.2 4.1 3.2

a/ Based on alternative power demand scenario for Yongnam region.

Cost Estimates

3.29 Detailed cost estimates of KGC investments for each of the fivescenarios are in Annex 11. They are summarized below:

Table 3.4: Alternative Investment Programs a/(in $ million)

Scenarios A B C C1 D

1990-93 323 424 598 598 6261994-97 427 432 574 574 8081998-01 16 16 80 142 802002-06 liZ 162 90 118 90

Total 928 1,034 1,342 1,432 1,604

a/ Including taxes and duties but excludinginterest during construction.

3.30 These cost estimates are based on the feasibility studiescommissioned by KGC. They would need to be refined through detailed designstudies as implementation proceeds. However, a preliminary review of theseestimates in the light of experience in other countries indicates thatthere is room for cost-effectiveness measures, particularly in the designand construction of transmission lines. Such measures would be likely toentail substantial cost reductions which would facilitate the penetrationof gas in the economy.

D. City Gas Distribution

.31 As indicated earlier, the Government's strategy has been tolicense private companies to establish city gas networks in selected urbanareas to be operated in the first place on manufactured gas with a view tobuilding up markets for LNG ahead of the start-up of actual deliveries.This is a sound strategy which has the double advantage of minimizingrecourse on public resources in an area which is essentially a commercialactivity, while ensuring access of high-value markets as soon as LNGdeliveries started. However, a number of shortcomings in the way city gascompanies have developed need to be flagged as they iApact directly onfuture sector planning and would have a number of important institutionalconsequences.

3.32 The main concern is that, while the government objectives in thesector are clearly long-term (10 to 15 years), partly due to the lumpinessof the investments involved and the characteristics of LNG contracts, theobjectives of the gas companies are essentially short-term and do notnecessarily match those of the Government. This is due to a number offactors, e.g.:

(a) the planning capabilities of the gas companies, both in termsof marketing and technical design, are not geared to the longterm and their planning horizon is at best three years;

(b) although there is an association of city gas companies, thecompanies do not seem to exchange information aboutdistribution network planning;

(c) finally, it seems that the development plans of individualgas distribution companies are largely dependent on short-term financial objectives.

This situation makes it difficult to reconcile the national objectives andthose of the private utilities in the absence of an overall policyframework providing guidelines for the utilities and ensuring that overallobjectives are met within the limits of economic and financial viability.This issue is further discussed in Chapter 4 (paras. 4.4-4.6).

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Company Operations

3.33 The city gas networks were initially dsveloped to operate onmanufactured gas. Because of the limited competitiveness of manufacturedgas outside the traditional cooking market, little provision was made indeveloping these systems for the subsequent introduction of natural gas,which the Government expected to lead to a broadening of gas markets, inparticular to address the space heating air pollution problem. As aresult, network structures are poorly adapted to the development ofimportant loads over large areas. The capacity of mains, which conditionsthe long-term capacity of the systems and their ability to expand overtime, has in general been conservatively planned and reticulation of mainsis little developed. The networks consist mostly of polyethylene (PE)coated steel pipes operating under a cumbersome multi-pressure system, withdistribution lines designed for low-pressure operation only, which severelyrestricts the scope for additional loads. Finally, customer governors aregenerally of an outdated technology and ill-suited to industrial use.However, the city gas companies appear to have developed reasonably goodnetwork computing capabilities, and the overriding issue is more one ofmanagement and investment priorities than of technical know-how.

3.34 The construction costs of gas utilities in Korea are generally highcompared to those in other countries. This is possibly due to localfactors, such as difficulties in obtaining trenching permits and severereinstatement regulations imposed by the municipalities and, moregenerally, excessive intervention of local authorities in planning,construction and safety issues. In addition, until recently governmentregulations precluded the use of polyethylene materials under medium-pressure operating conditions as is now the norm in most countries. Therelevant code of practice, which insisted on low-pressure distributionnetworks necessitating larger diameter pipelines and with far lessflexibility for subsequent expansion, was modified at the beginning of1989. Recourse to medium-pressure technology should result in aprogressive reduction in distribution costs, possibly by up to 20-30X.

3.35 The city gas companies normally invest in the mains anddistribution lines while local distribution networks (i.e., within newapartment building areas) are left to the developers. The cost ofinvestments downstream of the service connections (i.e., service lines,meters and regulators, as well as internal piping) is assumed by thecustomers. Investment financing does not appear to have been a problem sofar, with the companies being able to draw on cheap (5X) government fundsavailable through the Petroleum Fund. Part of these funds can be on-lentto customers to finance their own share of expenditures (internal piping,appliances, etc), which compensates to an extent for the conservative hook-up policy indicated above.

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Estimated Costs of Fture City Gas Investments

3.36 Due to lack of long-term planning by the city gas companies, themagnitude of gas distribution investment required to meet the expectedgrowth in non-power demand is subject to much uncertainty. The gascompanies are requested by the Government to prepare three-year investmentplans (on a rolling basis). However, because of the absence of long-termmaster plans, the extent to which past and present company investmentsprovide for the construction of a main grid, which would generate economiesof scale as markets develop, is unclear. This makes it particularlydifficult to extrapolate from the available near-term figures.

3.37 With the help of KGC, the mission prepared projections of gasdistribution investments for each of the four supply scenarios presented inthe previous section (Table 3.5). These projections should be consideredas very tentative and would need to be corroborated by conceptual studies(para 3.42). They are essentially based on linear forecasts of mains andservice lines according to future demand. As such, however, they provide arather conservative outlook of future needs, and therefore constitute areasonable basis for the purpose of assessing the economic viability ofsector investment.

Table 3.5: Estimates of Distribution Costs(in $ million)

Sicenarios A B C C1 D

1990-93 274 301 301 301 3011994-97 222 252 437 437 4931998-01 292 342 518 518 6392002-06 287 352 560 560 668

Total 1,075 1,247 1,816 1,816 2,101

System Planning

3.38 The high degree of uncertainty on future distribution costs, whichto a large extent derives from the role assumed by private investors inthis segment of the industry, will affect the ability of the Government tochart a rational gas utilization strategy and formulate effective policiesto implement this strategy, including pricing. Without questioning themerits of the government strategy to rely on private initiatives andresources in what is essentially a commercial activity, this element ofuncertainty underscores the need to take a longer-term view of systemdevelopment to rationalize the use of resources. Distribution costs aloneare expected to amount to between one and two billion dollars over the next10 years (or about 55-60X of total sector investments on a net presentvalue basis), and will probably require a continuation of government

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support on a significant scale. In view of the magnitude of theseinvestments, we recommend that conceptual master plans for urbandistribution networks, backed up by discrete consumer surveys, be preparedfor the largest consumer concentrations, including (a) the Seoul/Incheonarea; (b) the Pusan/Ulsan area; (c) a typical medium-density city (e.g.,Taejon); (d) a typical low-density city. Consumer surveys should focus onindustrial consumers, taking into account recent advance in gas utilizationtechnology. These master plans could be completed within a period of sixmonths to a year and at a cost of about $1 million, a very small amountcompared to the investment program itself. KGC should take the lead inexecuting these studies in close collaboration with the utilitiesconcerned.

E. Economic Evaluation

3.39 This section presents the results of an economic evaluation ofthe four alternative investment scenarios described in Section C (togetherwith the corresponding gas distribution component). The analysis is doneon an incremental basis, taking the situation in 1989 as reference, i.e.,previous investments are considered as sunk and the pattern of LNG usage in1989 is taken as a starting point. Future investments (by KGC and the citygas companies) are expected to achieve the following objectives: (a) toincrease the average end-use value of the quantities of gas available underthe original contract by shifting their usage from existing thermal powerplants (where they substitute low-value HFO) to city gas markets; and (b)to expand the overall supply of gas, in part in response to KEPCO'sincreased demand and in part (for Scenarios B, C and D) by broadening thegeographical availability of natural gas to the southern regions.

3.40 Economic benefits are derived from the netback value of gas atthe consumer (plant) gate, as discussed in Chapter 2. These netback valuesare based on the economic cost of the energy source being displaced,corrected for differentials in heating value, thermal efficiency, and thecapital and operating costs of appliances and end-use equipment. Economiccosts include the CIF price of imported LNG and all infrastructureinvestments by KGC (for reception, regasification and transmission) and thecity gas companies (for distribution). The analysis covers the period1989-2007.

3.41 Each alternative supply/demand scenario was measured against theoriginal 1989 situation by calculating the net present value (NPV) ofincremental costs and benefits. Since the four scenarios representincreasingly more ambitious investment programs, their viability should beassessed on an incremental basis (i.e., each additional investment shouldgenerate a higher NPV). The results underscore the high attractiveness ofScenariA with an NPV close to $1 billion. These positive results are dueto a combination of factors: (a) the basic infrastructure for supplyingSeoul is already in place and would only need marginal strengthening tosupport a substantial expansion in throughput; (b) as sales to city gas

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users expand, gas use can be shifted from substituting low-value HFO inpower plants to higher-value uses; and (c) high returns will be derivedfrom the use of gas in combined-cycle units starting in the mid-1990s.

3.42 The analysis also indicates that Scenario B, with an NPV similar tothat of Scenario A, would be an acceptable alternative; i.e., constructionof a transmission line south of Pyeong Taek to the Taejon area would bejustified, albeit on a marginal basis and subject to confirmation ofestimates of distribution costs for the Taejon area (para. 3.47).

3.43 While Scenarios A and B are clearly attractive, the analysisindicates that Scenarios C and D would not be viable in the absence ofsubstantial demand from the power sector, particularly in high-value end-uses (e.g., combined-cycle type of facility, including CHPs). Scenario C1illustrates the minimum demand from KEPCO estimated to be required tojustify construction of a trunkline to the Yongnam region. In brief, it isestimated that gas would have to be used in about 800 MW of new (combined-cycle) power capacity located in the south, as well as in a number ofexisting oil-fired units (about 1,500 KW), in order to justify the proposedtrunkline investment. Note, nowever, that the investment could bejustified with a lower demand from the power sector if substantial value isattached to the objective of reducing pollution in the highlyindustrfalized Pusan/Ulsan area!'-. The economic attractiveness ofScenario i is significantly more marginal than that of Scenario C becauseof the lower anticipated gas demand in the Honam region. The Government isconsidering far-reaching regional development plans for the westernseaboard, partly through the establishment of industrial zones. Theseplans could have a significant bearing on future gas demand, particularlyif the new industrial parks were to be equipped with centralized utilitysystems which would provide a convenient and economic market for naturalgas. We recommend that plans to make natural gas available to thesouthwestern part of the country be reviewed after regional developmentplans have been firmed up and updated forecasts of gas demand areavailable. Note that the conclusions reached in regard to Scenarios B, C,Cl and D are largely dependent on the estimates made of future distributioncosts. As indicated earlier, these estimates need to be corroborated byconceptual master plans for the key areas (i.e., Taejon and Pusan/Ulsan).

3.44 The results of the analysis (Annex 12) are summarized below:

U/ Gas substitution for HFO in existing power plants in thePusan/Ulsan area would generate substantial benefits through improvedenvironmental conditions. The analysis presented here permits apreliminary evaluation of the costs of meeting environmental concernsthrough gas use, should GOK decide to go ahead with an investment programnot fully justified from a strictly economic perspective.

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Table 3.6: Net Present Value of Alternative Investment Programs(in $ m'llion)

Scenarios: A B C Cl a/ D

13X Cost of CaDital

BenefitsPower Sector 3,096 3,168 3,133 4,171 3,150Others 1.681 2.024 2.601 2.602 2.853

Total 4,777 5,192 5,734 6,773 6,003Costs b/

LNG (CIF) 2,813 3,097 3,497 4,259 3,700Basic Infrastructure 422 488 683 702 809Distribution 549 615 819 819 914

Total 3.784 4.200 5.000 5.780 5.423

Net Present Value 993 992 736 993 580

81 Cost of Capital

BenefitsPower Sector 4,184 4,310 4,251 5,843 4,286Others 2.710 3.301 4.340 4.340 4.802

Total 6,894 7,611 8,591 10,183 9,088Costs b/

LNG (CIF) 4,630 5,125 5,847 7,220 6,225Basic Infrastructure 550 626 861 892 1,025Distribution 778 880 1.216 1.216 1.376

Total 5.957 6.631 7.924 9.328 8.626

Net Present Value 937 980 667 855 462

a/ Based on alternative mission scenario for power.b/ Capital and operating costs.

3.45 The results of the analysis were tested using a lower cost ofcapital (81). Prima facie, a decline in the cost of capital would ease theheavy investment burden associaLed with gas import and utilization. Theimplicit cost of infrastructure would go down and the economics of gasutilization in most residential, commercial and industrial applicationswould improve. However, as discussed in Chapter 2, a decline in the costof capital would also lessen the comparative advantage of gas use for powergeneration vis-a-vis coal in conventional thermal stations, which hingeslargely on capitai cost differentials. Because of the expectedpredominance of combined-cycles in the future pattern of gas use, this is asignificant factor. Actually, both factors tend to cancel each other, withthe present value of each alternative scenario showing little sensitivity

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to variations in the cost of capital (although this becomes an increasinglyrelevant factor as one moves towards more capital-intensive scenarios, e.g.C and D). This, however, does not eliminate the relevance of the cost ofcapital in defining a gas utilization strategy for Korea since differingcapital cost burdens would affect the distribution of the available rentamong consumers, with important pricing and other implications.

3.46 The impact of alternative LNG price hypotheses is alsoinstructive. The net present value of the four alternative supply/demandscenarios was tested with the three LNG price variants introduced inpara. 1.58.

Table 3.7: Impact of LNG Prices(NPV in $ million)

LNG Price Scenarios a/InvestmentScenarios I II III IV

A 993 1,113 1,242 1,223B 992 1,124 1,266 1,246-, 736 885 1,045 1,026Cl b/ 993 1,175 1.370 1,352D 580 737 907 888

a/ See para 1.58 and Annex 5.b/ Based on alternative scenario for power

sector demand.

While lower LNG prices would obviously improve the returns on Scenario A,they would not be necessary to justify a positive decision. Lower LNGprices, however, become relevant when assessing the prospects for ScenariosB, C, and D. All three cases show much improved returns at lower LNGprices, when assessed on an incremental basis vis-a-vis Scenario A. Withlower LNG prices (Scenario III), Scenario C could actually be justifiedwith a lower additional demand from high-value power units than under ourbase-case assumptions (about 400 KW instead of 800 MW). Note, however,that for Scenarios B, C and D, these conclusions are largely dependent onassumptions made on future distribution investment by the city gascompanies -- assumptions which need to be confirmed through conceptualmaster plans as indicated in para. 3.47.

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Suggested Agenda

3.47 We recommend that preparation work start for Scenario B as soonas possible, including (a) detailed feasibility studies for terminalcapacity expansion (at Pyeong Taek and Incheon); (b) detailed design of aPyeong Taek-Taejon pipeline (which could be conceived as a first phase ofan eventual trunkline to the south); (c) detailed design for thestrengthening of the existing pipeline system north of Pyeong Taek; and (d)conceptual master plans for gas distribution (backed up by discreteconsumer surveys) for the Seoul/Incbeon area, the Pusan/Ulsan area, theTaejon area, and a typical low-density city. In parallel, further analysisof gas demand from the power/CHP sector in the south would need to beundertaken jointly by KGC, KEPCO and KDHC, with a view to betterestablishing the justification for further extension of the gas grid. Inthis context, early clarification of government policies in regard to theconversion of existing oil-fired power plants to gas will be essential.

4. INSTITUTIONAL AND POLICY ISSUES

4.1 The analysis presented in the preceding chapters suggests thatthere is clearly a significant role for LNG in the energy sector in Koreabased solely on narrowly defined economic criteria. First, it appears thatlarge quantities of gas consumption for power generation will be justifiedno longer simply in a "swing" consumption role. Rather, LNG, when coupledwith combined-cycle generation technology, will emerge as a significantcomponent of the least-cost power ganeration plan for the country. Second,it appears that, in areas served by the existing gas infrastructure, gaswould be the economic choice in selected household, commercial and ,industrial end-uses even without consideration of environmental factors.Moreover, environmental benefits, even though they are difficult toquantify, are probably sufficient to justify an expanded gas utilizationstrategy aimed at a progressive expansion of gas infrastructure to serveselected areas outside the Seoul metropolitan area. Overall, KEEI's targetof some 10 million tons of LNG to be imported annually by 2010 (or 7.5X oftotal primary energy in that year) appears reasonable.

4.2 While the case for giving LNG a significant role as part of botha least-cost energy supply strategy and a least-cost pollution controlstrategy is quite compelling, there is a risk that, because of themagnitude of costs involved, government attention would be focussed oninvestment implementation to the detriment of policy development. There isindeed a complementary need for policy formulation to ensure that thecombination of market forces with selective government intervention leadsto an economically efficient LNG consumption pattern. An importantconclusion emerging from the previous chapters is that gas utilizationneeds to be carefully charted to ensure that it leads to an efficient useof resources; this applies particularly to the goal of reducing airpollution through fuel switching. However, while the general parametersthat govern the economic attractiveness of gas use in power and selected

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(both in terms of location and type) household, commercial and industrialend-uses are known, much remains to be done to adequately define a gasutilization plan and an implementation strategy for Korea. This willinvolve resolving a number of institutional issues dealing with thequestions of system planning, market analysis, pollution control options,technology availability and regulatory issues. This chapter presents apreliminary discussion of these important topics.

A. Strategy Formulation and System Planning

4.3 A critical feature of the proposed gas strategy is the centralrole to be played by the power sector (including CHP plants both fordistrict heating and industrial park supply). The pattern of gas-firedpower units will largely dictate the structure of the main gasinfrastructure (e.g., terminals and main transmission lines). At the locallevel, industrial (and large commercial) demand will be the maindeterminant of the viability of setting up a distribution grid, while thedevelopment of residential (and small commercial) markets will, in turn,depend on decisions made in regard to power generation and industry. Thisunderscores the need to lift as soon as possible the remaininguncertainties conicerning these two critical sectors. Our recommendation(para. 3.4) that industrial market surveys be carried out before extendingthe existing gas infrastructure to other regions is motivated by thisgeneral assessment.

(1) Power System Planning

4.4 Much progress has been done recently in defining the future roleof LNG for power development. KEPCO is firming up its projections of gasutilization in the Seoul area and KGC is making plans accordingly to meetthe revised demand scenario. Now that the basic premise that gas-firedcombined-cycle plants would be an attractive adjunct to KEPCO's presentarray of plant types has been established, there is a need to rationalizeand strengthen the interface between power planning and gas infrastructureplanning. The long-term use of gas in power plants (including CHP plants),in the Seoul area, and more importantly outside this area, will be acritical factor in defining and justifying future gas infrastructureinvestments. Details, however tentative, of the pattern of Lutureconsumption need to be worked out (e.g., quantities, plant locations, etc.)at an early stage since they will condition such major decisions as thelocation and timing of future terminals and bulk transmission lines. Tostrengthen the interface between the various agencies involved, werecommend that the Government consider the establishment of a task forceconsisting of representatives of KGC, KEPCO, HOER (and possibly KDHC) witha view to improving coordination of these agencies' planning efforts.

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(2) Residential, Commercial and Industrial Markets

4.5 The need to strengthen the planning capability of the city gascompanies was underscored when discussing the estimates of likely futureinvestments in gas distribution facilities. There are several ways for theGovernment to address this question. The choice of method will clearlyaffect the nature of the regulatory environment the Government would wantto enforce vis-a-vis the companies; it will also impact on KGC's role inassisting the Government structure a strategy for the sector:

(a)GOK could set broad objectives for the city gas companies basedon its own assessment of future demand and request them toprepare medium to long-term development plans aimed at meetingthese objectives. These plans would also include the companies'recommendations towards changes in policy as well as pujlicsector contribution to the financing of investments, and wouldbe reviewed by GOK.

(b)Alternatively, GOK would prepare a gas distribution master olanfor the Seoul metropolitan area, as well the financial andregulatory framework that would make its implementationpossible. This master plan would be used as a basis fornegotiating long-term supply agreements with private utilities.As in the first alternative, these agreements would also serveas a basis for the design of large infrastructure facilities byKGC and be an input in the size and timing of future LNG importcontracts.

4.6 Under either approach, GOK needs to have a reasonable knowledgeof the costs involved with various alternative distribution strategies. Inthe second approach, the Government would assume a more direct involvementin the formulation of policies and investments. In view of the extent ofexternalities involved (largely due to the environment issue) whichrestricts the scope for purely commercial transactions, we think that thisis the most reasonable approach. In this case, KGC should take the lead incommissioning the work for the preparation of the master plan.

4.7 Irrespective of the way the Government decides to deal with thecity gas companies, KGC would need to undertake as early as possiblespecific conceptual studies for the main urban areas where it currently is,or could soon be, supplying natural gas. This would enable KGC to plan itstransmission investments with sufficient confidence in its forecast ofdownstream developments. These studies should be undertaken in closecollaboration with the ucility(ies) involved and would be instrumental instrengthening the links between KGC and the distribution companiesindependently of the Government's choice of a regulatory framework.

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4.8 Gas penetration of the residential market will depend largely ona institutional mechanisms that condition investment decisions in thehousing sector. Given the magnitude of the investment programs to beundertaken, a lot more needs to be done to clarify government priorities inthe area of urban planning inasmuch as they affect fuel choices. With aview to this objective, we recommend that the Government establish aworking group on energy use in the residential sector, which would be incharge of preparing an "energy zoning plan" (initially for the Seoulmetropolitan area), together with the necessary regulations.

(3) Safety Codes and Standards

4.9 In parallel with the construction of the existing gastransmission and distribution system, the initial framework for aregulatory system has been developed by KGSC. This framework, which isbased on a compilation of systems in application in other countries,provides for (a) safety codes, defining minimum standards for gas supplysystem and end-use equipment; (b) engineering standards for the design andconstruction of gas supply system and end-use equipment; and (c) thelegislative basis for regulating the operations of public and privateentities involved in the sector.

4.10 The rapid pace at which gas has been introduced in Korea has ledso far to a generally straight adoption of codes and standards from thecountries supplying the technology. While this was indeed the mostexpeditious approach in the initial phase, consideration now needs to begiven to a detailed review of these codes and standards (a) to identify anylacuna in the existing system; and (b) to induce greater cost effectivenessin the design, construction and operacion of gas supply systems and end-useequipment, taking the specificity of the Korean environment into account.Streamlined codes and standards could be instrumental to hring about thereduction in the costs of supply systems and the improvemeit in equipmentefficiency that are seen as critical to the successful impl,mentation ofthe proposed gas strategy.

4.11 The review and development of codes and standards could followthe following four-step approach:

(a)identification and prioritization of issues through a riskanalysis of designs and operational procedures for supplysystems and end-use equipment installation and use;

(b)operational and environmental research in design criteria,materials, installation techniques and operational parameters,taking into account consumer know-how and public exposure;

(c)development of relevant Korean codes and standards; and

(d)amendments, if required, of enforcement proceoures.

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4.12 KGSC has the expertise and experience required to carry out theabove program with che assistance of KGC, selected city ges conmanies andequipment manufacturers. Additional expertise for specific purposes car, beobtained from the international gas industry. KGC should take the lead incarrying the ground work for this review, with KGSC and the KoreanStandards Institute providing direction and quality control and beingresponsible for final submission to the Government. The successfulcompletion of this program would provide the Korean gas industry with astrong technological base. It would need, however, to be subject to acontinuous updating process to benefit from further advancements inmaterials and techniques.

B. Environmental Quality and LNG Use

4.13 The future role of natural gas in Korea and envirornmental issuesare closely intertwined. Yet, little analytical work has been done so farto define a rational environmental strategy in the context of which the gasoption could be properly evaluated. While the construction of a nationalgas infrastructure can be justified, albeit for part of it on a marginalbasis, based on narrowly defined economic criteria (i.e., ignoringpotential environmental benefits), the rationale for such an ambitious gasstrategy would be clearly strengthened if it was conceived in the contextof a coherent environmental strategy based on an economic analysis of airpollution control options that would establish the relative advantages ofgas use in specific applications. This analysis would need to examineexisting fuel quality regulations, fuel switching options, as well aspossible emissions controls and other (conversion efficiency regulation)policy options. The evaluation should be based on economic and othercriteria including administrative feasibility. And, at least with respectto household energy consumption, it should consider equity as well asaconomic efficiency criteria.

4.14 Current regulations on fuel use are apparently based at leastpartially on administrative ease and on an assumption that commercial userscould more easily bear the financial costs of conversion and the additionalenergy costs of LNG city gas as opposed to HFO than residential consumers.Yet, residential energy use is overwhelmingly the greatest source of airpollution in urban areas and a major source of other environmental concerns(coal briquettes account for much of the solid waste disposal problem).Conversion of coal users in the household sector to a cleaner fuel isapparently considered administratively an intractable problem. Yet,experience in other countries would suggest that with the appropriatetechnologies, financing and institutional delivery mechani-ms, large scalehousehold fuel switching is feasible. Such fuel switching, along withother options and issues outlined below, requires analysis.

77 -

Polcy Options

4.15 The range of environmental control options potentiallyapplicable (technically feasible) for each specific pollutant of concernincludes current applications in Korea as well as alternatives notcurrently in use but which appear to deserve consideration aU, e.g.emission relocation DJ, end-use location control M, fuel treatment (i.e.,desulfurization), emission and combustion control, and fuel switching to amcleaner fuels.

4.16 The range of alternative emission control measures is discussedin Chapter 2. Reflecting GOK's concern with sulfur, FGD is a mandatedcontrol on new coal power plants, and is expected to become also mandatedfor other large-scale users in the industrial sector. It is unclear, LAhowever, whether the technical and economic tradeoffs of mandating suchcontrols for smaller facilities have been done, compared to switching tocleaner fuels or relying on centralized CHP plants (managed by industrialutilities).

4.17 Emission control can also be achieved through tightercombustion/end-use technology standards. Thus, the efficiency standardsplaced on manufacturing for boilers (greater than 1 MT/hour) have beenraised gradually since 1982. This has led to increases of more than lOX inthe case of larger oil boilers (5 MT/hr or more). There is an urgent need,however, to introduce similar standards for gas boilers (which are notcovered under the existing regulations); and to extend the manufacturingstandards to smaller boilers for all fuels.

4.18 Government policies have been largely focussed on HFO users andlarge users of coal (power). Yet, as seen in Annex 13, per unit of energy,coal is the biggest problem, and it is a problem for more than just sulfur

38/ The focus of the Government's environmental concern is assumed tobe essentially on the urban and highly industrialized environment. Theapproach could be different if the concern was broader geographically,dealing with the overall national environmental quality, or even the globalatmospheric warming concerns. However, some environmental control optionsare applicable for both narrowly defined and more macro problems.

I2/ This aims to minimize the point or area impact of the emission; itincludes the options of increasing stack heights or physically relocatingfacilities and/or building new facilities (such as coal-burning powerplants) away from urban areas. In Korea, in effect such controls are beingutilized for electric power users.

g/ This option, often implemented through changes in zoningregulations, prevents increased end-uses of particular types in specificareas. De facto use of this option, driven more by rising land values andother matters than by environmental concerns, is already taking place.

- ./a -

dioxide. The figures also suggest that use of diesel is not to be ignored.Hence, the following alternatives not currently in use should be examined:

(a)Foster the switching of household coal users to city gas throughspecial assistance programs. This would include a considerationof retrofit with very high efficiency household-sized boilerswhich minimize some of the retrofit costs (little or noventing). The examination of this alternative shouldincorporate the significant savings in solid waste removal thatwould be achieved. Alternatively, examine the feasibility ofdistrict heating systems in selected areas with high density ofcoal users.

(b)Encourage the switching of some diesel users to LNG city gas.The end-use analysis indicates that gas and diesel oil are closefrom an economic standpoint. In a "least-cost" S02 limitationstrategy, switching to gas would make sense if distributioncosts can be contained.

(c)As the focus moves from S02 to include other pollutants (inparticular NOx,, diesel (and gasoline) end-use switching willbecome increasingly relevant. In this context, comressednatural gas (CNG) would be a relevant alternative for urbantransport, particularly for market segments for which use of LPGuse is not feasible. Conversion of city buses would be a firstpriority. We recommend that a detailed feasibility study ofpossible use of CNG (or directly of LNG) as a transport fuel beundertaken.

Conclusions

4.19 LNG city gas is likely to be an important component of a "leastcost" air pollution control strategy, but. such a strategy should be basedon careful consideration of all options and all costs. Implementation ofthe preferred strategy can be through various direct or indirect policymechanisms. Direct mechanisms would enforce or induce the use of a givenoption through regulations or standards, e.g., emission standards.Indirect mechanisms include pricing (of fuels or emissions) and otherfinancial mechanisms, e.g., loans or subsidies. Finally, other marketmechanisms, such as emission charges, marketable permits and otherapproaches, should be considered as a way to implement a least-coststrategy.

4.20 In assessing the merits of alternative policy options, therelative importance of different types of end-users need to be taken intoaccount. This relative importance should reflect the number of users,current fuel use and emission loads (in relation to the end-use technologyemployed). Such considerations might suggest, for example, dramaticallychanging the 'mandated" downtown Seoul fuel switching priorities, shifting

- 79 -

the emphasis to users who heve low efficiencies and/or little remainingusefulness in tneir equipment. In any case, considerations of relativeimportance will necessarily focus the analysis on household coal users andthe options available, one of which is conversion to LNG city gas.

C. Market and Regulatory Issues

4.21 Implementation of the recommended gas strategy will finallyrequire examination of a set of institutional and regulatory issues. Someof these issues are listed below:

(1) End-Use Technology Supply

4.22 Given the current limited size of the gas market and thedistortions between financial and economic prices, market pressures aloneare unlikely to produce the needed availability of technologies withrequisite end-use efficiencies -- namely those which are .conomicallyoptimal. To adequately define and implement an effective gas utilizationplan, a detailed technology suppiier review is required and this should bean important component of an implementation strategy for Korea. Thisreview should integrate considerations of market analysis and, in turn, beIntegrated with possible institutional and regulatory changes pertaining inparticular to technology efficiency. Regulatory interventions such asintroduction of end-use technology effiziency and other performancestandards could be quite effective for a number of market segments,including gas burners for household cooking and space cooling equipment.Development of the relevant policies would probably be better managedcentrally under KGC, which does not mean that KGC should take directresponsibility for all the tasks involved since research can be farmed out.In particular, the collaboration of KEMCO and CGA should be elicited.

4.23 Thtere also is a need to foster the introduction of additionalend-use technologies (in particular small-scale high-efficiencytechnologies) into the Korean marketplace, as well as a complementary needto assist end-users to adopt these technologies. With the current state ofmarket development, technology dissemination is insufficient to makeinformation and transaction costs low enough for end-users and hence, tolead to the least-cost total (energy and technology) solution. Specifictechnologies requiring particular attention include small-scalecogeneration units (for commercial usage); absorptive cooling systems; andhigh-efficiency gas boilers for residential space heating. There also is aneed to bring gas boilers of all sizes up to international standards (aswas done earlier for oil/coal boilers). For each technology, the areas inneed of attention include: (a) technology supply; (b) technology and othercustomer cost financing; (c) provision of technical assistance to users(both before installation and after service). This set of issues involvetechnology suppliers, financial institutions, consulting and other service

- 80 -

companies, as well as city gas companlies. We recommend that KGC take thelead in coordinating the required technology development activities.

(2) Market Development

4.24 Experience in other countries has shovn that the development ofa gas market is dependent on many factors, not just the relative financialprice of the commodity. Market penetration, even to achieve end-uses thatare financially and economically optimal, may take institutional change andregulatory actions unless the financial incentives are overwhelming.Because gas is imported at a high cost, such incentives are unlikely to beavailable in Korea. As seen from the end-use analysis, there will beapplications that are economically attractive (,ither narrowly defined ormore broadly in the context of a least-cost air pollution strategy), butfinancially not attractive. Market penetration of such end-uses willrequire regulatory and/or institutional changes (price change, technologystandards implementation, technology import/lilensing, etc.). Among the-.lternatives to overcome these impediments inc'.ude selected energycommodity price changes; selected customer-cost adjustments (special loanfunds and terms); complementary end-use technology standards (as indicatedabove); and revision of current regulations impacting the adoption of somehigh-efficiency end-use technology such as changing the rules regardingcogeneration review (to ensure, for example, that the comparison is notbased solely on KEPCO's generetion costs but also g!.ve some considerationto additional costs and losses).

4.25 In addition, as environmental concerns increase, uses ofalternative market mechanisms to bring financial prices in line witheconomic prices that reflect some environmental externalities, deserveconsideration. More than the current command and control approaches(dictating emissior. standards and control technologies) need consideration.Approaches such as tradeable emission permits and emission charges can beused to attain the most cost effective path to particular environmentalgoals. Market mechanisms are beginning to appear in way other industrialcountries address their environmental concerns and measures that coulddramatically increase the use of such approaches are under consideration.We recommend that the Government examine these options.

KOREA

GAS UTILIZATION STUDY

Energy Balance Forecast(in million TOE)

. Nm MI LNG Aewv *gkj byjmHue PAnw. Pnmay E' Pc CiYGM FStm l h_

hI_y 12910.0 27.0 142.0 4405.0 0.0 37.0 7772.0 0.0 0.0 20765.0 3043.0 75.0 24503.0 44.3%

T_eott 3201.0 63.0 313.0 0.0 0.0 0.0 0.0 0.0 0.0 9201.0 74.0 00 9275.0 16.3%

Rins.ogm. 4265.0 3240.0 1045.0 0.0 0.0 11412.0 0.0 0.0 1319.0 17016.0 1435.0 1240 13575.0 33.3%

PubA&MwOU 1972.0 1033.0 0.0 0.0 0.0 42.0 0.0 0.0 0.0 2014.0 367.0 0.0 2301.0 4.4%

P4itdT 28374.0 217".0 2111.0 4435.0 0.0 11551.0 7772.0 0.0 1319.C 49016.0 5519.0 1"O 54734.0 100.0%

a smm"c 1189.0 1169.0 0.0 0.0 1065.0 920.0 2932.0 11105.0 0.0 18210.0 O63.0

eaGU"R 91.0 2.0 51.0 30.0 36.0 0.0 00 0.0 0.0 189.0 205.0

Los 0.0 0.0 0.0 0.0 11.0 0.0 0.0 0.0 0.0 11.0 -844.0 4.0

P*hLft 20654.0 22059.0 2162.0 4533.0 2104.0 12480.0 10704.0 11105.0 1319.0 57420.0

44.0% 34.1% 3.2% 6.7% 3.1% 16.5% 15.9% 1O% 2.0% 100.0%

ON Pw C4 LPG Hnu4ai L40 AntaM Bhumin HydVNue Rwiw. Pwnuy EJldIc CiWySm Fu4 ShWi

b1b0M 14513.7 0517.3 101.6 4334. 0.0 69.s 9000.5 0.0 0.0 23643.7 41752 110.2 27029.1 46.2%

Tuumupu 10635.7 9756.5 1070.2 0.0 0.0 0.0 0.0 0.0 0.0 10535.7 50.1 00 10915. 18.1%

Rmluubu 5127.4 3787.4 1'40.0 0.0 0.0 10760.0 0.0 0.0 1179.0 17095.4 1709.0 227.0 1903Z3 31.5%

PUatwo s 2016.3 2009.6 5.7 0.0 0.0 69' 0.0 0.0 0.0 2087.4 428.2 00 2513.6 4.2%

ft4ToW 324051 25070A 2560.5 4634. 0.0 10927.5 9060.5 0.0 1179.0 53662 6391.3 337.2 00390.7 100.0%

Sm ulmp 2303 2003.7 0.2 0.0 2472.9 314.7 36842 10916. 0.0 20892.5 7349.3

0oA#k U.3 1.2 30.1 26.0 236.9 0.0 0.0 0.0 0.0 305.2 337.2

Lasse 0.0 0.0 0.0 0.0 7.2 0.0 C.0 0.0 0.0 7.2 -958.0 00

P*n.UZ S3646.3 27075.7 2625. 4850.5 2713.0 11842.3 12744.7 10916.8 1179.0 74867.1

47.4% 37.4% 35% 6.5% 3.6% 15.8% 7.0% 14.0% 1.6% 100.3%

OQ :o

KOREA

GAS UTILIZATION STUDY

Energy Balance Forecast(in million TOE)

lowOi F s 06 LPG ONm" LUG Mlva saurn HWaac Pmnmw Pe 0,mwy Elsgl Cllyw Pai Urn

indum 12281.1 10366.3 .. 0 68 0.0 87. 1025A24 0.0 55A 28157.7 4850.3 33 33350. 47.0%no 1p7o550 1241.8 13418 0.0 Oh 0.0 0.0 0.0 0.0 13756 97.3 0.0 13820 19.6%

Rmzwmn. 6337.0 4517.8 1610.2 0. 0.0 361.0 0.0 0.0 M16.7 17026.7 2111.2 469.4 19007.3 2.1%PubAC0rms 222.7 2220.0 0.7 0. 0.0 34.2 0.0 0.0 89.5 2353.4 491A 0.0 2852. 4.1%FbToW 3S9003.4 29517.3 3400.? 3634. 0.0 0754.7 10252.4 0.0 1642.8 61293.3 7567.1 303.0 69035 100.0%

Swmn'bn 2915.3 2015.3 0.0 0.0 2320.8 1000.0 4231.0 13826.3 0.0 24294.3 8524.909Mok 2908.3 0.0 215. 32. SIB.? 0.0 0.0 0.0 0.0 815.0 503.0Loa 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 957.8 0.0

FWoL 43517.0 324332 38185 6787.3 267.3 10704.7 14484.4 13826.3 1648 88402.640.6% 37.8% 4.2% 7.8% 3.3% 12% 16.% 16.0% 1.9% 100.0%

01 Fuel U LPo WI-" LUiG Ass WmIny HMyduc Ruww. Pnnwuy Elso Co*Ga Fbd 88w.

Kiosay 20765.1 11682.3 68. 8333.0 0.0 22.5 14314.1 00 1157.7 36259.4 6352.1 1076.4 43687.9 48.2%uUapJn 21551. 19071.1 160.0 0.0 0.0 0.0 0.0 0.0 0.0 21551.9 138.7 0.0 21688.6 236%

rsuicmnn. 763.5 5456.7 2431.6 0.0 0.0 61594 0.0 0.0 700.9 16810.8 3213.4 127.8 21852.0 24.1%PubAOtmw 2500.0 248.0 13.0 0.0 0.0 24.3 0.0 0.0 250.4 2774.7 663.4 0.0 3438.1 3.8%PFiTW 52707.5 33299.1 5018.4 8303.. 0 0 606.2 14314.1 0.0 2169.0 77338.5 10368.7 2304.2 eM6008 100.0%

bminon 40103 4020.3 0.0 0.0 2607. 1094.0 0515.2 -15454.0 0.0 32391.1 11678.4GMWnuf 104. 0.0 194.6 0.0 2706.4 0.0 0.0 0.0 0.0 2304.2 2J04.2L s 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -1312.7 0.0

Pino as86Yu 43313.4 5t10.2 833.0 8517.0 9300.2 23829.3 15454.0 2109.0 113182.180.3% 38.3% 4.6% 7.4% 4.0% 8.2% 21.1% 13.7% 1.9% 10e.0%

M M

0

II-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~V

KOREA

GAS UTILIZATION STUDY

Energy Balance Forecast

(in million TOE)

01 Fui 01 LP hswo US AMW U1 "F~ PAn. PrwIwy EbS CIO

_ s-- 23 12222.7 4.550. 5J51.5 0.0 - .0.0 1319.6 .0.0 1705.5 43454.4 7U4.7 1500.1 525. 4.5%

wpm1. - 27b17.6 225 *1.4 0.0 0.0 0.0 0.0 0.0 0.0 27617.6 111.4 0.0 2775.0 25.%

PARIuM 5810.1 0100.9 2C. 0.0 0.0 677.4 0.0 0.0 7434 10346.6 4551.5 33244 24222 22

ftb8OUm 255W.5 2U1.4 -1TA 0.0 0.0 23.0 0.0 0.0 $41 1 3202.9 54.3 0.0 4"1.2 r7%

Fd*Tod 52007.5 46962 52. 951.9 0.0 6103 16319.0 0.0 2794 0 9021.7 13465.5 4833.5 1091.0 100.0%

_ _mpI 3312.S 5312.5 0.0 0.0 3400.5 1092.J 13225.4 21813.3 0.0 42047.7 15174.1

0k 30.0 0.0 30.0 0.0 43.4 0.0 0.0 0.0 0.0 4603.4 4533.5

Lou" 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -1708.3 0.0 c

AbpL. 66040.3 502757 SO12.7 19 .5234.2 703.1 315450 21513.3 275.0 135t5

47.7% 8.3% 4.3% 7.1% 5.0% 57% 2L.% 15.% 2.0% 100.0%

2010co VW ON LPG Nmnuh LNG AM" SWsi K^94= Rmwv. Ptnmy 3jgft CRySi FtU ohm

klusy 7017.6 13954.5 116.0 1104.5 0.0 0.0 21824.9 0.0 3527.0 52370.1 11325.9 2141.0 6563., 45.3%

Tuomu S4654.3 31255. 33663 0.0 0.0 0.0 0.0 0.0 49.0 4W03.3 357.9 0.0 35061.2 260D%

ALrmj.W 10604.2 727.3 3036O. 0.0 0.0 3773.7 0.0 0.0 1233.3 15676.7 3107.0 51535 26937.3 21.4%

Puvt&0tws 3151.2 311.7 31. 0.0 0.0 6.4 0.0 0.0 784.6 39412 1263.4 0.0 5204. 3.%

FbUTUN 7547.3 50015.5 760015 11S56. 0.0 $779.1 21524.9 0.0 3600.0 10091.3 21057.3 7294.6 135043.1 100.0%

Gmrom 19591 1969.1 0.0 0.0 6245. 500.0 25417.9 31533. 0.0 65969.1 23S90.0

o0zot 00.0 0 . 0.0 7294 0.0 0.0 0.0 0.0 7354.6 7264.6

Low" 0.0 0.0 0 Q0.0 0.0 0.0 0.0 0.0 0.0 0.0 -252.7 0.0

PrLn.N 77516.4 5795 7651.3 1156 .S 13543.2 4579.1 47242. 315335 5600.0 150015.0

43.1% 32.2% 4.3% 6.% 7.5% L5% 26.2% 17.5% 3.1% 100.0% @

111

KOREA

GAS UTILIZATION STUDY

Energy Balance Forecast(in million TOE)

Tad P,bmwy Unwo06 Fwi 06 LPG N.. LNG OM Antin nM HdNIW Pao. P* nwV OI9L%

1357 290M4.0 225.0 21.0 450 2104.0 23164.0 12480.0 10704.0 11150.0 1319.0 6742.0

10 35 3 273757 262 460 2716.0 2145.0 1164. 12744.7 10315.5 1179.0 7487.1 11.0%

1330 42517.0 32433.2 301" 6O6t 26875 252.1 1014.? 14464.4 1320.3 1642.8 5t4026 7.4%

1065 S5S662. 43310.4 5210.2 3930 5517.0 33129.5 3200.2 2=823.3 15454.0 2109.0 113162.l 5.5%

2000 MM04.3 S025T 5t12.7 6U1.0 62)4.2 39451.1 7103.1 3154.0 21013.3 2764.0 138332. 4.1%

2010 77516.4 596U60 7661.3 11666S 13543.2 S16211 4579.1 47242.8 315235 5000.0 18O005.0 2.7%

11-10 3.0% 2.9% 3.% U.% .% 3.7% -4.2% 0.1% 4.2% 60% .7%

T*W Fnal 5"wW09 FimI 0N LPG "Nuh Cog An@h tSlWmnn Rsww. Elstlc CuyGas FoiI drskt%

1087 28374.0 21765L0 2111.0 4465.0 19323.0 11551.0 7772.0 1319.0 5519.0 ¶99.0 54734.0

'IO6 32465.1 25070.J 25615 45.0 136.1 10027J 000.5 1179.0 6301.3 337.2 00380.7 10.3%

10 39603.4 23517.3 3400.7 054.5 20047.1 1794.7 10252.4 1642.6 7567.1 803.0 O0363.5 7.4%

1305 52707.5 39230.1 5O1S.4 3U33 22520. U062 14314.1 21609.0 10305.7 2904.2 9006.6 5.4% 1

2000 297.8 480962 55L27 651.0 2512.0 610.3 15319.0 2704.0 13465.6 4533.5 105321.0 3.7% D

2010 7547.3 56i019. 7001.3 11666.8 25004.0 377.1 21U4.9 SOO0.0 21057.3 7294.5 1S3043.1 2.2%

,1-10 3.3% 3.3% 4.1% 2.9% 1.2% -&A% 3.3% 0.3% 5.3% I1.7% 3.4%

Ib'iA E.flwOn FUe on LPG NefF*u CoM Anmta SWnmh Rneww. Eetor CftyO.u Fin 0GofL%

1907 12916.0 5279.0 142.0 4435.0 7009.0 97.0 772.0 0.0 3043.0 75.0 24503.0

1366 14513.7 3517.3 161.6 4834.5 9130.0 09.5 9000.5 0.0 4175.2 110.2 27920.1 14.0%

1000 17281.1 10366. 230.0 0S4.5 10319.9 67. 10252.4 556.6 4659.3 333.6 3335O.S 9.3%

135 20765.1 11CS29 06. 5393.0 14320. 22.5 14314.1 1157.7 5352.1 1076.4 43657.1 5.5%

2000 23425.3 12722.7 60.7 3551.9 15319.0 0.0 18319.6 1709.5 7364.7 1509.1 52641.2 3.9%

2010 27017.0 13964.5 1106.6 11.5 21624.9 0.0 21524.9 3527.6 11326.9 2141.0 653.3 2.2%

V11-0 2.3% 1.5% .6.% 2L.% 3.0% 3.6% 9.7% 4.3% 9.7% 3.5%

Tnuwapuee h maw0O FuNl 6 PG NbAfsl CoN Anywa SBumAn Renew. Elacuc C*tGw Foa GrowVh.%

130 1201.0 5233.0 016.0 0.0 0.0 0.0 0.0 00 74.0 0.0 927s.0

1OU 1035 075U 107.2 0.0 0.0 0.0 0.0 0.0 60.1 0.0 10015.5 17.7%

100 1375". 12413. 1341.8 0.0 0.0 0.0 0.0 0.0 97.3 0.0 136LO 12.7%

1995 21551.9 16671.1 100.8 0.0 0.0 0.0 0.0 0.0 135.7 0.0 21006.0 9.4%

2000 27617.0 25220.2 2309.4 0.0 0.0 0.0 0.0 0.0 181.4 0.0 27706.0 5.1% m m

2010 34654.3 32125.0 3003 0.0 0.0 0.0 0.0 49.0 357.9 0.0 35001.2 2.3%

11.10 47% 4.7% 4.7% 87% 4.8%

_

KOREA

GAS UTILIZATION STUDY

Energy Balance Forecast(in million TOE)

Rudu /CowunscWJEnugycm Fl Oil LPO Non-Fut Coal AnMtn Sfumin RPnw. EUAic CityGs Fini Giown3.e

1087 4285.0 3240.0 1045.0 0.0 11412.0 11412.0 0.0 1319.0 1435.0 124.0 18575.01906 5127.4 3787A 1340.0 0.0 10789.0 101.0 0.0 1179.0 1709.9 227.0 10032.3 2.5%1990 6337.0 4517.8 1019.2 0.0 9093.0 0093.0 0.0 908.7 2111.2 409.4 19t07.3 1.1%1905 7890.5 5458.7 2431.8 0.0 6159.4 8159.4 0.0 760.9 3213.4 1827.8 21652.0 2.2%2000 U16.1 3190.9 26252 0.0 6787.4 6787.4 0.0 743.4 4551.5 3324.4 24222.? 2.1%2010 10604.2 7627.3 3036.9 0.0 3773.7 37 3.7 0.0 1233.6 8107.0 5153.5 26937.3 1.%91-10 2.6% 2.7% 2.0% -4.6% -4.0% 1.1% 7.0% 12.1% 2.0%

Pia.c & Oms. EnugCi Fu ONi LPG Non-ust Coil Anilva Bumin Rwww. Emic City Ga Fini Growlh.%

1987 1972.0 1968.0 0.0 0.0 42.0 42.0 0.0 0.0 367.0 0.0 2361.01011 201113 2009.6 0.7 0.0 89.1 09.1 0.0 0.0 42.2 0.0 2513.0 5.0% 11990 2229.7 2220.0 9.7 0.0 34.2 34.2 0.0 B0.5 499.4 0.0 28528 6.% OD

1905 20.0 :237.0 i.0) 0.0 24.3 24.3 0.0 250.4 68.4 0.0 3438.1 3.6%2000 21138. 2621.4 17.4 0.0 23.0 23.0 0.0 341.1 646.3 0.0 40512 3.3%2010 3151.2 3119.7 31.5 0.0 5.4 5.4 0.0 784.A 1203.4 0.0 5204.6 2.5%

191-10 1.7% 1.7% 0.1% 4.% -L8* 11.5% 4.6% 3.1%

GF*Wlh RO % PsW

01 Fuel 0 LPG Non-ust LNG An lh ytVNuo Rmn. P qNm

1-'00 13.0% 12.2% 18.7% 14.3% 10.5% -4.7% tQ.O% 7.4% 7.6% 8.O%11-10 4.4% 4.5% &.0% 3.8% 11.2% 3.1% 6.1% 4.7% 5.5% 4.6%01-10 1.6% 1.4% 2.6% 1.9% 5.1% -5.3% 4.1% 3.8% 7.2% 2.7%91-10 3"% t9% 3.0% 2.8% 611% -4.2% 6.1% 4.2% 6.3% 3.7%

840 191-00 '01-10 *91-10maimmy 10.8% 4.7% 2.2% 3.5%TIwm.po 14.3% 7.2% 2.3% 4.8%RhsJCnL 1.3% 2.1% 1.8% 2.0%FulACkovwO 6.2% 3.0% 2.5% 3.1% I"P"iToi O.4% 4.0% 2.2% 3.4%

0ol-

- 86 -

Annex 2Page 1 of 3

KOREA

GAS UTILIZATION STUDY

Petroleum Product Price Forecast

Table 1: PROJECTION OF LANDED PETROLEUN PRODUCT PRICES IN KOREA

.. ... .... ........ ..---- I .... .. . .......................... . ......

I Year ICRUDE OIL. LPG DIESEL InJustr. FUEL OIL .KEROSENE NAPliTHA I

I I . OIL D.Oi B/C .

I IUS $/St . U S D o l l a r I TOn . I

1 1989 I 18.5 126.0 173.8 143.9 93.5 182.9 171.4 I

I 1990 I 156.0 184.0 157.5 104.0 197.0 185.7 II 1991 I 20 194.3 194.8 172.5 115.8 210.8 201.5 II 1992 I 201.9 201.3 176.6 119.5 217.1 207.8 II 1993 . 209.7 208.0 180.9 123.3 223.7 214.4 II 1994 I 22 . 218.0 214.8 185.3 127.3 230.4 221.5 II 1995 I 222.5 221.5 190.7 132.0 236.3 226.3 I

I 1996 . 227.2 228.4 196.2 137.0 242.4 231.2 II 1997 . 232.0 235.5 201.9 142.2 248.6 236.3 II 1998 I 25 236.8 242.9 207.8 147.5 255.0 241.4 II 1999 I 240.3 246.8 211.2 150.5 259.1 245.5 II 2000 . 243.9 250.8 214.7 153.6 263.3 249.8 1

2001 . 247.5 254.8 218.2 156.8 267.5 254.0 II 2002 I 27 251.2 258.9 221.8 160.0 271.9 258.4 II 2003 I 251.2 258.9 221.8 160.0 27i.9 258.4 II 2004 . 251.2 258.9 221.8 160.0 271.9 258.4 II 2005 . 251.2 258.9 221.8 160.0 271.9 258.4 II 2006 1 27 251.2 258.9 221.8 160.0 271.9 258.4 !I 2007 . 251.2 258.9 221.8 160.0 271.9 258.4 II .. I. .. ........ ................ ............ IIPresent I I

IValue * 1 203.5 214.5 184.4 127.1 228.0 216.8 1

t Present Value at discount rate: X 13

Exchange rate WOn /US S : 660

LHV : 11900 10250 10200 9800 10360 10550

KCat /Kg LPG Diesel IDO F.oil Kerosene Naphtha

-87 - Annex 2Page 2 of 3

Table 2: PROJECTION OF 'ECONOMIC PRICES' OF PETROLELH PRODUCTS IN KOREA

__.______._ ........ -- -.------------ ------------------- '''''''-''''''''''''''- ........................................................... F-

I Year ICRUDE OIL. LPG DIESEL Industr. FUEL OIL .KEROSENE WAPHTNA I

I I . OIL D.Olt B/C .

IUS $/St U S D o l l a r / Ton .

I 1989 I 18.5 343.2 221.8 190.7 136.4 . 236.1 231.2 II 1990 I 37n 3 232.3 204.7 147.2 . 250.5 245.9 I

I 1991 I 20 411.6 243.1 219.7 159.0 . 264.3 261.5 II 1992 I 419.2 249.6 223.8 162.7 . 270.6 268.0 II 1993 I 427.0 256.3 228.1 166.5 . 277.2 274.6 I1 1994 1 22 435.3 263.1 232.5 170.5 . 283.9 281.7 1I 1995 I 439.8 269.8 237.9 175.2 . 289.8 286.5 II 1996 I 444.5 276.7 243.4 180.2 . 295.9 291.4 II 1997 I 449.3 283.8 249.1 185.4 . 302.1 296.5 II 1998 ! 25 454.1 291.2 255.0 190.7 . 308.5 301.6 II 1999 I 457.6 295.1 258.3 193.7 . 312.6 305.7 II 2000 I 461.2 299.1 261.8 196.8 . 316.8 310.0 II 2001 I 464.8 303.1 265.3 200.0 . 321.0 314.2 II 2002 I 27 468.5 307.2 269.0 203.2 . 325.4 318.6 II 2003 I 468.5 307.2 269.0 203.2 . 325.A 318.6 II 2004 I 468.5 307.2 269.0 203.2 . 325.4 318.6 1I 2005 ! 468.5 307.2 269.0 203.2 . 325.4 318.6 II 2006 I 27 468.5 307.2 269.0 203.2 . 325.4 318.6 I1 2007 I 468.5 307.2 269.0 2.3.2 . 325.4 318.6 1I . . . .. I IIPresent I I

IValue * I 420.8 262.7 231.5 170.2 281.5 276.9 I

* Present Value at discount rate: X 13

Exchange rate Won /US S : 660

LHV : 11900 10250 10200 9800 10360 10550KCal /Kg LPG Diesel IDO F.oil Kerosene Naphtha

IECONOMIC PRICE BUILD UP I

IAssumptionc LPG DIESEL Industr. FUEL OIL .KEROSENE NAPHTHA I

IUS S/Ton OIL D.Oi B/C . I

ITerminal & Losses 63.1 24.2 23.1 20.3 25.2 31.9 IIlnland transport 36.5 9.5 9.5 8.5 10.1 10.1 I

IWholesale margin 117.7 14.5 14.5 14.4 18.2 18.2 II IIT o t a l 217.3 48.3 47.2 4' ' 53.5 60.2 I

IRetafl Margin 134.8 24.8 24.8 0 27 27 I-. - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - -

- 88 - Annex 2

Page 3 of 3

Table 3: LANDED PETROLEUM PRODUCT PRICES IN KOREA - 1 9 8 9 -

SINGAPORE & KOREA PETROLEUM PRODUCT PRICES CRUDE PRICE 19 $ /81M a r c h 1 9 8 9 ........................

I I L P G PREMIUM NAPHTHA KEROSEN DIESEL I 0 0 FUEL OILII . * I

I IIi FOB SING. March 19891 19.9 56.7 44.4 52.8 53.2 18.5 13.0 II US Cts/Gal *US$18l I I

I FOB SING. WON /lit I 34.7 98.7 77.3 92.0 92.6 76.8 54.0 II FOB SING. USS/ Ton I 97.3 199.5 162.7 174.1 165.1 135.3 85.2 II (Arab Gulf for LPG) I I

I AFRA rate* I 500 154 150 151 150 148 143 1I S 100 I 5.8 5.8 5.8 5.8 5.8 5.8 5.8 II Freight cost l 28.54 8.79 8.56 8.62 8.56 8.45 8.16 1I Insurance 1 0.13 0.21 0.17 0.18 0.17 0.14 0.09 1I CIF Price US$/ Ton 126.0 208.5 171.4 182.9 173.8 143.9 93.5 I

I LANDED KOREA S/T 1 126.0 208.5 171.4 182.9 173.8 143.9 93.5 1i I II Landed USS/MN8TU I 2.67 5 4.09 4.45 4.27 3.55 2.4 1l Landed US S/Gcal 1 10.58 19.86 16.25 17 65 16.96 14.11 9.54 1ILanded Won /liter 1 44.89 103.21 81.46 96.57 97.52 81.67 59.21 1

!I…

I ECONOMIC COST I

I Losses 1 1.17 1.62 1.62 1.62 1.62 1.62 0.95 II Inland Transpt W/l 1 13.00 5.35 5.35 5.00 5.35 5.00 5.35 II Terminal cost W/l 1 21.26 11.81 11.81 11.81 11.81 11.81 11.81 II Wholesale marg. W/i 1 41.98 21.5 9.64 9.64 8.14 8.14 9.1 1I Econ. cost- Average II Won /liter 1 122.3 143.5 109.9 124.6 124.4 108.2 86.4 II I 1I US $ /IMMBTU 1 7.27 6.96 5.52 5.74 5.45 4.71 3.51 1I US S lMcal I 28.84 27.61 21.91 22.79 21.64 18.7 13.9. II US $ /Ton I 343.2 289.9 231.2 236.1 221.8 190.7 136.4 I

I EX REFINERY PRICES II Won /lilter 1989 1 44.9 103.2 81.5 96.6 97.5 81.7 59.2 1I I 1I US $ /MMBTU (4) 1 2.67 5.00 4.09 4.45 4.27 3.55 2.4 1I I II US S /Ton 1 126.0 208.5 171.4 182.9 173.8 143.9 93.5 1

(1) Insurance % FOB 0.1 (4) Theoretical refinery price equal to(2) Losses * CIF 0.5 landed cost in Korea(3) Exchange WN $ 660Specific gravity 0.54 0.75 0.72 0.80 0.85 0.86 0.96Heating value Kcal/Kg 11900 10500 10550 10360 10250 10200 9800

GAS UTILIZATION STUDY

Schedule of Domestic Petroleum Product Prices

Governnent - Posted Domestic Oil Product .Prices…=======.====== -t~- =====_ ==5 =======5sr86. 11. 2.

I Unit: i,'1Liter, r. U91-_-_- ----- ----- ----- ---- ----- ----- - - -- ----- ---- ----- ----- ----- ---- ----- ----- ----- ----- ---- ----- ----- ----- ----Refinery Agent ( Whole Sale ) Service Station ( Retail )Before Tax After Margin After . largin AfterTax SET VAT tt! Tax IET VAT Ttl Tax NET VAT Tti Tax

VCUiLe - *SOl1fl 210.i8 210.78 42.16 252.94 463.72 21.50 2.15 23.65 487.37 35.12 3.;1 3S.63 `20.00Re0b^r ias1i^ne o1-62 163.62 35.972 196.4 359.96 16. 62 1.66 18.28 378.2S 21 90 2.16 23.76 402. 00* u~nade- cb$Xne 166.94 141.90 30.88 172.78 339.72 21.5C 2.15 2o.65 363.37 3j.12 3.51 38.63 402.00- - - _ __ - ----------------- - -------- - -- - ------------ --- …

------------------- ___________…-____ - - -----xernoxe=& 1145.20 14.5; 14. 5? 1i9.72 9.64 0. 96 10.60 170. 32 14. 25 1.43 i. 68 186.00 co

0. 4% D*atjel 131.56 11.84 14. 34 26. 18 157.74 8. 14 0. 81 8. 95 166.69 13.92 1. 39 1i. 31 182.00I. - Diesel 12S.87 11.60 14.05 25.65 154.52 8.76 0.86 9.64 164.16 13.49 1.35 14.84 179.001.6x B - A 114.I8 11.42 11.42 12*.64 7.19 0.72 7.91 133.522. Oe 8 - A 112.30 11. 23 11.23 123.53 7. 19 0.72 7. 91 131.441.6x L. E.0. 93.54 9.35 9.35 102.8? 7.36 0.74 8.10 110.993.0 L.LF.0. 89.65; 8.99 8.99 98.84 ?.36 0.74 8.10 106 041.6% B - C 77. ?4 7.2 7.72 . 84.96 8.2. 0.83 9.10 94.064.2.,x 8 - .75.68 ,;Q 7.59 63.47J.0O B ;C 7;.e61 7.36 7.36 80.97 7.43 0.74 8.17 89.14

Propane ;.en.Use) 1P5.43 15.60 21.06 36.66 231.69 77.0; 7 77 85.42 317.11 88.9? 8.901 97.39 41 .0OCxtY-S) I)),ID 8. 96 12. 1. 7. 06 123.12Butane .cen.Usei 194.57 15.57 21.01 36.58 231.15 56.23 5.62 61.85 293.00

.ity-as) 06.33 8. 51 11. 48 19. 99 126.32

SolveneJet A-..JP- 4Asphalt

lietes : 1. 100. of special excise tax is currently Imposed am presiox and -egular gasoline. 85!; on unleaded gasoline. 9% on diesel and 8d on V2. 16-; of value added tax Is tqually levied an all goods and strvices in Kurea.3. 10-; VAt is also included in the aar;in for agents and service stations.4. The prices of solvent and jet futl oil have beto liberallied since Feb. 6. 1083.5. The price of asphalt has bten liberalized since Xov. 2. 1988.

- 90 -Annex 4

KOREA

GAS I'fILIZATION STUDY

Coal Price Proiections

FOB Tr. & In CIF CIF----------(1989 U8MMT)- -------- (/ocal)

1989 37.02 11.16 48.19 7.651990 37.02 12.07 49.Ob 7.791991 37.02 12.36 49.38 7.841992 37.02 12.66 49.68 7.891993 37.28 12.96 50.24 7.981994 37.86 13.27 51.13 8.121995 38.45 13.70 52.15 8.281996 39.00 14.15 53.15 8.441997 39.S6 14.61 54.17 8.601998 40.13 15.08 55.22 8.761999 40.71 15.38 56.09 8.902000 41.30 15.68 56.97 9.042001 41.30 15.88 57.28 9.092002 41 30 16.29 57.59 9.142003 41.30 16.29 57.59 9.142004 41.30 16.29 57.59 9.142005 41.30 i6.29 57.59 9.142006 41.30 16.29 57.59 9.142007 41.30 16.29 57.59 9.14 m

Net PresentValue 38.46 13.51 51.96 8.25(1989)

Notes,

Bituminous coal11,340 Btu/lb or 6,300 Kcal/Kg

1988 date based on sEPCO's contract termsFOB projections based on IBRD dateTransport costs linked to crude prices

:EP8:0's Coal Price Structure '1988)(U8$/MT)

FOB 35.16Sea Freight 10.55Insurence 0.05

CIF 45.76

Impo't Duties (1%) 0.46Defense Taxes (2.5% 1.14Port Charges 0.13Inspection Fee 0.01Unloeding 1.26Other Cherges 0.01

Delivered Cost 48.77

- 91 - Annex 5

Page 1 of 4

KOREA

GAS UTILIZATION STUDY

LNG Price Forecast

Scenario I (Base Case) Ratios

LNG (fob) Transport LNG (cif) LNG (cif) LNG(fob) LNG(cif) LNG(cif)-------------($/mmbtu)------------- ($/Gcal) /Crude /Crude /D. Oil

1989 2.88 0.6S 3.S3 14.02 0.90 1.03 0.851990 3.12 0.70 3.82 15.16 0.90 1.03 0.821991 3.19 0.72 3.91 1S.52 0.90 1.03 0.821992 3.27 0.74 4.01 15.90 0.90 1.03 0.821993 3.35 0.75 4.10 16.28 0.90 1.03 0.821994 3.43 0.77 4.20 16.67 0.90 1.03 0.821995 3.S4 0.80 4.34 17.21 0.90 1.03 0.821996 3.65 0.82 4.48 17.77 0.90 1.03 0.821997 3.77 0.85 4.62 18.35 0.90 1.03 0.831998 3.90 0.88 4.77 18.94 0.90 1.03 0.831999 3.97 0.90 4.87 19.31 0.90 1.03 0.832000 4.05 0.91 4.96 19.69 0.90 1.03 0.832001 4.13 0.93 5.06 20.07 0.90 1.03 0.832002 4.21 0.95 5.16 20.46 0.90 1.03 0.842003 4.21 0.95 5.16 20.46 0.90 1.03 0.842004 4.21 0.95 5.16 20.46 0.90 1.03 0.842005 4.21 0.95 5.16 20.46 0.90 1.03 0.842006 4.21 0.95 5.16 20.46 0.90 1.03 0.842007 4.21 0.95 5.16 20.46 0.90 1.03 0.84

NetPresentValue 3.49 0.79 4.27 16.96

Notes: LNG (fob) pegged on marker crude (base - crude x .9)------ as under existing contract

Transport costs linked to crude (base $.65 in 1989)

Crude freight: US$9/MT in 1989, linked to crude oil prices.

- 92 - Annex 5Page 2 of 4

LNG PRICE PROJECTIONS

Scenario II Ratios

LNG (fob) Transport LNG (cif) LNG (cif) LNG(fob) LNG(cif) LNG(cif)-------------($/mmbtu)------------- ($/cal) /Crude /Crude /D. Oil

1989 2.73 0.65 3.38 13.43 0.85 0.99 0.821990 2.95 0.70 3.66 14.51 0.85 0.99 0.791991 3.03 0.72 3.75 14.86 0.85 0.99 0.791992 3.10 0.74 3.84 15.22 0.85 0.99 0.791993 3.17 0.7S 3.93 15.59 0.85 0.99 0.791994 3.25 0.77 4.02 15.97 0.85 0.99 0.791995 3.36 0.80 4.15 16.48 0.85 0.99 0.791996 3.46 0.82 4.29 17.02 0.85 0.99 0.791997 3.58 0.85 4.43 17.57 0.85 0.99 0.791998 3.69 0.88 4.57 18.14 0.85 0.99 0.791999 3.77 0.90 4-66 18.49 0.85 0.99 0.792000 3.84 0.91 4.75 18.85 0.85 0.9' 0.802001 3.91 0.93 4.84 19.22 0.85 0.99 0.802002 3.99 0.95 4.94 19.E9 0.85 0.99 0.802003 3.99 0.95 4.94 19.S9 0.85 0.99 0.802004 3.99 0.95 4.94 19.S9 0.85 0.99 0.802005 3.99 0.95 4.94 19.S9 0.85 0.99 0.802006 3.99 0.95 4.94 19.59 0.85 0.99 0.802007 3.99 0.95 4.94 19.S9 0.85 0.99 0.80

Net,PresentValue 3.31 0.79 4.09 16.24

Notes: LNC (fob) pegged on marker crude (base - crude x .85)

Transport costs linked to crude (base - $.65 in 1989)

Crude freight: US$9/MT in 1989, linked to crude oil prices.

- 93Annex 5Page 3 of 4

LNG PRICE PROJECTIONS--------------------------------------------- _

Scenario III Ratios

LNG (fob) Trensport LNG (cif) LNG (cif) LNG(fob) LNG(cif) LNG(cif)-------------($mmbtu)------------- ($/Gcel) /Crude /Crude /D. Oil

1989 2.57 0.65 3.22 12.79 0.80 0.94 0.781990 2.78 0.70 3.48 13.82 0.80 0.94 0.751991 2.85 0.72 3.57 14.16 0.80 0.94 0.751992 2.92 0.74 3.65 14.50 0.80 0.94 0.751993 2.99 0.75 3.74 14.85 0.80 0.94 0.751994 3.06 0.77 3.83 15.21 0.80 0.94 0.75i995 3.16 0.80 3.96 15.70 0.80 0.94 0.751996 3.26 0.82 4.08 16.21 0.80 0.94 0.751997 3.37 0.85 4.22 16.74 0.80 0.94 0.751998 3.48 0.88 4.35 17.28 0.80 0.94 0.751999 3.54 0.90 4.44 17.62 0.80 0.94 0.762000 3.61 0.91 4.53 17.96 0.80 0.94 0.762001 3.68 0.93 4.61 18.31 0.80 0.94 0.762002 3.75 0.95 4.70 18.66 0.80 0.94 0.762003 3.75 0.95 4.70 18.66 0.80 0.94 0.762004 3.75 0.95 4.70 18.66 0.80 0.94 0.762005 3.75 0.95 4.70 18.66 0.80 0.94 0.762006 3.75 0.95 4.70 18.66 0.80 0.94 0.762007 3.75 0.95 4.70 18.66 0.80 0.94 0.76

NetPresentValue 3.11 0.79 3.90 15.47

Notes: LNG (fob) pegged on marker crude (base - crude x .8)

Transport costs linked to crude (base - $.65 in 1989)

Crude freight: US$9/MT in 1989, linked to crude oil prices.

- 94 -

Annex 5Page 4 of 4

LNG PRICE PROJECTIONS

Scenario IV Ratios

LNG (fob) Transport LNG (cif) LNG (cif) LNG(fob) LNG(cif) LNG(cif)-------------($/mmbtu)------------- ($/Gcel) /Crude /Crude /D. Oil

1989 2.88 0.65 3.53 14.02 0.90 1.03 0.851990 3.00 0.70 3.70 14.69 0.86 1.00 0.801991 3.04 0.72 3.76 14.91 0.85 0.99 0.791992 3.08 0.74 3.81 15.13 0.84 0.98 0.781993 3.13 0.75 3.88 15.40 0.84 0.97 0.781994 3.19 0.77 3.96 1S.72 0.83 0.97 0.781995 3.27 0.80 4.06 16.13 0.83 0.9' 0.771996 3.35 0.82 4.17 16.55 0.82 0.96 0.771997 3.43 0.85 4.28 16.97 0.81 0.95 0.761998 3.51 0.88 4.39 17.41 0.81 0.95 0.761999 3.57 0.90 4.47 17.72 0.81 0.95 0.762000 3.63 0.91 4.S4 18.03 0.80 0.94 0.762001 3.67 0.93 4.60 18.26 0.80 0.94 0.762002 3.71 0.95 4.66 18.49 0.79 0.93 0.762003 3.71 0.95 4.66 18.49 0.79 0.93 0.762004 3.71 0.95 4.66 18.49 0.79 0.93 0.762005 3.71 0.95 4.66 18.49 0.79 0.93 0.762006 3.71 0.95 4.66 18.49 0.79 0.93 0.762007 3.71 0.95 4.66 18.49 0.79 0.93 0.76

NetPresentValue 3.24 0.79 4.03 15.98

Notes: LNG (foi) linked 50% to crude oil end 50% to coal(base - crude x .9 as under existing contract)

Transport costs linked to crude (base - $.65 in 1989)

Crude freight: US$9/MT in 1989, linked to crude oil prices.

of --

KOREA

GAS UTILIZATION STUDY

End-Use Analysis

Residential, Commercial and Industrial Markets

I. INTRODUCTION

1. This Annex presents the results of end-use analysis which examines thecomparative economic (and financial) attractiveness of using natural gas as opposedto other fuels. This analysis is intended to serve multiple objectives:

(a) to estimate the value (economic and financial) of gas in alternativeend-uses;

(b) to provide information regarding the attractiveness of gasinfrastructure investments; and

(c) to make inferences regarding sector organization and changes thatprivate firms and government bodies would need to make to insurepenetration of the most attractive end-use market segments.

2. Estimates of the value of gas in specific applications are an input to theestimation of overall subsector demand and to the examination of the economicattractiveness of supply infrastructure programs. There are two avenues in whichthese estimates are used in the overall supply-demand and infrastructure investmentanalysis. The estimates of gas value in specific end-uses, in particular thefinancial values, are used in estimating possible levels of demand. The economicvalue of gas is used as a measure of benefits in the cost/benefit analysis ofinfrastructure investments.

3. Even without resorting to an integrated investment analysis, it is possibleto utilize the end-use analysis to provide information regarding the gas infrastruc-ture investment. This is done by incorporating estimates of infrastructure costs(for a defined supply infrastructure investment program) into the end-use analysissuch that the economic cost of natural gas in a particular end-use can be comparedto the economic costs of the end-use being met by an alternative competing fuel (andits associated end-use technology). In the end-use analysis these infrastructurecosts are allocated to particular classes of end-users. The viability of theinfrastructure investment can be considered from the perspective of the variousend-uses in terms of whether the total gas cost for that end-use is lower than thecost of alternatives.

4. The comparative end-use analysis also allows inferences regarding whichspecific end-uses are most attractive from a gas utilization perspective; suchinferences can be made in both economic and financial terms. Cases in whichinferences in economic terms are not supported by the comparative analysis infinancial terms suggest needed policy changes, including pricing or other regulatorymechanisms, to alleviate the distortion between economic and financial parameters.

5. Other inferences on the need for policy or institutional changes can alsobe drawn from the comparative end-use analysis. The total economic cost of meeting

Page :' of 29

any particular energy end-use is the sum of the economic cost of the energycommodity at the point of importation or production and the costs associated withinfrastructure capital ai,d operations to take the commodity from point of productionor import to the point of energy end-use. The cost comparisons between an energyend-use met with gas or alternatively met via competing fuels must include the costsof the end-use technology (stove, boiler, etc.). The comparison must also includeappropriate adjustments to reflect differing end-use efficiency, if any. For manyenergy end-uses, relative technology costs and efficiency are a critical part ofthe comparative calculus in determining whether gas is competitive. In the U.S.(and to a lesser extent other large, well developed natural gas markets) the end-usetechnology is very important to gas' competitive position; gas end-use technologyis often lower in cost and higher in efficiency than the same technology whichutilizes oil (and much lower in cost and higher in efficiency than the sametechnology for coal). In addition, for some end-uses (or combined end-uses suchas space heating and cooling systems) a number of technology options are availablefor gas use but not for other fuels. In addition, other aspects of technologyavailability may be that some technologies are not as readily available from asgreat a diversity of euppliers, or the technologies are not available in sizes tomatch a large range of scale of end-use.

6. In Korea, the end-use technology market, at least as it pertains togas-using technology, is not fully developed. Some gas end-use technologies arenot available; others are available, but at costs and efficiencies which are lessfavorable to gas use than similar technologies in other, more well developedmarkets. The comparative end-use analysis allows estimation of the importance oftechnology availability, relative costs and efficiency to the economic use of gas. -The analysis also allows inferences regarding changes needed (such as theintroduction of specific technologies) to allow market penetration in those end-usemarket segments in which gas is most economic.

II. STRUCTURE OF THE COMPARATIVE END-USE

7. The comparative end-use analysis is done on an annualized basis, measuredin terms of annual energy requirements (kcal/year). Capital costs are annualizedusing economic discount rates and equipment lifetimes; the annual costs are thenallocated to the total number of kcal utilized per year and comparisons are madein terms of S/kcal.1

8. The methodology of the end-use comparative calculus includes estimatingthe various components that determine the economic costs of natural gas andcompeting fuels. The costs are then built up (summed) from production or importpoint to the point of end-use. Although all costs must be considered, it is usefulto distinguish between costs at various points, thus differentiating between thecosts born by the user and those born by the supplier.

9. In the economic calculus, some infrastructure costs are in some cases takenas zero (sunk), where the infrastructure is already in place and no additionalinvestment is needed "at the margin" to supply a particular user. This is the casefor many end-users in the Seoul area for the terminal and trunkline infrastructure,

1 This typa of comparison in terms of total cost/kcal is often referred toas a "levelized' cost comparison.

Vof 29

but not for distribution in which additional investment is needed "at the margin."The financial analysis follows somewhat the same approach as the economic calculusin that capital costs of end-use equipment are annualized and the comparison isexpressed in terms of $/kcal.

III. END-USE COVERAGE AND DATA REQUIREMENTS

10. A series of 17 representative end-use case analyses were constructed toexamine the competitive position of gas from both the national (economic) andfinancial perspectives (Table 1). These cases cover selected domestic, commercial,and industrial end-uses which differ in various ways and could therefore impact thecomparative calculus. Among the most important considerations are:

o differences in the end-use itself (e.g., cooking versus heating);

o differences in the quantity of use in a specific sector/subsectorfor the same end-use (hotel space heating is provided for more hoursthan that of commercial offices);

o differences in the quantity of use in a specific sector/subsectorwhich are a function of scale (large versus small commercialoffices).

11. Three general categories of information are needed for the analysis:

(1) energy requirements for specific end-uses.

(2) economic and financial supply costs of fuels delivered to the customergate; including, in the case of natural gas, infrastructure costs forimport, bulk transmission and distribution.

(3) economic and financial costs (and lifetimes) of end-use technologiesand other customer costs including, when gas is used, costs of servicelines, meters/regulators and internal piping.

12. A number of sources were drawn upon, including KEEI, KEPCO, KEMCO, twocity gas companies, complemented by mission estimates. The fuel price scenariosused in the analysis are presented in Annexes 2, 4 and 5. The estimates ofeconomic costs of equipment and infrastructure are based on financial costs nettingout taxes, as were the downstream (landed) components of petroleum products. Itwas not possible to determine an estimate of the economic (as opposed to financial)cost of electricity.

Base Case Analysis

13. The existing terminal and trunk line infrastructure in the Pyeong Taek-Seoul area can supply significantly greater quantities of household, commercial,and industrial consumption with only an incremental distribution system andcustomer investment. Hence, it was decided that for the household, commercial, andindustrial cases a base analysis would be defined as one in which the terminal,trunk and city ring line are treated as sunk costs. The results of this base caseanalysis are summarized below.

98 9Eage 4 of 29

List of End-Use Case Analysis

1. Cooking, Domestic Single Family

2. Cooking, Individual Apartment Unit

3. Cooking and Heating, Domestic Single Family

4. Heating, New 600 Unit Apartment Building (assumes apartments would havegas for cooking in any case)

5. Keating, Retrofit 600 Unit Apartment Building (assumes apartments wouldhave gas for cooking in any case)

6. Comiiercial Space Heating (and Hot Water), Office of 3,300 Sq. Meters (1000Pyong)

7. Commercial Space Heating (and Hot Water), Office of 39,600 Sq. Meters(12,000 Pyong)

8. Commercial Space Heating (and Hot Water), Hotel of 39,600 Sq. Meters(12,000 Pyong)

9. Commercial Space Heating and Cooling, Office of 26,400 Sq. Meters(8000 Pyong)

10. Commercial Space Heating and Cooling, Hotel of 26,400 Sq. Meters(8000 Pyong)

11. Cooking, Restaurant

12. Cogeneration of Electricity and Steam for Commercial Office

13. Industrial Process Heat - Textiles Industry

14. Industrial Process Heat - Metal Industry

15. Industrial Process Heat - Food Processing Industry

16. Industrial Process Heat - Electronics Industry

17. Industrial Process Heat - Glass Industry

l

- 99 - X 6Page 5 of 29

IV. SUMMARY RESULTS

14. The results of the base analysis for each of the 17 household, commercial,and domestic cases are shown in the attached tables. The fuel alternativesexamined include the following: two different city gas alternatives, one based ona combination of naphtha cracking and propane, the other based solely on a propaneair mixture; kerosene; diesel (light fuel oil); LPG; and Bunker-C fuel oil (HFO).In some cases electricity directly enters the calculus. In general, however, notall fuels are applicable to all end-uses, and in some cases a particular fuel (orfuels) may be utilized with differing technologies to meet the same end-use.

15. In general, LNG-based city gas is economically attractive (withoutconsideration of environmental factors) in selected household, commercial, andindustrial end-uses. Among the more important characteristics determining acategory which makes LNG city gas economic ares

(1) The competition is against a high economic cost fuel (at the burnertip). This category will always include LPG, and city-gas based onnaphtha and/or LPG; in some instances light fuel oil (diesel) alsofits this category.

(2) The user is willing to pay a premium based on the convenience orquality associated with the use of gas. Cooking falls in thiscategory for most households; many industrial process applicationsalso fall in this category.

(3) LNG gas is used in combination with h:.gh efficiency end-usetechnologies which are readily available in other markets ifnot in Korea. Certain cogeneration and combinedheatirng/cooling technologies fit this category.

(1) Domestic Cooking, Single Family Dwellings

16. Table 1 presents the economic and financial ccJiparison of fivealternatives for household cooking; the comparison is made on a "new" selectionbasis. In the absence of pipeline gas, LPG is the fuel of choice for domesticcooking. Compared to LPG, city gas (from LNG or manufactured gas) brings addedconvenience although at a significant added cost, and its penetration of urbanmarkets over the last 5-10 years reflects the significant increase in domesticincome achieved by the urban population. LPG is thus the fuel with which gas needsto be compared. Although there is still coal-based domestic cooking, thisalternative is not considered for a number of reasons: on a quality andconvenience basis it is not equivalent to a gas-based alternative. And, as incomesrise, cooking with coal is likely to decrease in use, particularly in urban areas.Strictly speaking kerosene and LPG are also not "equivalent' in quality andconvenience to the three gas-based alternatives, although LPG, being a gas, is muchcloser. The issue of quality and convenience is very important as cooking is aconsumptive energy use, and therefore fuel preference, and hence "willingness topay" (and economic benefit), is strongly influenced by qualitative factors,particularly as household incomes rise.

17. While the introduction of LNG as a city gas feedstock results in areduction in the cost of pipeline gas, city gas remains dramatically more costly,albeit more convenient, than LPG. The question is whether the consumer'spreference is such that the additional costs are warranted economically.Profitable city gas operations have established that single-dwelling consumers arewilling to pay for conveni"nce a price higher than LPG-equivalent. However, this(financially revealed) lower bound of the consumers' willingness-to-pay (about$49/GCal) is significantly lower that the estimate of economic costs of gas,including distribution, ($l22/GCal) (suggesting some cross-subsidy in the existinggas tariff structure). Absolutely clear-cut inferences as to the economicviability of gas use for cooking in Individual housings are thus not possible basedon the available data base. Although there is a possibility that gas distributioncosts are somewhat overestimated, the issue is whether domestic consumers arewilling to pay for quality the full extent of economic costs of gas distribution.A detailed assessment of possible embedded subsidies (or cross subsidies) in thecurrent tariffs would therefore be required before the Government decides topromote LNG as a cooking fuel in individual housing units more aggressively,particularly since an acceptable alternative exists in the form of LPG. One canpresumably assume, however, that as incomes grow further, the consumers'willingness-to-pay will eventually cover the full extent of economic costs as theydo in other countries.

(2) Domestic Cooking, Individual Apartment Unit

18. In the case of an individual apartment unit (Table 2), an additionalalternative would consist of LPG delivered in bulk to the apartment building andpiped internally to individual apartments. This alternative would be equivalentin convenience and quality to direct access to city gas, while being probablycheaper both in economic and financial terms (despite unit costs of gasdistribution for apartments being substantially lower than for single dwellings).(Note that kerosene would not represent an equivalent convenience alternative).If confirmed to be feasible, this alternative would undermine the rationale forcity gas-based cooking by apartment dwellers (unless coupled with gas use for spaceheating as argued below). We therefore recommend that the technical feasibilityof this alternative be investigated. On the other hand, if the piped LPGalternative is not feasible, then all the questions of preference and willingnessto pay raised in the previous case also apply to the apartment case.

(3) Cooking and Heating, Domestic Single Family

19. The case of domestic cooking and heating (single family) is shown in Table3, which presents the economic and financial comparison of six alternatives.Again, the comparison is maae on a "new" selection basis; the retrofit case wouldplace LNG gas in a less advantageous position. This case attempts to make thecomparison between somewhat equivalent alternatives while including coal. Incontrast to coal's exclusion from the cooking case analysis above, coal is includedin this case because not only is it currently an important fuel for domesticheating, but given the retrofit costs it is likely to remain so without significantregulatory directives and/or special incentives. However, the coal- (boiler) basedalternative, coupled with LPG cooking, is not really equivalent in convenience tothe other alternatives. As in the case of domestic cooking, as incomes rise therewill likely be changes particularly in urban areas; but these changes may be inthe direction of increased heating rather than retrofitting to somewhat moreconvenient heating source/technology. -

- 101 - Annex 6Page 7 of 29

20. Comparing the use of gas (for cooking and heating) with a combination ofLPG for cooking and diesel for heating underscores its lack of (economic andfinancial) competitiveness in the individual housing market because of high unitcosts of distribution, unless the convenience element in cooking is taken intoaccount. Diesel (heating) and LPG (cooking) are the least-cost options, and theranking is the same for the financial calculus. On an incremental basis, however,gas use for heating is shown to be economically attractive if one assumes that gaswould be used as a cooking fuel in any case. Moreover, if one applies the lowerbound of the consumer's willingness-to-pay (as established by the ongoing gastariff) as a measure of benefits derived from the use of gas for cooking, thecombined utilization of gas for cooking and heating is only slightly lesseconomically attractive than the gasldiesel alternative. on a financial basis,however, diesel remains substantially more attractive than gas (by about 102),which points to the need for a more disaggregated gas tariff structure todifferentiate between cooking loads and the larger space heating loads which offerscope for substantial economies of scale in system design 2.

21. It should be noted that in financial terms coal is indistinguishable fromdiesel, and could as well be the minimum cost option. While in economic terms coalis less attractive than diesel; it is actually still less economic as the existingcalculus underestimates the economic costs of the coal alternative. This isbecause financial prices of coal were used in both the economic and financialcomparisons as information to estimate economic prices was unavailable, althoughcoal is known to receive significant direct subsidies and, in addition, there hasbeen no consideration of relative environmental costs.

(4) Space Heating - Apart -nt Buildings

22. Two cases were examined to illustrate the issue of space heating inapartment buildings. In both cases, it is assumed that there will be citygas-based cooking (now or in the immediately foreseeable future). This appears tobe the accepted planning practice for apartments for the city gas companies. Costsfor gas connections, service lines. etc., are therefore only the incremental costsabove those for cooking. However, as the analysis discussed thus far indicates,while it is clear that Korean consumers will pay a premium for gas-based cooking,the level of this willingness to pay is unclear, and even if there is a highwillingness to pay, piped LPG may be a more economic solution to meeting consumerpreference, particularly in less dense areas. Both cases refer to a 600 unitapartment building. The alternatives considered attempt to reflect (a) the rangeof relevant fuel choices; and (b) the individual versus central heating systemoptions. The latter aspect i; important for multiple reasons. Increasingly,especially as incomes rise, households will want 'the control and convenience" ofregulating their own space heating. And, at lower incomes, a family may not wantthe burden of 'common heating standards" if these are higher than their own. Alsoexamination of the individual versus central system allows consideration of issuesof first costs and the burden of the first cost. There are a number ofinstitutional issues related to this question of first cost including who bears thecost and available financing means (e.g., individual apartment ownerlrenter (direct

2 Unit consump.ions are in a ratio of about 17 on an average basis; takingthe seasonal variations in heating loads and the daily variations in cookingloads into account, the relevant ratio is probably about 1:3.

6- 102 - Page 8 of 29

cash, direct but through financing, or through rental) or time payment from the gascompany). These issues can be expected to impact directly on fuel and technologychoices.

23. The first case (Table 4) represents a new apartment situation with fouravailable options: central and individual LNG city gas alternatives, a diesel(light fuel oil) individual option and a central heating Bunker-C option. TheBunker-C option is least-cost under both the financial and economic rankings. Butin economic terms individual gas is very close; given the estimation basis of thenumbers, there is not a sufficient difference to distinguish between these twooptions. This suggests that at this scale and for new construction gas heating maybe attractive, and given the individual convenience this would increase itsattractiveness to the consumer. But the distortions between itnancial and economicprices will be a barrier to such use. In financial terms Bunker-C is much cheaperand there are all the first cost financing and related matters outlined earlier.

24. The second case (Table 5) analyzis the options for retrofitting anexisting building. The options considered are continuation of central Bunker-Cheating (alternatives #3a and M3b); switching the centralized Bunker-C to naturalgas (12a and M2b); and switching completely to individual natural gas systems(alternative #1). The issue arises of the residual economic value of the existingequipmenit. The approach adopted here was to consider two bounding assumptions -i.e., setting this economic salvage value at either 10 or 100 percent of the valueof new equipment. The 100 percent figure would be for the case in which theequipment was just about to be installed and the fuel switching option was beingconsidered (options t2a and #3a). The lower figure of 10 percent ettempts toconsider a situation in which the equipment is in place but has some residual value(options t2b and M3b). The comparison indicates that continuation of Bunker-C useis clearly the least-cost option in both econom.ic and financial terms, although asthe time for equipment replacement nears, i.e., as the situation characterized by#3a approaches, gas becomes more competitive.

(5) Commercial Space Heating (and Hot Water)

25. The intensity of energy use, which im,'acts on the scale of gasinstallations, is the most critical factor when analyzing the use of gas forcommercial space heating. Two bounding cases were considered to characterize thisrelationship. The range of floor space considered goes from 3,300 sq. m. (1,000pyong), which represents the lower end of commercial buildings served by KukdongCity Gas Co. downtown Seoul, up to 39,600 sq. m. (12,000 pyong). The case ofcombined heating/cooling facilities was considered separately. as well as that ofhotels (because of their greater energy needs per unit of space). Sixalternatives, all using boilers, are considered. These include, in addition to LNGcity gas, the two other city gas options and diesel, Bunker-C and LPG-based boilersystems. The last is included only to provide a comprehensive comparison; it israrely used for space heating in Korea.

26. In the first case considered (Table 6), the building size (3,300 squaremeters or 1000 Pyong) represents the small end of the range of commercial buildingsserved by the Kukdong City Gas Co. LNG city gas at a total cost of $58/GCal isclearly not competitive. Based on both financial and economic criteria, Bunker-Cfuel oil ($38/Gcal) is the least-cost alternative, even though the efficiency ofits boiler technology is significantly lower than that of its nearest competitor,diesel (light fuel oil). Part of the economic competitive disadvantage of LNG gas

- 103 - Annex 6Page 9 of 29

in the commercial space heating is due to scale. Smaller commercial buildings havesignificant distribution and customer (boiler, service connection, piping) capitalcosts; and at the lower gas use of smaller (as opposed to larger) buildings, thesecosts account for most of the total costs, as the energy commodity costs are only$17 of the total $S58/Gcal.

27. The impact of distribution and customer costs is dramatically lessened atlarger scale and higher annual gas use. This is illustrated by the case depictedin Table 7 of a larger building size (39,600 square meters or 12000 Pyong), whichexemplifies situations at the larger end of the range of commercial buildingsserved by Kukdong City Gas Co. As in the prev'ous case Bunker-C is the least costoption in both economic and financial terms. However, while in financial termsBunker-C is much cheaper, in economic terms LNG gas l' very close. In fact, giventhe information base, the two estimates should be considered indistinguishable.This suggests that at larger scales where the impact of infrastructure and customercoste are lessened, natural gas may be an economic alternative for commercial spaceheating. But such a choice will not be made based on current financial prices.A close review of the gas/HFO alternative (taking into account possiblemodifications in relative boiler efficiencies is and the possible impact ofdifferences in non-fuel operating costs of energy systems, is important todetermine whether existing scale-determined, fuel-switching environmentalregulations are grounded on appropriate economic rankings.

28. Hotels. Table 8 presents a third case developed to examine commercialspace heating. This case is designed to examine the implications of hotel versusoffice building differences. The case incorporates a building of the same size(39,600 square meters or 12000 Pyong) as the larger office case presented above butwith the much higher (per unit of space) energy use based on hotel rather thanoffice heating; again, this is exemplified by usage rates experienced by companiesin Korea. As in the previous cases, Bunker-C is the least-cost option in financialterms. However, while in financial terms Bunker-C is much cheaper, in economicterms LNG gas is now lower in cost. This reinforces the implications of theprevious case, namely that at larger scale and/or higher usage where the impact ofinfrastructure and customer costs are lessened, natural gas may be an economicalternative for commercial space heating But, again, such choice will not be madebased on current financial prices.

(6) Restaurant Cooking

29. Table 9 presents the economic and financial cost estimates for fivealternatives for a (small) restaurant. However, only the four gas alternativesare reasonably comparable based on cooking convenience, quality and lack of smell.Hen?e, kerosene is included only as an incidental reference. Among comparablealternatives, NG city gas is the least-cost option and there is no distortionbetween the financial and economic rankings. Consideration of larger restaurantswould only increase the attractiveness of LNG city gas as the weight of the capitalcost components (in total costs) would decrease as usage increases. A primaryreason for the attractiveness of gas as a fuel for restaurant cooking is the factthat it is competing against other fuels that also start out with high energycommodity costs (as opposed to delivery and end-use technology costs), inparticular LPG.

Annex 6- 104 - Page 10 of 29

(7) High End-Use Efficiency Options in Commercial Sector.

30. The commercial space conditioning cad-use is further examined with threeadditional case analyses which examine high end-use efficiency achieved throughmeeting jointly two energy end-uses. The first two cases which follow examine theuse of gas-fired absorption technology to provide both heating and cooling. Thethird case examines internal combustion engine technology for the joint productionof electricity and heat. Even more so than other cases reported herein, theseanalyses must be considered only as illustrative and indicative. Further analysisof these high efficiency options should be part of any overall gas development planfor Korea.

31. Heating/Cooling Systems. Table 10 looks at the total space conditioning(heating and cooling) requirements of a commercial office building (26,400 sq.maters or 8,000 pyong). Four alternatives are considered: in the firstalternative (#l) natural gas is used for both heating and cooling (absorptivecooling); the second alternative (12) uses natural gas for heating and electricityfor cooling; the third alternative (13) uses diesel gas for heating and electricityfor cooling; finally, the fourth alternative uses Bunker-C and electricity. Theimportant inference is that use of this high-efficiency technology (gas-firedabsorption) makes gas quite competitive in economic terms ($52/Gcal): lower thandiesel ($57/Gcai) and close to Bunker-C ($49(Gcal), whose costs are likelyunderestimated. But again, as in other cases, the financial rankings aredifferent, indicating that financial pricing will, as in other cases, be a marketbarrier that wi]l prevent gas penetration of this market with this technology.

32. Table 11 shows the case of a hotel of 26,400 Sq. Meters (8000 Pyong). Thehigher energy consumption (of hotels compared to office buildings) decreases therelative impact of capital cost components and enhances the competitiveness of gas.In this case also, gas appears as more economic than diesel. And given theestimation basis, the economic costs of the gas heating and cooling option(S26/Gcal) must be considered indistinguishable from those of the very preliminaryestimates (and likely low) for the Bunker-C alternative ($24/Gcal). But, in thiscase also, there is a distortion in the ranking based on financial prices,indicating the need for further analysis to define corrective measures.

33. Cogeneration of Electricity and Steam for Commercial Office. Cogenerationanalysis can be particularly complex because of the range of technical options andoperating procedures. The technologies vary in their mix of electricity, steam,and heat outputs which can be used to meet a wide variety of end-uses: lighting,shaft power, space heat, process heat, space cooling and dehumidification.Furthermore, the operating procedures can vary from thermal to power loadfollowing, and can involve power sales to the grid or only in-house use. Theeconomics are complicated by cost factors such as grid electricity costs (peak,off-peak), grid prices for cogenerated electricity (peak, off-peak), stand-by powercosts, and availability and cost of fuel (peak, off-peak). Despite thesecomplexities, a simplified analysis is possible in order to indicate the potentialattractiveness of cogeneration.

34. Tables 12 a&b present the case of a cogeneration system sized to meet thebase-load thermal erergy demands of a commercial building (floor space: 26,400 sq.meters or 8,000 pyong) so that all of the electricity and heat produced is usedin-house. The approach compares the total annual cost of meeting the thermalenergy demand by cogeneration versus other fuels with conventional boilers. The

- 105 - Page 11 of 29

cogeneration options are credited with the value of electricity produced;sensitivity analysis is performed to examine the sensitivity of the total annualcost to the value of this electricity credit. (An equivalent way to approach thisissue could be to credit the cogenerated steam with the value of other steamraising technologies and calculate an inferred marginal cost of electricity. Thiselectricity cost could then be compared with the ecotomic cost of deliveredelectricity from the grid.)

35. With the base case of valuing electricity at $0.10/kwh, gas-firedcogeneration is the least-cost option. The next least-cost options are a naturalgas-fired boiler and then a bunker C-fired boiler. Diesel cogeneration is moreattractive than a diesel boiler, but it ig more costly than these other options.The cogeneration option is sensitive to the value of the electricity credit whichconstitutes more than one-half of the total annual costs of cogeneration. Incomparison to the boiler-only option, the marginal cost of cogenerated electricityis about $0.07/kwh in the case of natural gas. At electricity credits below thismarginal cost, cogeneration becomes unattractive. Note that the divergence betweeneconomic and financial prices changes the ranking of attractive options, withdiesel cogeneration being the least-cost option.

(8) Industrial Sector

36. Gas can only compete effectively in the industrial sector in applicationswhere its quality or other characteristics are of relevance to its end-use such asin a number of direct heat and drying processes where gas enjoys a clear albeitdifficult-to-quantify technical advantage (due to its clean combustion and betterflame quality because of its paucity of impurities, easy heat control, and otherfactors). Industrial utilization is characterized by high unit consumption. Fiveseparate cases of direct heat applications were examined to allow for a sufficientrange of parameters for gas utilization and conversion (retrofit) costs, coveringthe textiles industry, metal industry, food processing industry, electronicsindustry and glass industry (Tables 13-17). All are retrofit cases and in allcases the assumed substitution is either LPG or diesel or some mixture. To reflectthe salvage value of equipment in place, a 10 percent salvage value (retrofit) caseand a 100 percent value (new/whole replacement) case are used for boundingcharacterizations of the conversion costs involved. Since all of the industrycases are ones of relatively high energy use, it is assumed that petroleum productscan be obtained directly from the refiners (avoiding the wholesaler costs) at theex-refining price plus inland transport costs. In subsequent analyses thisassumption may warrant further investigation and analysis.

37. The alternatives considered include, in addition to LNG city gas, the twoother city gas alternatives, diesel (13 and 14) and LPG (t5 and 16). In the caseof diesel and LPG, there are two alternatives reflecting differing assumptionsregarding equipment salvage value/economic life.

38. The economic comparison shows that, despite a wide range of unitconsumption (from 15 to 650 thousand cubic meters per month) gas is in all casesthe least-cost choice even when the salvage value of equipment is low. However,there are distortions from economic ranking based on financial costs. Thissupports the view that, to compete in the industrial fuel market, the city gascompanies have to be willing to sell at substantial discounts.

6- 106 - Page 12 of 29

TABLE 1

SECTOR: DOMESTIC COOKING(Single Family Dwelling)

------------------------------------------------------------ __----------

#i #2 #8 94 #5N. Gas LPG Keroseno C. Goo C. 0*o2

LPG/Nsp. (prop)unit m^3 kg liter a's m'Skeel/unit LliV 11,000 11,000 8,800 11,000 1,000end-use efficIency (1) 70 70 46 70 70Ocai/y- (1lo' kcel/yr) 1.98 1.96 8.08 1.98 1.96

ECON. Build Up */GoalCIF/Production 16.96 17.10 22.00 19.26 17.10Terminel/Refining 5.96 2.45 18.96 12.48Transmiusion/Wholoeaio 14.60 2.74 8.88 8.46Distribution/Retail 104.93 12.78 2.80 104.98 104.98SUBTOTAL Cons. Gate 121.89 60.44 29.79 146.61 187.96

Applilenc/Equip. S/Ocal 16.58 18.64 4.68 16.68 16.58K cost 187.74 154.82 80.30 187.74 187.74KIlf- 8 8 8 8 8

InhOut Pipe etc. 3/ocal 65.82 68.82 68.82K cost 692.98 692.98 692.96K life 20 20 20

SUBTOTAL Customer 69.91 18.64 4.56 89.91 69.91

ECONOMIC COMPARISONTOTAL I/Gcoal 191.79 69.08 84.86 216.42 207.87TOTAL S/yr 879.75 186.78 105.80 428.61 411.68

COMPETING FUEL VRS N. GAS - 8REAKEVEN ECON. COSTS S/GenlSystem Investment 52.12 86.47 199.46 190.91Invest. To Cons. Gate -17.79 -88.48 129.55 121.00Invest. To City Gote -122.71 -188.86 24.63 16.08

Netback Value at Consumer Gate -0.88 -16.47 140.61 187.96

N. Gas LPG Kerosene C. Gost C. Gas2FINANCIAL COMPARISONConsumer OGte (S/Goal) 45.19 69.60 88.86 46.19 48.68

Appliance/Equip. S/Gcal 14.62 16.48 4.48 14.62 14.62K cost 161.52 170.80 88.a8 161.62 161.62K lfe 8 8 8 8 8

InsOut Pipc sto. 8/Goal 87.41 87.41 87.41K cost 762.27 762.27 762.27K l.fo 20 20 20

TOTAL */Ocol 97.28 76.08 88.84 97.23 100.69TOTAL S/yr 192.61 160.64 118.10 192.61 199.17

--------------------------------------------------------------- __-------

6Page 13 of 29

- 107 -

TABLE 2

SECTOR: DOMESTIC COOKING(Individual Apartment Unit)

------------------------------------------------------------- __--------------__--

#1 #2 P t4 #5 #6Conventional Piped

------- ------- ------- ------- --------- LPGN. Gas C. ceos LPG Kerosene C. o2 --------…

LPG/"ap. (propane)unit m'8 m^3 kg liter m"s kgkcal/unit 1HV 11,000 11,000 11,000 8,800 16,000 11,000and eff. () 80 so 80 4E 80 80Ocal/yr (10^8 kcel/yr) 1.98 1.98 1.08 8.62 1.98 1.98

ECON. Build Up 8/OcalCIF/Production 16.69 19.26 17.10 22.00 17.10 17.10Terminal/Refining 18.96 5.98 2.46 12.48 6.96Transmission/Wholesale 8.s8 14.60 2.74 8.46 14.60Distribution/Retail 29.24 29.24 12.78 2.60 29.24SUBTOTAL Cons. Gate 46.20 70.88 50.44 29.79 62.26 87.66

Appliance/Equip. S/Oal 16.64 16.64 18.69 8.99 16.64 18.69K cost 188.18 188.18 165.26 80.80 188.18 155.26K life 8.00 8.00 8.00 8.00 8.00 8.00

InaOut Pipe etc. S/oal 87.42 87.42 87.42 12.72K cost 486.86 486.u8 489.86 165.29K life 20 20 20 20

SUBTOTAL Customer 54.06 54.06 18.89 8.99 54.06 81.41

ECONOMICTOTAL S/Gaol 100.26 124.99 69.18 88.78 116.84 69.07TOTAL S/yr 198.62 247.27 138.68 118.91 280.85 186.78

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS S/GcalSystem Investment 107.98 62.17 48.09 99.88 52.11Invest. To Cons. Gate 58.87 -1.89 -10.97 46.82 -1.96Invwst. To City Gate 24.88 -81.18 -40.21 16.08 -81.19

Notback Value at Consumer Gate 70.98 16.07 6.99 82.28 15.01

Conventionol Piped------------------------------------------ LPGN. Gas C. uasi LPG Kerosene C. 0*2 ---------

FINANCIAL COMPARISONConsumer Gate (S/Oal) 45.19 45.19 57.16 88.86 48.56 57.16

Appliance/Equip. S/Gcal 14.87 14.67 16.48 8.92 14.67 16.48K cost 162.00 162.00 170.79 88.28 162 170.79K life 8.00 8.00 8.00 8.00 8 6.00

InlOut Pipe etc. S/Goal 28.26 26.26 26.28 8.92K cost 656.00 585.00 586.00 181.82K life 20 20 20 20.00

FINANCIALTOTAL S/GOal 86.12 86.12 78.64 87.78 89.48 82.68TOTAL S/yr 170.61 170.61 145.81 188.00 177.17 168.48

-- -- -- -- -- -- -- -- -- -- -- -- -- -- -- - --- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- ---

- 108- Annex 6Page 14 of 29

TABLE J

SECTOR: DOMESTIC COOKING AND HEATING(single family du llinp)

-------------. _--------------_-------------------------------__--------_-----__---------------_--_------------

#1 92 #S #4 P p- - -- - -- - -- -- -- -- -- -- -- -- --- -- -- --- -- -- -- -- -- -- -- -- --- -- -- -- -- -- -- -- ---

Not. LPGcook3diloslhoot LPOcookceoalhoet NOcooldeselbhatGo* C. auol LPG Di-gel C. Ga82 LPG Coal B. N. 0ae Diesel

LPG/Nap. (propane) (bolier)unit N'8 0^8 kg lOter a's kg kg u'S literkcal/unit UHV 11,o00 11o000 11,000 o ,720 15,000 11,000 4,167 11,000 0,720end-UFA effic. (N) cooking 70 70 70 70 70 70end-ua; offic. (3) heating es es 0o es 45oal/yr cooking 1.93 1.03 1.93 1.96 1.93 1.93Goal/yr beating 14.08 14.03 14.61 14.0* 26.97 14.61Gol/yr TOTAL 16.06 16.06 1.98 14.61 16.06 1.93 25.97 1.96 14.61

ECON. Build Up /OacelCIF/Production 16.96 19.25 17.10 20.90 17.10 17.10 16.98 20.90Terminal/Rofining 16.96 5.96 2.34 12.46 5.90 2.t4Tranamisalon/Whoy I-ele 8.86 14.60 2.84 8.46 14.60 2.84Distribution/Retail 12.94 12.94 12.78 12.94 12.76 104.9JSUBTOTAL Cuut. Gats 29.90 54.52 50.44 26.66 45.93 50.44 19.70 121.69 25.69

ANNUAL EQUIP. COSTS 3/yrCooking appliances 8/yr 82.64 82.64 86.91 82.64 86.91 82.64

X coat 187.74 187.74 164.62 187.74 154.62 187.74K lfe 8 8 6 8 6 a

Hosting appliances 9/yr 152.66 152.69 165.86 152.63 131.89 165.86K cost 626.45 626.45 626.45 626.46 454.55 626.45K lfe 1s 1S 10 1S 6 10

IniCut Pipe *te. */yr 186.61 18.61 186.61 105.56K coat 896.69 696.69 696.69 692.96K lfe 20 20 20 20

SUBTOTAL Cone. Equip 8/yr 822.18 82218 86.91 165.86 822.18 86.91 181.69 186.41 165.86

ECONOMIC COMPARISONTOTAL 5/Ocal 49.96 74.56 69.03 86.27 66.08 69.03 24.76 191.79 66.27TOTAL J/yr 602.26 1197.76 695.61 LPGDO 1060.51 760.27 <-LPu ool 986.76 NOAdleoal

COMPETING FUEL VRS NAT. GAS - iREAKEVEN ECON. COSTS */OcalC.Gaol LPuaDO C..aa2 LPOaCooIB NG&dlesel dioel

System Inveotmant 57.62 26.87 49.07 81.62 a/ 22.74Invest. To Cons. Gate 87.56 6.81 29.02 11.57 9.70Invest. To City Gate 24.68 -6.68 16.03 -1.87 9.70

Netback Voluo at Consumer Gate 54.52 28.27 45.96 26.58 26.66--------------------------------------------------------------------------------------------------------------

91 92 #4 #4 #P toFINANCIAL COiPARISON N. Gas C. Ganl LPG 6Oleeel C.Gaa2 LPO A Coal N. Gas Wlesel

LPG/Nap.

Unit Costs S/Oval (Cooking) 45.19 45.19 67.16 46.6e 57.16 46.19Unit Costa S/Ocal (Heating) 38.52 88.52 82.28 46.50 19.7 82.28ANNUAL EQUIP. COSTS 6/yrCooking appliances 3/yr 28.94 28.94 82.58 82.58 82.58 26.94

K coat 151.52 161.52 170.80 170.80 170.80 151.52K life 8 6 8 8 6 8

Heating appilancea 6/yr 120.68 120.66 159.86 120.68 121.68 169.98K cost 909.09 909.09 909.09 909.09 600.00 909.09K lilfe 1 1S 10 1S 6 10

InBOut Pipe etc. 8/yr 150.28 160.28 150.26 116.14K cost 966.86 986.J8 996.80 762.27K life 20 20 20 20

SUBTOTAL Cons. Equip S/yr 800.10 800.10 82.58 159.66 808.69 82.68 121.68 145.03 119.09

TOTAL 6/yr 981.91 981.91 776.44 LPUOO 1,051.87 779.00 LPG&CoolB 965.28 NGAdleal------------------------------------------------------------- __--------------__-----------------_-------------

- 109 - Page 15 of 29

TABLE 4

SECTOR: SPACE HEATING - APARTMENT(New 800 Unit Apartment Building)(assums gas Is used for cooking In any case)

#1 #2 #8 t4N. Gas N. Gas Diesel Bunk. CIndlv. Central Indiv. Centralheating heating heating heoting

unit m^B m^8 liter literkoal/unit LHV 11,000 11,000 6,720 9,400end-use efficiency (#) Oa 8s 80 80caol/yr (10^6 kcal/yr) 9.a4 9.84 9.89 9.89

ECON. Build Up I/GcalCIF/P.oduction 16.90 16.96 20.9 18.00Terminal/Refining 2.84 2.06Transmission/Whoesale 2.84 2.20

letribution/Retail 6.20 6.20SUBTOTAL Cons. Gate 28.16 28.16 26.56 17.26

Appliance/Equip. S/GOal 12.27 14.56 18.28 16.19K cost 819.88 786.60 578.56 699.28K life 1s 15 10 10

InhOut Pipe etc. S/oal 0.42 1.12K cost 26.08 69.44K life 20 20

SUBTOTAL Customer 12.89 15.69 16.19

ECONOMICTOTAL S/GOcal 86.85 88.85 88.66 88.45TOTAL 8/yr 884.71 882.74 876.42 824.01

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS 5/GoalSystem Investment 23.86 17.76Invost. To Cust. Gate 10.67 6.06Invost. To City Gate 4.47 -1.15

Netback at Consumer GOte (vs #1) 27.68 22.02

N. Gas N. Gas Olisel Bunk. CFINANCIAL COMPARISON Indiv. Central Indiv. Central

Cons. Cato S/Geal a8.62 88.62 28.97 15.48

Appliance/Equip. 9.71 11.64 11.46 18.97K cost 681.82 810.28 680.91 769.16K life 16 15 10 10

InhOut Pipe etc. 0.80 0.78K cost 28.64 75.29K life 20 20

TOTAL S/Gcal 48.68 50.84 40.48 29.45TOTAL 8/yr 465.05 474.66 891.57 285.26

_ _ _ I -- --_-- --- -- --- --- -- --- -- --- -- --- --

A 6

- 110 - Page 16 of 29

TABLE 6

SECTOR: SPACE HEATING - APARTMENT(Existing 600 Unit Apartment Building)(Assumes gea- would be used for cooking In any ease)

------------------------------------------------------------------- __------

-- …---- rtrofit cases------#1 #2& *2b #8a #bBC to BC to SC toN. Gas N. OGe N. C.e Bunk. C Bunk. CIndiv. Central Central Central Central

unit M's a m8^ liter literkcel/unit LUV 11,000 lL,OOe 11,000 9,400 9,400end-use efficlency (X) 88 e8 88 80 bwOOcal/yr (10^6 kcal/yr) 9.84 9.84 9.84 9.69 9.89

ECON. Build Up S/OealCIF/Production 16.96 16.96 16.96 18.00 18.00Terminal/Refining 2.06 2.06TransmissIon/Wholesale 2.20 2.20Dlstrlbution/Retall 6.20 6.20 6.20SUBTOTAL Cons. Gate 28.16 28.16 28.16 17.26 17.26

ApplIance/Equip. 5/Ocal 16.76 16.36 2.91 16.19 1.62K cost 797.62 776.80 146.99 699.28 69.92K life 15 15 16 10 10

In&Out Pipe etc. 3/GOal 0.42 1.48 1.48K cost 26.03 87.98 87.98K life 20 20 20

SUBTOTAL Customer 16.21 16.80 4.84 l6.19 1.62

ECONOMICTOTAL 3/Ocal 89.87 89.96 27.60 88.45 18.88TOTAL S/yr 867.64 878.06 26e.79 824.01 182.87

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS S/OcalSystem Investment 17.76 2.68Invest. To Cust. aOte 1.64 -18.68Invest. To City Gate -4.68 -19.78

Netback Volue at Consumer Gate*8a and p8b vs #i 18.50 8.888 vo #2o and *Sb vs #2b 17.91 16.24

N. Gas N. Gas N. OGs Bunk. C Bunk. CFINANCIAL COMPARISON Indiv. Central Centrol Central Central

Cons. Gate S/Ocal 88.62 88.62 88.62 16.48 16.48

Appliance/Equip. 12.49 12.16 2.80 18.97 1.40K cost 877.27 868.98 161.69 769.16 78.92K life 1S 16 16 10 10

InlOut Pipe etc. 0.80 1.01 1.01K cost 28.64 96.72 98.72K life 20 20 20

FINANCIALTOTAL S/Goal 61.81 61.69 41.88 29.46 16.88TOTAL 8/yr 479.04 482.66 890.61 286.26 168.60

NOTES:Cases 2. and So assume that the salvage value of existing equipmntIs 100t of the value of new equipment.

Cases 2b and 8b assume that the salvage value of existing equipmentIs only 10X of the value of new equipment.

Page 17 of 29- 111 -

TABLE 6

SECTOR: COMMERCIAL - SPACE HEATING(1,000 pyong or 38,00 sq. mteros)

91 #2 #8 #4 56 9N. Qee C. Gas Dieel LPQ Bunk. C C. G4oa

LUP/Nap. (prop)unit Ma' m^8 ItTr kg liter akccl/unlt LH 11,000 11o,000 8,720 11,000 9,400 15,000end off (1) 88 8s 88 88 70 8sGcal/yr (10^8 kcel/yr) 228.88 228.88 228.86 228.s8 271.86 228.8

ECON. Build Up 5/acelCIF/Production 16.96 19.25 20.90 17.10 18.00 17.10Terminal/Refining 18.96 2.84 6.96 2.06 12.48Transmission/Whol esale 8.88 2.84 14.60 2.20 8.46Distribution/RetaIl 5.99 6.99 6.99SUBTOTAL Cons. Get* 22.96 47.58 25.65 87.66 17.26 89.08

Appliance/Equip. /Ocal 20.01 20.01 24.80 20.08 20.49 20.01K cost ('000 5) 24.79 24.79 24.79 24.81 24.79 24.79K life 15 15 1o 1s 10 1S

InlOut Pipe etc. */Gcal 16.28 16.23 15.28K cost ('000 *) 22.96 22.96 22.95K life 20 20 20

SUBTOTAL Customer 85.29 86.29 24.80 20.08 20.49 85.29

ECONOMICTOTAL S/GOcal 68.24 82.87 49.88 57.69 87.75 74.32TOTAL 8/yr 18,880 18,965 11,415 18,202 10,245 17,010

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS S/BcnlSystem Investment 65.91 82.92 40.78 27.80 67.86Invest. To Cons. Cate 80.62 -2.87 5.44 -7.49 22.07Invest. To City Gate 24.68 -8.87 -0.56 -18.48 16.08

Notbeck Value *t Consumer Gate 47.58 14.59 22.40 9.47 89.08

N. Gas C. Gas Diesel LPG Bunk. C C. Gas2FINANCIAL COMPARISONCons. Gate S/Ocal 88.62 89.62 28.97 48.68 16.48 48.44

Appliance/Equip. 15.85 15.85 20.96 26.78 17.68 15.85K coat ('000 S) 27.27 27.27 27.27 46.06 27.27 27.27K Ilfe 15 1s 10 1S 10 1s

InlOut Pipe etc. 10.72 10.72 10.72K cost ('000 8) 26.25 25.25 25.26K liTf 20 20 20

FINANCIALTOTAL S/Gcal 65.08 65.08 49.92 70.44 88.16 70.01TOTAL S/yr 14,896 14,896 11,425 16,121 8,999 16,022

-- -- -- -- -- -- -- -- -- -- -- -- -- -- -- - --- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- - --- -- -- -- -- -- ---

Page 18 of 29

- 112 -

TABLE 7

SECTOR: COMMERCIAL - SPACE HEATING(12,000 pyong or a9,600 sq. meters)

91 92 98 #4 96 f8N. Gao C. Gon Dilsel LPO Bunk. C C. Oas2

LPG/Nap. (Propane)unit M8 m',^ liter kg liter M^3kcal/unit LHV 11,000 11,000 8,720 11,000 9 '?0 1G,000end *ff. (X) e6 88 68 es 10 8aOcal/yt (10^8 kcul/yr) 2,746 2,746 2,746 2,748 8,266 2,746

ECON. Build Up 3/OcalCIF/Production 16.96 19.26 20.90 17.10 18.00 17.10T*rminal/Refining 18.96 2.84 5.96 2.06 12.48Transmisaion/Wholesalo 8.88 2.84 14.60 2.20 8.46Dstrilbution/Rtnail 0.88 0.88 0.88SUBTOTAL Cone. Gate 17.79 42.42 26.58 87.66 17.26 38.87

Appliance/Equip. */Gcnl 6.02 6.02 7.81 8.02 6.17 6.02K co-t 69,682 89,682 89,682 89,549 89,652 69,652K liY- 15 15 1o 15 10 15

InAOut Pipe etc. 3/Oal 4.24 4.24 4.24K cost 76,446 76,446 76,446K life 20 20 20

SUBTOTAL Customer 10.26 10.26 7.31 6.02 6.17 10.26

ECONOMICTOTAL 3/Ocal 26.06 52.66 82.89 48.66 28.48 44.14TOTAL 8/yr 77,049 144,678 90,880 119,966 76,284 121,209

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS 8/GcelSystem Inveetment 85.72 16.98 26.72 10.82 27.18Invest. To Cons. Ost. 26.48 5.67 16.46 0.55 16.91Invest. To City Gate 24.68 4.64 16.68 -0.28 16.08

Netback Value at Consumer Gate 42.42 22.68 a8.42 17.61 88.87

N. Gao C. 0s. Diesel LPu Bunk. C C. Oaa2FINANCIAL COMPARISONCons. Gate S/Oal a8.62 88.62 28.97 48.66 15.16 87.76

Appliance/Equip. 4.77 4.77 8.81 4.77 5.82 4.77K cost 96,486 98,4865 96,465 96,604 98,486 99,496K lfe 1s 15 10 15 10 16

InAOut Pipe etc. 2.98 2.96 2.98K cost 84,091 84,091 64,091K life 20 20 20

FINANCIALTOTAL 3/Ocal 46.26 46.26 85.27 48.45 20.48 45.62TOTAL 3/yr 127,048 127,046 96,866 188,061 66,669 125,016

Page 19 of 29

- 113 -

TABLE 8

SECTOR: HOTEL - SPACE HEATING(12,000 pyong or 89,600 *q. meters)

*1 *2 *8 #4 #6N. Gas C. Gas Diesel LPG Bunk. C C. G,s2

LPG/Nap. (propane)unit Ms m's liter kg liter ma -

kcal/unit WHV 11,000 11,000 8,720 11,000 9,400 16,000end off. (%) 88 8a 8a ea 70 8sOcal/yr (1O'$ kcal/yr) 22,984 22,984 22,984 22,984 27,198 22,984

ECON. Build Up S/GcalCIF/Productton 16.96 19.25 20.90 17.10 18.00 17.10Terminal/Refining 18.96 2.84 5.96 2.06 12.46Trensumssion/Wholessel 8.88 2.84 14.60 2.20 8.48Distribution/Retail 0.10 0.10 0.10SUBTOTAL Cons. Got S/Ocal 17.06 41.69 25.68 37.68 17.28 88.14

Appliance/Equip. S/Gcal 0.72 0.72 0.88 0.72 0.74 0.72K cost 69,582 89,652 89,532 89,549 89,682 89,652K life 1s 1s 1o 16 10 1s

InkOut Pipe etc. 8/oal 0.61 0.61 0.51K cost 76,448 76,446 76,446K itfe 20 20 20

SUBTOTAL Customer 1.28 1.28 0.88 0.72 0.74 1.28

ECONOMICTOTAL 8/Ocal 18.29 42.91 28.46 38.a8 18.00 84.87TOTAL S/yr 419,428 984,192 606,725 880,226 489,429 788,201

COMPETING FUEL VRS NAT. OAS - BREAKEVEN ECON. COSTS S/calSystem Investmente 25.96 9.50 21.42 4.38 17.41Invest. To Cons. Gats 24.78 8.27 20.19 8.15 16.18Invost. To City Gste 24.68 8.17 20.09 8.05 18.08

Netback Value *t Consumer Gate 41.69 25.28 87.15 20.1'1 8.14

N. Gas C. Gas Diesel LPG Bunk. C C. Gas2FINANCIAL COMPARISONCons. Gats 3/Ocal 88.52 88.62 28.97 48.68 16.16 87.78

Appliance/Equip. 0.67 O.5 0.76 0.67 0 .4 0.67K cost 98,486 98,486 98,485 98,604 99,486 98,485K life 1S 1s 10 15 1o 1s

InSOut Pipe etc. 0.86 0.86 0.86K cost 84,091 84,091 84,091K litf 20 20 20

FINANCIALTOTAL S/Gcal 89.45 89.46 29.72 44.26 15.80 38.71TOTAL S/yr 904,681 904,681 681,597 1,014,819 429,595 887,651

;

A 6

- 114 - Page 20 of 29

TABLE 9

SECTOR: RESTAURANT COOKING(Average Consumption: 6 m8/hr)

#1 92 98 54 95N. soo C. U.. LPG Kerosene C. 0as2

Prop#Nsp (propane)unit M8 O'8 kg liter O'8kcal/unit LU4V 11,000 11,000 11,000 8,800 16,000end-use efficiency (X) 70 70 70 46 70Ocal/yr (10o6 kcal/yr) 80 80 so 47 30

ECON. Build Up */GOciCIF/Production 16.96 19.25 17.10 22.00 17.10Teruinal/Refining 16.96 5.96 2.46 12.49Transmission/Wholesale 8.86 14.60 2.74 8.46Distribution/R teil 15.16 15.18 12.78 2.60 15.10SUBTOTAL Cons. Gate 82.14 56.76 50.44 29.79 48.22

Appliance/Equip. 6/Ocal 8.51 8.51 8.66 2.97 8.61K cost 418 418 480 8oo 418K llf- 7 7 7 8 7

InhOut Pipe etc. S/Ocal 6.74 6.74 6.74K cost 1,881 1,881 1,881K llfo 20 20 20

SUBTOTAL Customer 10.25 10.25 8.66 2.97 10.26

ECONOVICTOTAL S/Ocal 42.89 67.01 54.10 82.76 69.47TOTAL 8/yr 1,276 2,019 1,629 1,684 1,761

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS /GocalSystem Investment 60.05 87.14 84.00 41.61Invest. To Cons. Gate 89.80 26.89 28.76 81.26Invest. To City Gate 24.68 11.71 8.67 16.08

Netback Volue at Consumr Gate 56.76 48.85 40.71 48.22

N. OGs C. Onn1 LG Kerosene C. Qae2FINANCIAL COMPARISONCons. Gate S/Goel 45.19 45.19 57.16 8.806 46.56

Appliance/Equip. 8.16 8.16 8.29 2.92 8.16K cost 455 466 478 8a0 466K life 7 7 7 8 7

InAout Pipe etc. 4.78 4.78 4.78K cost 1,464 1,464 1,464K llfo 20 20 20

FINANCIALTOTAL 8/Ocal 58.00 68.08 60.46 86.78 54.44TOTAEl 8/yr 1,599 1,598 1,820 1,728 1,689

I

6Page 21 of 29

- 115 -

TABLE 10

SECTOR: COMMERCIAL - HEATING A COOLING(Office Space of 8,000 pyong or 26,400 sq. meters)

#1 92 8 4N. Gas N. Gas DXisel Eunk. Cl&C iHl.¢C AeloecC 4&Si.C

unit, M' M's liter literkeal/unit UfV 11,000 11,000 69720 9,400end off. (MN 8e 68 80 80Gcal/yr (10 6 kcal/yr) 2,091 1,426 4,242 2,24210^8 kWh/yr 119 279 286 286Capacity (kW) 170 645 645 546

ECON. Bulid Up U/GoalCIF/Production 16.96 l.96 20.90 18.00Terminal/RefinIns 2.84 2.06Transmission/Who sal 2.84 2.20Distribution/Retail 1.09 1.60SUBTOTAL Cons. Gate 18.05 18.66 26.58 17.26

Appliance/Equip. S/Goal 81.60 46.76 81.36 81.85K cost 857,696 841,661 860,946 860,945K life 1S 15 15 15

InhOut Pipe etc. I/Gcal 2.61 8.88K cost 85,813 85,818K life 20 20

SUBTOTAL Customer 84.21 60.65 81.86 81.86

ECONOMICTOTAL 3/Ocal 62.26 69.15 6s.98 48.61TOTAL Elec. Rev. 8/yr 24,846 67,858 6,547 6t8,647TOTAL I/yr 188,662 166,466 196,190 177,640

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS I/Go.lSystem Investment 62.65 76.87 67.96Invest. To Cons. Gate 28.44 42.66 88.78Invest. To City Oate 27.85 41.56 82.64

Netback Value at Consumer Gate 45.40 59.62 50.69

N. aOs C. Gas Dlesel Bunk. CFINANCIAL COMPARISONCons. Oate 8/Ocal 88.62 88.52 28.97 16.16

Appliance/Equip. 25.02 87.02 25.81 25.81K cost a98,4e6 897,089 897,089 897,089K life 15 15 1S 15

InlOut Pipe etc. 1.88 2.68K cost 89,894 89,894K iife 20 20

FINANCIALTOTAL 1/Ocal 66.87 78.22 64.28 40.46TOTAL Elec. Rev. 8/yr 24,846 67,858 68,647 68,547TOTAL 8/yr 161,082 179,410 190,267 159,806

------------------------------------------------------------- __

6

- 116 -. Page 22 of 29

TABLE 11

SECTOR: COkMERCIAL - HEATING A COOLING(Hotel of 6,000 pyong or 20,400 sq. meters)

#1 92 #8 #4N. as* M. Gon Olos,l Bunk. C

MaC H&leicC 4NA.eCC H&.iecCunit m^8 m,3 liter literkecl/unit LNV 11,000 11,000 8,720 9,400erd eff. (X) 88 8s 80 soGcal/yr (10^6 ke.l/yr) 9,844 7,617 11,970 11,97610^8 kWh/yr 659 1,812 1,844 1,844Capacity (kW) 170 546 645 645

ECON. Build Up 3/GoalCIF/Production 16.96 16.96 20.90 18.00Terminal/Refining 2.84 2.06Transmission/Wholesale 2.84 2.2001stribution/RitalI 0.28 0.80SUBTOTAL Cons. Gate 17.19 17.26 25.56 17.26

Applionea/Equip. 3/Gcal 6.06 10.61 7.04 6.69K cost 429,286 400,908 488,184 488,184K life 16 15 15 15

InAut Pipe etc. I/Goal 0.66 0.72K cost 85,818 86,818K lilf 20 20

SUBTOTAL Customer 6.61 11.22 7.04 6.68

ECONOMICTOTAL I/Geal 25.80 28.49 82.62 28.94TOTAL Elec. Rev. 8/yr 68,256 170,841 174,084 174,084TOTAL 8/yr 822,247 387,762 564,779 460,s80

COMPETING FUEL VRS NAT. GAS - BREAKEVEN E;ON. COSTS 3/GcelSystm Invostment 22.48 40.41 29.86Invest. To Cons. Gate 18.62 81.80 21.24Invest. To City Gate 18.69 81.57 21.01

Netback Value at Consumer Gate 80.78 48.76 a8.20

N. Gas C. Gas Diesel Bunk. CFINANCIAL COMPARISONCons. Gate 3/Ocal 88.62 a8.62 28.97 16.16

Appllance/Equlp. 6.86 8.82 5.69 5.69K cost 472,168 476,447 476,447 476;447K life 1s 15 1s 15

InlOut Pipe etc. 0.89 0.60K cost 89,194 89,894K life 20 20

FINANCiALTOTAL 3/Gcal 45.28 47.84 84.65 20.86TOTAL Else. Rev. S/yr 68,260 170,841 174,084 174,084TOTAL 8/yr 614,081 581,406 689,084 428,769

6Page 23 of 29

- 117 -

TABLE 12(a)

SECTOR: COMMERCIAL - COGENERATION OF HEAT AND ELECTRICITYEconomic Analysis

HMeting Only Cogenerstion

N. Gon C- Ga1 L1fht Bunk-rC D-e l N. Gao0 1

unit ma ^8 iter liter lit r *^akoal/unIt LHV 11,000 7,000 9,200 9,900 9,200 1l,000thermal efficiency ( 85 8S go 75 54 4cogen. *l-c ffie.(3) 26 20Fuel Use - Ocal/yr 8,629 8,620 8,760 4,000 6,656 5,656Cogen. MWh Prod./yr 1,680 1,680Cogen Sizo - kW (see note) 479 479

ECONOMIC - B/Goal of fuel useCIF/Production 16.96 19.26 20.90 12.94 20.90 16.96Terulnel/Refining 18.98 2.84 2.06 2.84Transmiseion/Wholesale 8.89 2.84 2.20 2.84Distribution/Retil 1.87 1.87 1.67SUBTOTAL Fuel et Cust. Gate 18.98 48.48 25.58 17.20 25.69 18.88

End Use Equlp. - I/Ocal 1.79 1.79 2.02 2.06 16.80 16.80IC cost - 84,247 94,247 41,096 44,521 479,884 479,834unit K - */Meol 40 40 48 52unit K - $/kW 1,000 1,000K life 1S 15 15 15 15 1508M (% of K cost) 8o 8% 8% 8x 4% 43

TOTAL - S/Ocal of fuel used 20.62 45.27 27.60 10.26 42.86 85.68TOTAL (0008/yr) 78 160 104 77 286 19#

Implicit cost of elec gon USc./kWh) 7.86 5.62Cosgnration Elec. Credit (3/Gol) -80.28 -80.28UnIt Cott after Cogen. Credit (6/Qcal) 12.15 5.40

TOTAL (COOOS/yr) 78 160 104 77 07 80

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS 8/Ocol

System Investment 28.86 18.24 8.47 25.42Investment To Consumer Gate 26.28 16.10 10.88 8.62Investment To City Gate 28.86 18.24 8.47 6.75

Notbick Value at Consumer Gate 42.19 82.06 27.29 26.58

SENSITIVITY OF TOTAL OOOS/YR TO ALTERNATIVE GRID ELECTRICITY PRICES_____________________________________________________________________________________________

ELEC HNsting Only CogenorationPRICE - - - - - - - - - - - - - - - - - - - - - - - - - - -(oIff Pk N. Gas C. Goa L t BunkerC iesel N Gas(USe. /kh) OLId

0.06 78 16O 104 77 lal 9a0.08 78 160 104 77 98 610.10 78 to6 104 77 6s so0.12 78 160 104 77 a8 0

Note: Cogeneration equipment In sized to m"t peak thormal demand.

Assumptions: Thermal demand 8,000 OOcl/yrPeak dmand: 856 Neal/hrElectricity demand 2,000 mWh/yr

6Page 24 of 29

- 118 -

TABLE 12(b)

SECTOR: COMMERCIAL - COGENERATION OF HEAT AND ELECTRICITY

Financial Comparison

Heating Only Cogeneratlon

N. a. C. 6 Ubht BunkerC diesel N. ag

unit M's M'8 liter liter littr es8keel/unit LHV 11,000 7,000 9,200 9,900 9,200 11,000thermal end off. (3) s6x esx 0ox 76%X 54 64Xcogen. else. off . ()26% 26XFuel Us, - Ocal/yr 3,629 8,629 8,750 4,000 5,556 6,556Cogan. MWh Prod./yr 1,680 1,680Cogen Sizo - kW 479 479

FINANCIAL - 3/Gc I of fuel useFuel et Cons. Gate 8t:.62 88.62 28.00 15.16 28.00 88.52

End-Use Equipment 1.29 1.29 1.48 1.48 12.88 12.88K cost - 8 84,247 84,247 41,096 44,521 479,84 479,884unit K - 8/Mcal 40 40 48 62unit K - 2/kW 1000 1000K life 15 16 16 15 15 16OAM (X of K cost) as ax ax ax 4% 4X

TOTAL - 8/Ocal of fuel used 89.81 89.81 29.48 16.64 40.88 50.86TOTAL 0001/yr 141 141 110 67 224 298

Marginal Cost of Electricity Goneration (USc./kWh) 6.76 8.46Cogen. Elsc. Credit (I/Oal) -80.28 -80.28Unit Cost after Cogen. CrEdlt (3/Ocal) 10.10 20.62TOTAL '0008/yr 141 141 110 67 S5 lS

SENSITIVITY OF TOTAL '00O0/YR TO VARYINO ELEC. PRICE

H eting Only Cogeneration

PRICE N. Gaos C. Ga1 Litht OunkerC diesel N. Gas(USc./ke'h) Oil

0.06 141 141 110 67 128 1820.08 141 141 110 67 90 1480.10 141 141 110 67 6e 11s0.12 141 141 110 67 28 8l0.16 141 141 110 67 (28) 81

Page 25 of 29

- 119 -

TABLE 18

SECTOR: INDUSTRIAL PROCESS NEATTEXTILES INDUSTRY(Average Consumption: 16,000 m^3/mo)

#1 #2 #P 4 6 p #7N. ass C. G.s Diesel Diesl1 LPG LPG C. Gas2

LPG/Nap. (New) (retro) (New) (retro) (propane)unit m's rna l1ter liter kg kg m^akeel/unit LHV 11,000 11,000 8,720 8,720 11,000 11,000 16,000end-usn efficiency (X) 80 80 80 80 80 80 80Qcal/yr (10^8 kcsl/yr) 1,980 1,980 1,980 1,980 1,980 1,960 1,98

ECON. Build Up */GcalCIF/Production 18.98 19.26 20.90 20.90 17.10 17.10 17.10Terminal/Refining 18.98 2.84 2.84 5.96 6.96 12.48Transmission/Wholesale 8.8s 0.98 0.98 8.46 8.48 8.46Distribution/Retail 8.46 8.46 8.46SUBTOTAL Cons. Gate 20.42 46.07 24.17 24.17 26.52 26.62 86.50

AppliTnce/Equip. 3/cal 1.19 1.19 1.26 0.12 1.19 0.12 1.19K cost 11,019 11,019 11,019 1,102 11,019 1,102 11,019K life 10 10 10 10 10 10 10

.n&Out Pipe etc. 3/ocal 0.96 0.85 0.86K cost 11,019 11,019 11,019K life 20 20 20

SUBTOTAL Customer 2.04 2.04 1.25 0.12 1.19 0.12 2.04

ECONOMICTOTAL 8/Ocal 22.46 47.11 26.42 24.29 27.71 26.64 88.64TOTAL */yr 44,477 98,276 50,826 48,101 64,864 52,789 76,815

COMPETING FUEL VRS NAT. GAS - BREAKEVEN ECON. COSTS S/Cc.lSystem Investment 80.15 8.40 7.as i0.76 9.68 21.6Invest. To Cons. Oate 28.11 6.42 5.29 8.71 7.04 19.64Invest. To City Gate 24.65 2.95 1.88 5.26 4.17 16.08

Netback Value at Consumer G.te 45.07 28.88 22.25 25.67 24.80 86.60

N. Gas C. Gas Diesel Diesel LPG LPG C. Gas2FINANCIAL COMPARISON (new) (retro) (new) (retro)Cons. Gate 6/Ocal 88.52 a8.62 27.41 27.41 29.01 ".01 87.78

Appliance/Equip. 1.02 1.02 1.08 0.11 1.02 0.10 1.02K cost 12,121 12,121 12,121 1,212 12,121 1,212 12,121K IfTe 10 10 10 10 10 10 10

In&Out Pipe ete. 0.69 0.69 0.59K cost 12,121 12,121 12,121K life 20 20 20

FINANCIALTOTAL 3/Ocal 40.18 40.18 28.48 27.52 80.08 29.11 89.89TOTAL 8/yr 79,456 79,456 56,400 54,482 59,465 67,640 77,989

Annex 6Page 26 of 29

- 120 -

TABLE 14

SECTOR: INDUSTRIAL PROCESS HEATMETAL INDUSTRY(Average Consumption: 50,000 m'S/Mo)

#1 #2 #3 #4 #8 #6 #7N. Oas C. aos Diesel Diesel LPO UPO C. Gae2

LPG/Nap. (New) (retro) (New) (retro) (propsno)unit M's m's liter liter kg kg u'8keel/unit LHV 11,000 11,000 8,720 8,720 11,000 11,000 16,000ord-uso efficioncy (1) so 80 60 so 90 90 s0Ccat/yr (1O'e kcal/yr) 6,600 6,600 6,600 6,600 6,6oo 6,600 6,600

ECON. Build Up 8/OcalCIF/Production 16.96 19.25 20.90 20.90 17.10 17.10 17.10Terminal/Refninng 19.98 2.84 2.84 6.96 6.96 12.46Transmission/Wholesale 8.88 0.98 0.93 8.46 8.46 3.46Distribution/Retail 1.04 1.04 1.04SUBTOTAL Cons. GCte 16.00 42.64 24.17 24.17 26.62 26.62 34.06

Appliance/Equip. 8/Ocal 0.89 0.89 0.94 0.09 0.89 0.09 0.89K cost 27,648 27,548 27,649 2,766 27,648 2,765 27,648K life 10 10 10 10 10 10 10

ln&Out Pipe etc. 8/Ocal 1.76 1.75 1.75K cost 75,759 75,769 76,768K life 20 20 20

SUBTOTAL Customer 2.64 2.64 0.94 0.09 0.89 0.09 2.64

ECONOMICTOTAL S/Ocal 20.64 46.29 25.10 24.26 27.41 26.61 86.72TOTAL S/yr 186,287 298,901 165,690 160,129 180,912 176,699 242,86

CuMPETING FUEL VRS NAI. GAS - BREAVEvIN ECON. COTs SuiicalSystem Investment 28.88 8.14 7.80 10.46 9.65 19.76Invest. To Cons. Cote 25.68 6.60 4.66 7.81 7.00 17.12Invest. To City oate 24.65 4.48 8.62 6.77 6.96 16.09

Notback Value at Consumer Gete 42.64 22.46 21.62 24.77 28.98 84.08

N. OGs C. Gas Diesel Diesel U2O LPG C. Q0a2-INANCIAL COMPARISON (new) (retro) (new) (retro)Cons. Gate 8/Ocal a8.62 88.52 27.41 27.41 29.01 29.01 87.78

Appliance/Equip. 0.76 0.76 0.81 0.06 0.76 0.08 0.76K cost 80,808 80,808 80,808 8,080 80,808 8,030 80,808K life 10 10 10 10 10 10 10

InAOut Pipe etc. 1.28 1.28 1.28K cost 88,888 98,888 98,888K life 20 20 20

FINANCIALTOTAL 8/Ocal 40.51 40.51 29.22 27.49 29.77 29.09 89.77TOTAL S/yr 267,846 287,846 198,224 181,427 196,509 191,984 282,469

i

Annex 6Page 27 of 29

- 121 -

TABLE 16

SECTOR: INDUSTRIAL PROCESS HEATFOOD PROCESSING INDUSTRY(Average Consumption: 70,000 m8/mo)

91 #2 98 94 #5 96 7N. Oas C. Gas Diesel Diesel 1LP LP2 C. Os92

LP0/Nap. (Now) (rotro) (New) (retro) (propano)unit m^8 m'8 liter liter kg kg m'8kcsl/unit LNV 11,000 11,000 8,720 8,720 11,000 11,000 15,000end-use efficiency (N) 80 80 60 60 80 80 80Gcal/yr (10^6 kcal/yr) 9,240 9,240 9,240 9,240 9,240 9,240 9,240

ECON. Build Up S/OcalCIF/Production 16.96 19.26 20.90 20.90 17.10 17.10 11.10Terminal/Refining 18.98 2.84 2.84 6.98 5.96 12.48Transmission/Wholesale 8.86 0.98 0.98 8.46 8.46 8.46Distribution/Retail 0.74 0.74 0.74SUBTOTAL Cons. Oate 17.70 42.85 24.17 24.17 26.52 26.52 88.78

Appliance/Equip. 6/Ocal 0.60 0.80 0.64 0.08 0.80 0.08 0.80K cnst 84,486 84,486 84,486 8,444 a4,486 8,444 84,485K life 10 10 10 1O 10 10 10

InAut Pipe etc. 6/Ocal 1.86 1.86 1.a8K cost 62,e46 82,645 82,645K life 20 20 20

SUBTOTAL Customer 2.16 2.16 0.64 0.06 0.80 0.08 2.16

ECONOMICTOTAL I/Ocal 19.86 44.51 25.00 24.26 27.82 26.60 86.94TOTAL S/yr 168,687 411,266 281,089 224,086 262,891 246,750 882,116

COMPETING FJEL YRS MAT. GAS - BREARKEVE4 ECON. COSTS 1/ocalSystem Investment 27.66 6.04 7.29 10.86 9.64 16.96Invest. To Cons. Gate 26.89 5.68 6.18 8.19 7.48 16.62Invest. To City Gate 24.66 5.14 4.89 7.45 6.78 16.08

Netback Value at Consumer Gate 42.86 22.84 22.09 26.15 24.44 s8.76

N. Gas C. Gas Diesel Diesel 120 12G C. ¢as2FINANCIAL COMPARISON (Now) (retro) (Now) (rotro)Cons. Gate 3/Ocal 88.52 86.52 27.41 27.41 29.01 29.01 87.76

Appliance/Equip. 0.68 0.68 0.72 0.07 0.66 0.07 0.66K cost 87,679 87,879 87,679 8,788 87,879 8,766 87,679K life 10 10 10 10 10 10 10

InhOut Pipe etc. o.96 0.96 0.9sK cost 90,909 90,909 90,909K life 20 20 20

FINANCIALTOTAL S/Gcal 40.16 40.16 26.18 27.46 29.69 29.08 89.41TOTAL 8/yr 871,026 871,026 259,914 268,916 274,867 266,703 864,165

6Page 28 of 29

- 122 -

TABLE 16

SECTOR: INDUSTRIAL PROCESS HEATELECTRONICS INDUSTRY(Average Consumption: 150,000 mOa/mo)

#1 #2 *8 #4 P P #7N. Gas C. a.s Dlesel Diesel LPG LPO C. a.*2

LPO/Nap. (Wew) (retro) (New) (retro) (propane)unit m^8 a'8 liter liter kg kg e^8keel/unit LHV 11,000 11,000 3,720 6,720 11,000 11,000 15,000end-use efficiency (N) 80 60 60 60 80 80 s0Gcal/yr (10^' kcal/yr) 19,600 19,600 19,600 19,600 19,800 19,600 19,600

ECON. Build Up 8/ocalCIF/Production 16.96 19.25 20.90 20.sC 17.10 17.10 17.10Terminal/Refining 10.96 2.84 2.84 5.96 5.96 12.43Transmission/Wholesale 3.86 0.08 0.98 2 '6 8.46 8.46Distribution/Retail 0.85 0.85 e 85SUBTOTAL Cons. Gate 17.81 41.95 24.17 24.17 26.52 26.52 88.89

Appliance/Equip. 6/cacl 2.16 2.16 2.27 2.27 2.16 2.16 2.16 S K cost ('000 8) 200 200 200 200 200 200 200K llfe 10 10 10 10 10 10 10

InaOut Pipe etc. 8/Ocal 1.80 1.80 1.60K cost ('000 6) 169 169 169K life 20 20 20

SUBTOTAL Customer 8.47 8.47 2.27 2.27 2.16 2.16 8.47

ECONOdAICTOTAL 1/Ocal 20.77 45.42 26.48 26.48 28.86 28.68 88.86TOTAL S/yr 411,884 969,825 628,892 528,892 567,684 6s7,984 729,718

COiPETING FUEL VRS ;AT. GAS - BREAMEVE: ECON. COSTS VocalSystem Invu-Amennt 28.46 9.47 9.47 il 72 11.72 19.19Invest. To Cons. Gate 24.99 6.01 6.01 8.26 8.26 16.48Invest. To City Gate 24.65 6.66 6.66 7.91 7.91 16.06

Notback Value at Consumer Gate 41.95 22.97 22.97 26.21 25.21 88.89

N. Gas C. Gas Dlesl Diesl LPG LPO C. 0as2FINANCIAL COMPARISON (New) (retro) (New) (retro)Cons. Gate 6/ocal 88.52 88.62 27.41 27.41 29.01 29.01 87.78

Appliance/Equip. 1.84 1.64 1.96 1.96 1.84 1.84 1.84K cost ('000 8) 220 220 220 220 220 220 220K life 10 10 10 10 10 10 10

IniOut Pipe etc. 0.91 0.91 0.91K cost ('000 8) 168 16e 186K life 20 20 20

FINANCIALTOTAL 2/Ocal 41.26 41.26 29.86 29.86 80.68 80.86 40.64TOTAL 8/yr 617,268 617,268 561,874 681,874 610,986 610,986 802,608

__________________________________________________________________________________________

Annex 6Page 29 of 29

- 123 -

TABLE 17

SECTOR: INDUSTRIAL PROCESS HEATOLASS INDUSTRY(Average Consumption: 660,000 m^8/mo)

#1 #2 P #4 #P #P#N. Gas C. Ono Diesel Diesl ILP LPG C. G0s2

ProplNop. (New) (retro) (Now) (retro) (propane)unit m^a ms liter lIter kg kg e8koal/unit LHV 11,000 11,000 8,720 8,720 11,000 11,000 16,000 L7ctd-use efficiency (1) 80 80 80 60 60 s0 80oal/yr (106 kc.l/yr) 86,800 86,800 85,800 85,800 65,s80 86,800 65,600

ECON. Bulid Up 8/OcalCIFjProduction 16.96 19.25 20.90 20.90 17.10 17.10 17.10Terminal/RefinIng 18.98 2.84 2.84 5.96 s.s6 12.46Transmiseion/Wholosalo 8.38 0.98 0.98 8.40 -0.46 8.40Distribution/Retail 0.08 0.08 0.08SUBTOTAL Cone. Gate 17.04 41.69 24.17 24.17 28.52 28.62 &8.12

Appliance/Equip. S/Oal 5.16 6.16 5.40 0.64 5.16 0.52 5.16K cost ('000 *) 2,066 2,066 2,066 207 2,066 207 2,066K life 10 10 10 10 10 10 10

InlOut Pipe etc. 8/Ocal 1.66 1.66 1.66K cost ('000 8) 987 987 987K life 20 20 20

SUBTOTAL Customr 6.82 6.82 5.40 0.64 6.16 0.52 6.62

ECONOMICTOTAL 8/Goal 28.66 48.61 29.57 24.71 81.66 27.0o8 9.94TOTAL 8/yr (8'000) 2,047 4,162 2,587 2,120 2,716 2,819 8,427

COMPETING FUEL VRS NAT. AS - BREAKEVEN ECON. COSTS */OcalSyst- Trwst 91.Z5 I.6 C .b : 4.72 10.07 22.98Invest. To Cone. Gate 24.78 5.79 0.98 7.89 8.26 16.16Invest. To City Gate 24.65 5.71 0.65 7.81 8.17 16.08

Netback Value at Consumer Gate 41.69 22.75 17.99 24.85 20.21 88.12

N. Ga* C. Gas Diesl Diesl LPG LPG C. 0Gs2FINANCIAL COMPARISON (new) (retro) (new) (retro)Cons. Gato 8/oeal 88.62 88.62 27.41 27.41 29.01 29.01 87.78

AppIlance/Equip. 4.89 4.89 4.66 0.47 4.89 0.44 4.89K cost ('000 8) 2,278 2,278 2,278 227 2,278 227 2,278K llf- 10 10 10 10 1O 10 10

InhOut Pipe etc. 1.17 1.17 1.17K cost ('000 8) 1,080 1,080 1,080K llfe 20 20 20

FINANCIALTOTAL S/oal 44.08 44.08 82.07 27.87 88.41 29.45 48.84TOTAL 8/yr (8 000) 8,782 8,782 2,761 2,892 2,866 2,627 8,716

- 124- Annex 7

KOREA

GAS UTILIZATION STUDY

Summary of End-Use Analysis at 8Z Cost of Capital($/GCal)

Netback Available Average AvailableAlternative Value Rent at Distribution Rent at

End-Use Fuel of Gas Cons. Gate Costs City Gate a/

Residential

CookingIndiv. Houses LPG 49 b/ 32 77 (45)Apartments LPG 49 32 21 10

Space HeatingIndiv. Houses Diesel 38 c/ 21 13 21Apartments HFO 22 5 5 0

Commercial

Space Heating HFO 14-19 (3)-2 4-1 (8)-1Heating&Cooling HPO&elec 51 34 1 34

HotelsSp. Heat. HFO 20 3 (0) 3Htg&Cool. HFO&elec. 38 21 (0) 21

R.cstaurantCooking LPG 46 29 11 18

Sp. Heat. w/Cogeneration HFO&elec. 30 13 1 12

Diesel 26 9 1 7

Industrial

Boiler Fuel HFO 20 3 0-3 0-3

Direct HeatNew Diesel 22-23 5-6 0-3 4-6

LPG 25-26 8-9 0-3 6-8

Retrofit Diesel 19-23 2-4 0-3 2-6LPG 21-25 4-8 0-3 4-8

a/ Assuming an average price of gas of $17/GCal (cif).b/ Based on lower estimate of willingness-to-pay in city gas networks.c/ Assumes gas is used both cooking and heating.

- 125 - Page .of 4

KOICA

AS UTILIZATION Smo

Nctback Vclue of Gas In Power Sector

A. Netback Velue of Gas in Csbined Coele Plant(Compared to conventional coal-fired *tam plant)

Table Al: Sluleation of OwFlied Cea6lage Cycle Float

Capcity i 600 First Mr 1968Load factor hrs/y 5i25 (66.54) Start-up yar 1992Comsption TI/kilW 7200 (47 4) Lifetim yatrs 19Gas CN STU/cft 1236 Start-. load 66%Monetary unit : US S Investment (mill.): 390 (1)

I llnvestment I Operat.l GAS I GAS I Fixed Variable I ELECTR. II Year I I Rate I Consumption I cost I Cost Cost IProductionl

I million S I hrs/y I Bcf/y lOcf/d Imillion SI million S I GWH/y I

1 1986 1 0.00 I C I 0.00 0.00 1 0.00 1 0.00 0.00 1 0 11 1987 1 0.001 0 1 0.00 0.0 1 0.00 1 0.00 0.00W 0

1988 1 0.00 1 0 1 0.00 0.00 1 0.00 1 0.00 0.00 1 0 11 1989 ! 97.50 1 0 1 0.00 0.00 i 0.00 1 0.00 0.00 I 0 1I 1990 1 156.00 1 0 1 0.00 0.03 I 0.00 I 0.00 0.00oo 0 o1 1991 1 136.50 1 3845 1 13.44 36.81 1 112.60 1 7.46 0.37 1 2307 11 1992 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 1993 1 0.00 I 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 1994 1 0.00 I 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 1995 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 1996 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 1997 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 1998 1 0.00 I 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 1I 1999 1 0.00 1 5025 1 20.36 55.78 1 170.61 1 11.31 0.56 I 3495 11 2000 1 0.00 1 5825 1 20.36 55.78 1 170.61 11.31 0.56 1 3495 11 2001 1 0.00 5 5825 1 20.36 55.78 1 170.61 11.31 0.56 1 3495 11 2002 1 0.00 1 5825 1 20.36 55.78 1 170.61 11.31 0.56 1 3495 11 2003 1 0.00 1 5825 1 20.36 55.78 1 170.F I 11.31 0.56 1 3495 11 2004 1 0.00 1 5825 1 20.36 55.78 1 170 1 11.31 0.56 1 3495 11 2005 I 0.00 1 5825 1 20.36 55.78 1 17C I I 11.31 0.56 1 3495 11 2006 5 0.005 5825 1 20.36 55.i8 1 l70Ajl i 11.31 0.56, 3495 I1 2007 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 2008 1 0.00 1 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 2009 1 0.00 5825 1 20.36 55.78 1 170.61 1 11.31 0.56 1 3495 11 2010 1 -39.00 1 5825 1 20.36 55.78 I 170.61 1 11.31 0.56 1 3495 1

ias price -treakeven gas price at 13% d.r. S/lBTU 6.8

1Discount rate I 0.00%1 8.00%1 11.00%1 13.00%1 14.00%1 16.00%1

lAverage fuel cost 1 4.88 1 4.88 1 4.88 1 4.88 1 4.88 1 4.88 1I cts/kWh I I I I I I IlAverage O.M.R. costl 0.34 1 0.34 1 0.34 1 0.34 1 0.34 1 0.34 1I cts/kWh I I I I I I IlAverage capital I 0.51 1 1.14 1 1.43 1 1.63 1 1.74 1 1.95 IIcost cts/kWh I I I I I I I

I I I- I I- … I lAverage electricityl 5.73 1 6.36 1 6.65 1 6.85 1 6.96 1 7.17 1Icost cts/kwh I I I I I I I

(1) Capital cost : 650 S/KW

Main assumptions

Construction schedule : Year -5 Year -4 Year -3 Year -2 Year -1

Comibined Cycle plant: 25 % 40% 35 %

Coal plant: 15 % 15 % 25 % 25 % 20 %

- The Combined Cycle plant is able to produce 2/3 of its nominal energy capacityduring the 3rd year of construction.

Lifetim 19 ars for Coeibned Cycle plant24 Mrs for Coal plant

-126 - Page !of 4

Table A2: SolmaItl*a Of COal-FIred Stasm Plast

capacity KW : 686 First year : 1986Load factor hrs/y 5095 (58.2%) Start-up year 199Coinsumption BTU/kWh Om98 (384) Lifetime years 24Coal LHlY BTU/kg : 2500 Start-up load 100%Monetary unit us S Investment (mill.): 754 (1)

I llnvestment I Operat.1 COAL. I COAL I COAL I Fixed Variable I ELECTR. II Year I I Rate IConsumpt.1 Price I Cost I Cost Cost IProductionlI- - - -I-- - -- - -I-- - - -I-- - ------------ I… - --… -I-- - - - -- - - - -I-- - -- - I

I I million S I hrsly 1000 Tons I S/Ton Imuillion SI millIion S I GWHi/y I

I 1986 1 0.00 I 0 1 0.00 I 0.00 I 0.00 I 0.00 0.00 I 0 11 1987 1 113.10 1 0 1 0.001I 0.001I U.00I 0.00 0.001I 01iI 1988 1 113.10 1 Dl 0001I 0.00 I 0.001I 0.00 0.00 I 0 11 1989 1 188.50 1 0 1 0.001I 0.001I 0.00 I 0.00 0.001 0 1 1990 1 188.50 1 0 I 0.001I 0.001I 0.00 I 0.00 0.001i 0 11 1991 1 150.80 1 0 1 0.00 I 0.001I 0.00 I 0.00 0.001I 0 1I 1992 I 0.00 I 5095 I 1255.4? I 51.09 1 64.14 1 34.68 5.10 1 3495 1I 1993 I 0.00 I 5036 I 1255.47 I 51.65 1 64.84 1 34.68 5.10 I 3495 II 1994 i 0.00 I 5095 I 1255.47 I 52.S4 1 65.95 1 34.68 5.10 1 3495 1I 1995 I 0.00 I 5095 I 1255.47 I 53.56 I 67.24 I 34.68 5.10 1 3495 II 1996 I 0.00 I 50951 11255.47 I 54.56 I 68.50 I 34.68 5.10 I 3495 II 1997 I r-.00 I 50951 11255.47 1 55.58 I 69.78 1 34.68 5.10 1 3495 II 1998 I 0.001I 50951 I1255.4? I i6.63 1 71.10 1 34.68 5.10 I 3495 II 19991I 0.00 I 5095 I 1255.47 1 57.50 I 72.19 1 34.68 5.10 1 3495 1I 2000 1 0.00 I 5095 I 1255.47 I 58.38 I 73.29 1 34.68 5.10 I 3495 1I 2001 I 0.00 I 5095 11255.47 I 58.69 I 73.68 1 34.68 5.10 1 3495 II 2002 1 0.00 I 5095 I 1255.47 I 59.00 I 74.07 I 34.68 5.IC I 3495 II 2003 I 0.00 I 5095 I 1255.47 I 59.00 1 74.07 I 34.68 5.10 I 3495 II 2004 i 0.00 I 5095 I 1255.47 I 59.00 I 74.07 I 34.68 5.10 1 3495 II 2005 I 0.00 I 5095 I 1255.47 I 59.00 I 74.07 I 34.68 5.10 I 3495 II 2006 I 0.00 I 5095 11255.47 I 59.00 I 74.07 I 34.68 5.10 I 3495 1I 2007 I 0.00 1 5095 I 1255.47 1 59.00 I 74.07 I 34.68 5.10 I 3495 II 2008 I 0.00 I 5095 I 1255.47 I 59.00 I 74.07 1 34.68 5.10 I 3495 II 2009 1 0.00 I 50951 I1255.47 I 59.00 1 74.07 I 34.68 5.10 I 3495 II 2010 I 0.00 1 50951 11255.47 I 59.00 1 74.07 I 34.68 5.10 I 3495 II 2011 I 0.00 i 5095 I 1255.47 1 59.00 I 74.07 1 34.68 5.10 I 3495 I1 2012 1 0.00 I 5095 I 1255.47 I 59.00 I 74.07 1 34.68 5.10 I 3495 II 2013 I 0.00 1 5095 I 1255.47 I 59.00 I 74.07 1 34.68 5.10 I 3495 II 2014 1 0.00 i 50951 11255.47 1 59.00 1 74.07 1 34.68 5.10'1 3495 1I 2015 I -75.40 I 5095 I 1255.47 I 59.00 I 74.07 I 34.68 5.10 I 3495 I

lOiscount rate I 0.0041 8.00,41 11.0041 13.0041 14.0041 16.0041

lAverage fuel cost I 2.06 I 2.01 I 2.00 1 1.99 I 1.98 I 1.97 II cts/kWIu I I I I I I I[Average O.M.R. costl 1.14 I 1.14 I 1.14 I 1.14 1 1.14 I 1.14 II cts/kItII I I IlAverage capital I 0.81 I 2.33 I 3.13 I 3.72 1 4.04 I 4.72 I[cost ctslkWh I I I I I I I-- - - - -- - - - -I-- -- -- I-- -- -- I-- - -- -I-- -- -- I-- - -- -I-- -- --[Average electricityl 4.01 1 5.49 1 6.26 1 6.85 1 7.17 I 7.84 IIcost cts/kWh I I I I I III-- - - - -- - - - -I-- -- --I-- - - - I-- - -- -I-- - - - I-- -- -- …-- -- -IGas netback value I I I I II

I USSIICF I 5.42 1 6.88 1 7.72 1 8.38 1 8.74 1 9.51 11 uSS/POIBTU I 4.38 1 5.S6 1 6.24 1 6.78 1 7.07 I 7.70 1I US$IGCal I 17.4 1 22.1 I 24.8 1 26.9 1 28.0 1 30.5 1

8REAI(OOVN OF NETBACK VALUE

IDiscount rate I 0.0041 8.0041 11.0041 13.0041 14.0041 16.0041

I Capital different.1 I I I I II US$/ MWBTU I 0.41 1 1.65 1 2.36 1 2.91 I 3.20 1 3.85 1I US$/ GCaI I 1.64 1 6.57 1 9.36 1 11.53 1 12.71 1 15.26 11 OMWRcost differentl I I I I I II US$/ 1148TU I 1.11 I 1.111I 1.11 I 1.11 I 1.11 I 1.111I

I ~ ~~I I I I I I II Fuel efficiency I I I I I I II diff. US$/ III8TU I 0.57 I 0.55 1 0.55 I 0.55 I 0.55 I 0.54 II Fuel I I I I I I II cost US$/ IIBTU I 2.29 1 2.24 1 2.23 1 2.21 I 2.21 I 2.20 1

…-------- -I …----I …----I …-----I …----I …-----I …-----Capital cost : 1100 S/KM including 100 $/KW for FGO

availability differential Is taken into account by setting:- 66.b 4 load factor for Comrbined Cycle plant with 600 NW to procuce 3495 GWN /yearj

- 58.2 % load factor for Coal plant with 608 MW to produce 3495 0Mb /year

Anex 8Page 3 of 4

B. Netback Value of Ga In Cenvaitlonel Steam Plant

Table lit Sl..1t1.m of aa0-UInd Ste4m1 PI Mt

Capacity U1 s First yew 191Lo tfactor a/y 4 () St?t-w yew 1992Consumption STU/lkVh 853 0 A(40) Lifetime yea: 19Gas LHV BTU/cft: 1236 Start-up load 70*Monetary unit us S Investwnt (mil1.): S10 (1)

I lInvestment I Operat.l GAS I GAS I Fixed Variable II Year I I Rate I Conswition I cost I Cost Cost Ii------- _ I------…- _____ I - ---.-- -- I…………I … … - I- ------ II I miI1ion $ I hrs/y I Bcf/y lcfd Imillion SI million S I

… I-------I----- -- - -----… … …---I--- ----- -------------1 1986 1 o.o I I1 1987 1 0.001 I 1 11 1988 1 51.001 I I II 1989 1 127.50 I I ' I 1990 1 178.50 1 1 ' ' II 1991 1 153.00 1 1 1 1 II 1992 I 0.00 1 3255 1 13.48 36.93 1 81.30 1 10.46 1.31 11 1993 1 0.00 I 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 11 1994 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 11 1995 I 0.00 i 4650 1 19.2S 52.75 1 116.14 1 10.46 1.31 1! 1996 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 11 1997 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 11 1998 1 0.00 1 4650 1 19.25 .52.75 1 116.14 1 10.46 1.31 11 1999 1 0.00 1 4650 ! 19.25 52.75 1 116.14 1 10.46 1.31 11 2000 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 11 2001 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 11 2002 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 11 2003 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 11 2004 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1

a I j6 i i.2 52.75 1 11C.: ! ^ !_-t I

1 2006 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 i1 2007 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 11 2008 1 0.00 1 4650 I 19.25 52.75 1 116.14 1 10.46 1.31 11 2009 1 0.00 1 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 11 2010 1 -51.00 I 4650 1 19.25 52.75 1 116.14 1 10.46 1.31 1

Gas price - breakeven price at 13* d.r. US$/MIITU 4.88

IDiscount rate I 0.00*1 8.00*1 11.00*1 13.00%1 14.00*1 16.00%1

lAverage fuel cost I 4.16 1 4.16 1 4.16 1 4.16 1 4.16 1 4.16 1I cts/kWh I I I I I I IlAverage O.M.R. costl 0.43 1 0.43 1 0.44 1 0.44 I 0.44 ' 0.44 'I cts/kWh I I I I I I IlAverage capital I 0.88 1 2.10 1 2.70 1 3.15 1 3.38 1 3.88 1Icost cts/kWh I I I I I I II _… … ___I--- - I - I- I _ …IlAverage electricityl 5.47 1 6.70 1 7.30 1 7.75 1 7.99 1 8.48 1Icost cts/kWh I I I I I I I

(1) Capital cost 850 I/KW

Page 4 of 4

Table St: S.Iletl.. of 0W -Flrd Stem PIe|

Capacity 1 Go First wr : 1Load fator hW/y : t (53S) Stat-. yr : t0Consumption BTU/kWh: 7SO () Lifatlu ts oFuel oil LHV 8TU/kg : 38900 Start-up usd : 70lMonetary unit US S Investment (mill.): 540 (1)

I Ilnvestment I Operat.1FUEL OIL IFUEL OIL IFUEL OIL a Fixed Variable II Year I I Rate IConsuwpt.1 Price I Cost I Cost Cost I

I I mil;ionS I hrs/y 1000 Tons I S/Ton Imillion Sl milltan S I

1 1986 1 0.00 1 I I I I I1 1987 1 0.001 1 1 11 1988 1 54.00 1 1 1 1 I1 1989 1 108.00 1 1 1 122.4 1 1I 1990 1 216.00 1 1 1 144.7 1 1 11 1991 1 162.00 1 1 1 147.5 1 1 11 1992 1 0.00 1 3255 1 439.30 1 150.3 1 66.03 1 11.61 i9 I1 1993 1 0.00 1 4650 1 627.57 1 153.2 1 96.14 1 11.61 4.69 11 1994 1 0.00 1 4650 1 627.57 1 156.2 1 98.03 1 11.61 4.69 11 1995 1 0.00 I 4650 i 627.57 1 160.9 1 100.98 1 11.61 4.69 11 1996 I 0.00 1 4650 1 627.57 1 165.9 1 104.11 1 11.61 4.69 11 1997 1 0.00 1 4650 1 627;57 1 171.! 1 107.3PJ I 11.l1 4.69 11 1998 1 0.00 1 4650 I 627.57 1 176.4 1 110.70 1 11.61 4.69 1I 1999 ' 0.00 1 4650 1 627.57 1 179.4 1 112.59 1 11.61 4.69 11 2000 1 0.00 1 4650 1 627.57 1 182.5 1 114.53 1 11.61 4.69 11 2001 1 0.00 1 4650 1 627.57 1 185.7 1 116.54 1 11.61 4.69 11 2002 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 11 2003 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 11 2004 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1I 2005 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 11 2006 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 11 2007 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 11 2008 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 11 2009 1 0.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 11 2010 1 -54.00 1 4650 1 627.57 1 188.9 1 118.55 1 11.61 4.69 1I------…-----------------------------------------------------------------Fuel oil price S:ton: 150.3 (in 1992) Price to KEPCO excludes wholesale margin

I1iscount rate I 0.001 8.00S1 11.00S1 13.0041 14.00S1 16.00S1-__I------- _I-------- _I-- -- -- _I--_- _I- -_I

lAverage fuel cost 1 4.01 1 3.90 1 3.85 1 3.83 1 3.82 1 3.79 1.1 cts/kwh I I I I I I IlAverage O.n.R. costl 0.59 1 0.60 I 0.60 I u.61 1 0.6O I U.bl II cts/kwh I I I I I I IlAverage capital 1 0.93 1 2.22 1 2.85 1 3.31 1 3.56 1 4.08 1Icost cts/kWh I I I I I I II------------------- _I------- _I- -_I- -_I- -_I- -_I- -__IlAverage electricityl 5.54 1 6.71 1 7.31 1 7.75 1 7.98 1 8.48 1Icost cts/kWih I I I I I I II …-…-…-…-…-…-… _ _ _ _ _ _ IlGas netback value I I I I I I II US$/MCF I 6.13 1 6.05 1 6.G4 1 6.03 1 6.03 1 6.02 II US$/M8BTU I 4.961 4.901 4.881 4.88 1 4.881 *.87 1I U.S/GCal I 19.68 1 19.44 1 19.38 1 19.36 1 19.35 1 19.34 1

Fuel oil price S/ton: 150.3 BREAKDOWN OF NET8ACK VALUE -FUEL OIL PLANT-

10iscount rate I 0.0041 8.00S1 11.0041 13.00S1 14.0041I …-…-…-…-…-… _ __ ______ _. _ IICapital + OM cost I I I I I I1diff. US$/ MMDTU I 0.25 1 0.33 1 0.37 1 0.39 1 0.40 1I US$/ GCal I 1.01 1 1.31 1 1.45 1 1.55 1 1.60 1IFuel I I I I I IIcost US$/ srTU I 4.71 1 4.57 1 4.52 1 4.49 1 4.471---- …-…-…-…-… ___ _____ ______ I ____ I

(1) Capital Cost: 900 S / KW

of 6

KONtEA

OAS UTILIZATION STUOY

Oae Oomand Scenarlo.

K O R E A G A S S T U D Y S c e n a r i o s A . C .D

NATURAL AS SU PPLY /OEMAND PR06RAN" Th_aTGns LNG

I I C I T Y G A S 1 0 0 0 T o n s I P O W E R I T O T A LiI I I Coot Cyc Steam Total I II I KYONGIN CENTRAL YONGNAM HONAM SOUTH TOTAL I North Plants I L N G I

1 1988 1 11 1989 1 361 361 1639 1639 2000 11 1990 1 473 473 1527 1527 2000 111991 1 586 586 1415 1415 2000 1i 1992 1 698 698 325 1477 1802 2500 11 1993 1 798 61 859 800 1341 2141 3000 11 1994 1 877 79 956 1252 1292 2544 3500 11 1995 1 960 105 1065 1252 1683 2935 4000 111996 1 1053 137 277 76 1543 1252 1705 2957 4500 111997 1 1152 156 328 100 1736 1252 2012 3264 5000 I1 1998 1 1250 187 388 134 1959 1577 1964 3541 5500 111999 1 1366 216 460 178 2220 1902 1879 3781 6000 11 2000 1 1488 252 544 236 2520 1902 1578 3480 6000 11 2001 1 1619 297 644 314 102 2976 1902 1622 3524 6500 11 2002 1 1733 33C 736 362 115 3284 2553 1163 3716 7000 11 2003 1 1848 380 829 410 128 3595 2553 1352 3905 7500 11 2004 1 1963 42 922 458 141 3906 3203 1391 4594 8500 11 2005 1 2078 464 1015 507 15 4219 3203 1078 4281 8500 I12006 1 2193 S06 1106 55 166 4530 3203 1267 4470 9000 I12007 1 2298 545 1200 603 1I8 4827 3203 970 4173 9000 1

Thousand Tons ING

I i S c e n a r i o A. I S c e n a r i o B. I S c e n a r i o C. I S c e n a r i o D. II I K Y O H G I N I + C E N T R A L I + Y O N G NAN I + H ON A 1 I

I l TOTAL City Total I TOTAL City Total I TOTAL City Total I TOTAL City Total II I LNG gas Power I LNG gas Power I LNG gas Power I gas Power I

-_ … ………… _- I------------------------I-… II I (2) 1 (2) I (2) 1 (2) I

1 1989 1 2000 361 1639 2000 361 1639 2000 361 1639 2000 361 1639 11 1990 1 2000 473 1527 2000 473 1527 2000 473 1527 2000 473 1527 11 1991 1 2000 586 415 2000 586 1415 2000 586 1415 2000 586 1415 11 1992 1 2500 698 1802 2500 698 1802 2500 698 1802 2500 698 1802 11 1993 1 2940 798 2142 3000 859 2141 3000 859 2141 3000 859 2141 11 1994 1 3400 877 2523 3500 956 2544 3500 956 2544 3500 956 2544 11 1995 1 3900 960 2940 4000 1065 2935 4000 1065 2935 4000 1065 2935 '1 1996 1 4000 1053 2947 4150 1190 2960 4400 1467 2933 4500 1543 2957 11 1997 1 4400 1152 3248 4600 1308 3292 4900 1636 3264 5000 1736 3264 1I 1998 1 4800 1250 3550 5000 1437 3563 5400 1825 3575 5500 1959 3541 11 1999 1 5100 1366 3735 5400 1582 3819 5800 2042 3759 6000 2220 3781 11 2000 1 4950 1488 3462 5400 1740 3660 5800 2284 3516 6000 2520 3480 11 2001 1 5100 1619 3481 5450 1916 3534 6100 2560 3540 6400 2874 3526 11 2002 1 5450 1733 3717 5800 2071 3729 6500 2807 3693 7000 3169 3831 i1 2003 1 5750 1848 3902 6150 2226 3922 7000 3057 3943 7400 3467 3933 11 2004 1 6550 1963 4587 7000 2385 4615 7900 3307 4593 8400 3765 4635 11 2005 1 6350 2078 4272 7000 2542 4458 7900 3557 4343 8400 4064 4336 1i 2006 1 6650 2193 4457 7100 2699 4401 8200 3807 4393 8850 4362 4488 1i 2007 1 6450 2298 4152 7100 2843 4257 8200 4043 4157 8850 4646 4204 1

…-- - - - - - - - -- - - - - - - -

Base of Demand projections Basic Plan for LNG National Supply Project'September 1989 - S K. SHIN - Ministry of Energy and Resources -

(1) Gas consuiption in Poeer generation as in Basic LNG Plan Report

(2) Gas consuiption in Porer generation adjusted in each scenario for smoothing LNG supply

K O R E A G A S S T U D Y S c e n a r i o A.

N A T U R-A-L G A S S-U P-P L- Y / D E MA--NOD P-R O-G-R-A-M Thousand Tons LNG

I R E S I D E N T I A L I C O N M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL II I I I TRY I I I I

I I I I I I IL H G II Cooking Total I Operat- Adminis- Total I I City I Combin Steam Total I lI Heating I ional trative I I gas I Cycles Plants I I

11988 1 111989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 0 1639 1639 2000 11 1990 1 92 60 152 37 107 143 178 473 .0 1527 1527 2000 1I 1991 1 106 77 182 46 134 1'79 224 586 0 1414 1414 2000 111992 1 119 94 213 54 160 214 271 698 325 1477 1802 2500 11 1993 1 133 111 244 62 176 238 316 798 800 1342 2142 2940 1 0

11994 1 147 128 275 69 193 262 340 877 1252 1271 2523 3400 11 1995 1 160 148 308 77 209 286 365 960 1252 1688 2940 3900 111996 1 178 171 349 85 231 316 389 1054 1252 1694 2946 4000 11 1997 1 195 198 393 95 253 348 411 1152 1252 1996 3248 4400 11 1998 1 213 228 441 105 281 386 424 1251 1577 1972 3549 4800 1

1999 1 230 268 498 115 309 424 443 1366 1902 1832 3734 5100 1! 2000 1 247 312 559 126 336 462 467 1488 1902 1560 3462 4950 11 2001 1 265 355 620 136 364 500 499 1619 1902 1579 3481 5100 1!2002 1 280 399 679 146 391 537 518 1733 2553 1164 3717 5450 112003 1 294 442 736 156 417 573 540 1848 2553 1349 3902 5750 112004 1 307 486 793 166 443 609 561 1963 3203 1384 4587 6550 1!2005 1 320 529 849 176 469 645 584 2078 3203 1069 4272 6350 11 2006 1 332 573 905 186 497 682 606 2193 3203 1254 4457 6650 1!2007 1 345 616 961 195 522 717 619 2298 3203 949 4152 6450 1

(1) Total LNG import figures are rnunded, and the difference is absorbed by Steam Power Plantsacting as swing consumers. The Combined Cycle programme, however, is fixed with the sameschedule for the scenarios A and B.

K O R E A G A S S T U D Y S c e n a r i o B.

N A T U-R A-L G A-S S U P P-L- Y / D-E M-A N-D P-R-O G-R A-M Thousand Tons LNG

I R E S I D E N T I A L I C O M M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL II I I TRY I I I

I I I I I I I L N G II I Cooking Total I Operat- Adminis- Total I I City I Coffbin Steam Total I I

I Heating I ional trative I I gas ICycles Plants I I--I I I- - I I I

11988' I!1989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 1639 1639 2000 111990 1 92 60 152 37 107 143 178 473 1527 1527 2000 1I1991 1 106 77 182 46 134 i79 224 586 1414 1414 2000 1

1992 1 119 94 213 54 160 214 271 698 325 1477 1802 2500 111993 1 145 121 266 67 192 260 334 859 800 1341 2141 3000 11 1994 1 162 141 303 76 213 289 364 956 1252 1292 2544 3500 1!1995 1 180 166 346 86 236 322 397 1065 1252 1683 2935 4000 11 1996 1 204 196 400 97 266 363 427 1191 1252 1707 2959 4150 111997 1 225 227 452 109 293 402 454 1308 1252 2040 3292 4600 11 1998 1 249 265 514 123 328 451 472 1438 1577 1985 3562 5000 1! 1999 1 272 314 586 136 365 501 495 1582 1902 1916 3818 5400 11 2000 1 296 369 665 '50 402 552 523 1740 1902 1758 3660 5400 112001 1 322 427 750 165 442 608 559 1916 1902 1632 3534 5450 112002 1 345 485 830 1i9 480 659 582 2071 2553 1176 3729 5800 11 2003 1 365 544 910 193 517 710 608 2228 2553 1369 3922 6150 112004 I 386 604 990 207 555 ;62 633 2385 3203 1412 4615 7000 1

2005 1 405 663 1068 221 592 813 661 2542 3203 1155 4358 6900 12006 1 423 723 1147 235 630 865 687 2699 3203 1298 4501 7200 1

12007 1 441 782 1223 249 666 915 706 2843 3U03 1054 4257 7100 1-------------------------------- _------------------------- ---------------- 0

(1) Total LNG import figures are rounded, and the difference is absorbed by Steam Power Plantsacting as swing consumers. The Combined Cycle programme, however, is fixed with the sameschedule for the scenarios A ard B.

K O R E A G A S S T U D Y S c e n a r i o C.

N A T U R A L G A S S U P P L Y / D E M A N D PROGR,AM Thousand Tons LNG

I I R E S I D E N T I A L I C O M M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL I| I I I TRY I I I Ig I I I I I I L N G I

I I Cooking Total I Operat- Adminis- Total I I City I Combin Steam Total I II Heating I ional trative I I gas I Cycles Plants I I

11988 1111989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 1639 1639 2000 1I 1990 1 92 60 152 37 107 143 178 473 1527 1527 2000 1I 1991 1 106 77 182 46 134 179 224 586 1414 1414 2000 11 1992 1 119 94 213 54 160 214 271 698 325 1477 1802 2500 11 1993 1 145 121 266 67 192 260 334 859 800 1341 2141 3000 11 1994 1 162 141 303 76 213 289 364 956 1252 1292 2544 3500 1I 1995 I 180 166 346 86 236 322 397 1065 1252 1683 2935 4000 1i1996 1 251 232 483 118 328 447 538 1468 1252 1780 3032 4500 11 1997 1 280 272 552 134 365 499 586 1636 1252 2TI2 3364 5000 11 1998 1 313 321 634 153 412 565 627 1826 1377 2097 3674 5500 1I 1999 1 347 382 729 172 462 634 679 2042 1902 2056 3958 6000 11 2000 1 384 453 836 192 516 707 740 2284 1902 1814 3716 6000 11 2001 1 424 531 955 215 574 789 817 2560 1902 2038 3940 6500 11 2002 1 458 607 1065 235 630 865 876 2807 2553 1640 4193 7000 1I 2003 1 489 689 1178 256 683 939 940 3057 2553 1890 4443 7500 11 2004 1 520 773 1293 276 737 1012 1002 3307 2?03 1990 5193 8500 112005 1 549 856 1405 295 790 1085 1067 3557 3203 1740 4943 8500 112006 1 577 941 1518 315 844 1159 1130 3807 3203 1990 5193 9000 112007 1 6U3 1025 1628 335 895 1230 1186 4043 3203 1754 4957 9000 1 m

0(1) Total LNG import figures are rounded, and the difference is absorbed by Steam Power Plants ^

acting as swing consumers. The Combined Cycle programme. however, is fixed with the sameschedule for the scenarios A and B.

_-

K O R E A G A S S T U D Y S c e n a r i o C .

N A TuR AL G AS S U P PLY /DOEM A ND P RO GR AM Thousand TonlsLN6

I I R E S I D E N T I A L I C O M M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL II I I TRY I I I I

I I I I I I I L N G II I Cooking Total I Operat- Adminis- Total I I City I Combin Steam Total I II I Heating I ional trative I I gas I Cycles Plants I I

1 19881 11 1989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 1639 1639 2000 1I 3990 1 91.9 60.2 152.0 36.7 106.7 143.4 177.7 473.1 1527 1527 2000 1I 1991 1 105.6 76.8 182.4 45.5 133.6 179.1 224.2 585.7 1414 1414 2000 11 1992 1 119.3 93.8 213.1 54.4 160.1 214.5 270.7 698.3 325 1477 1802 2500 11 1993 1 144.9 120.7 265.6 67.2 192.5 259.7 333.9 859.1 800 1341 2141 3000 11 1994 1 161.9 140.8 302.8 76.4 213.0 289.4 3638 956.0 1252 1292 2544 3500 11 1995 1 180.5 165.6 346.1 86.4 235.6 322.0 397.0 1065.1 1252 1683 2935 4000 11 1996 1 250.7 232.3 483.1 118.5 328.1 446.5 538.0 1467.6 1837 1695 3532 000 11 1997 1 279.6 272.5 552.0 134.4 364.5 498.9 585.5 1636.5 1837 1527 3364 5000 11 1998 1 312.8 320.8 633.5 153.0 412.0 564.9 627.3 1825.8 2487 1687 4174 6000 1I 1999 1 346.8 382.4 729.1 172.1 461.7 633.8 678.9 2041.8 2813 2145 4958 7000 1! 2000 1 383.6 452.8 836.4 191.9 515.6 707.5 740.4 2284.3 2813 1903 4716 7000 11 2001 1 424.0 530.6 954.6 214.7 574.3 789.0 816.8 2560.5 2813 1627 4440 7000 11 2002 1 458.1 607.2 1065.4 235.4 629.7 865.2 876.5 2807.0 3463 2230 5693 8500 11 2003 1 489.4 689.0 1178.4 255.6 683.3 938.9 939.9 3057.1 3463 1980 5443 8500 11 2004 1 520.1 772.8 1292.8 275.6 736.9 1012.5 1001.6 3306.9 4113 2080 6193 9500 11 2005 1 548.8 856.3 1405.1 295.4 789.5 1084.9 1066.7 3556.7 4113 1830 5943 9500 11 2006 1 576.6 941.3 1517.9 315.4 843.7 1159.0 1130.2 3807.1 4113 2080 6193 10000 I1 2007 1 602.7 1025.1 1627.8 334.8 894.9 1229.6 1185.6 4043.0 4113 1844 5957 10000 I

(1) Total LNG import figures are rounded, and the difference is absorbed by Steam Power Plants 4!acting as swing consumers.

In scenario Cl, the Combined Cycle plants schedule is increased in order to obtain thesame economic profitability as in scenario C . a

K O R E A G A S S T U D Y S c e n a r i o D.

N A T U R-A-L G A- S S U P P-L- Y /DO E M-A N-D P-R-O-G R-A-M Thousand Tons LNG

I R E S I D E N T I A L I C O M M E R C I A L I INDUS- I TOTAL I P O W E R I TOTAL II I I I TRY I I I I

I I I I I I IL N G II Cooking Total I Operat- Adminis- Total I I City I Combin Steam Total I II Heating I ional trative I I gas I Cycles Plants I I

1 1988 I1 1989 1 78.2 43.9 122.1 26.3 79.8 106.1 132.8 361.0 1639 1639 2000 1I 1990 1 92 60 152 37 107 143 178 473 1527 1527 2000 11 1991 1 106 77 182 46 134 179 224 586 1414 1414 2000 11 1992 1 119 94 213 54 160 214 271 698 325 1477 1802 2500 11 1993 1 145 121 266 67 192 260 334 859 800 1341 2141 3000 11 1994 1 162 141 303 76 213 289 364 956 1252 1292 2544 3500 11 1995 1 180 166 346 86 236 322 397 1065 1252 1683 2935 4000 11 1996 1 261 241 502 123 342 466 576 1544 1252 1704 2956 4500 11 1997 1 294 284 578 141 384 525 634 1736 1252 2012 3264 5000 11 1998 1 333 338 671 162 438 601 688 1960 1577 1963 3540 5500 1I 1999 1 376 409 785 186 499 685 750 2220 1902 1878 3780 6000 11 2000 1 422 489 911 210 565 775 835 2520 1902 1578 3480 6000 1

2001 1 474 581 1055 239 639 878 942 2874 1902 1624 3526 6400 12002 ! 514 667 1181 263 704 967 1021 3169 2553 1278 3831 7000 1

i 2003 1 551 760 1311 286 766 1052 1104 3467 2553 1380 3933 7400 12004 1 587 857 1443 309 827 1137 1185 3765 3203 1432 4635 8400 1

!2005 ! 621 953 1573 332 888 1221 1270 4064 3203 1133 4336 8400 12006 ! 653 1051 1704 355 951 1306 1352 4362 3203 1335 4538 8900 12007 1 684 1147 1831 378 1010 1388 1427 4646 3203 1051 4254 8900 1

m m(1) Total LNG import figures are rounded, and the difference is absorbed by Steam Power Plants

acting as swing consumers. The Combined Cycle programme, however, is fixed with the sameschedule for the scenarios A and B.

-S I _

- 135 - Annex 10

KOREA Page 1 of 5

GAS UTILIZATION STUDY

Natura! Gam Supply/OD_mnd Progra

K Y O N G I N A R E A S c e n a r i o A.

N A T U R A L G A S S U P P L Y / O E M A N O P R O G R A N

I I LNG SUPPLY I DEMAND 1411 ion M3/Year I TOTAL I POWER DEMAND II I I I I (1) II I K.Tons Mili.M3 IHouseh Conmrc. Industry INON POWER IComb Cyc Steam Pt

I I I I I II 1988 I 1926 2277 97 56 59 212 2065 1I 1989 I 2000 2364 144 125 157 427 1937 II 1990 I 2000 2364 180 169 210 559 1805 II 1991 I 2000 2363 216 212 265 692 1671 111992 I 2500 2955 252 253 320 825 384 1746 111993 I 2940 3474 289 281 373 943 945 1586 I11994 1 3400 4019 325 310 402 1037 1480 1502 I11995 I 3900 4609 365 338 432 1135 1480 1995 11 1996 1 4000 4728 412 373 460 1245 1480 2003 1I 1S97 I 4400 5201 465 411 486 1362 1480 2359 11 1998 1 4800 5674 521 456 501 1478 1864 2331 1I 1999 1 5100 6028 589 501 524 1614 2248 2165 11 2000 1 4950 5851 661 546 552 1759 2248 1844 I1 2001 1 5100 6029 733 591 590 1914 2248 1866 I1 2002 1 5450 6442 802 634 612 2048 3017 1377 I1 2003 1 5750 6796 870 677 638 2184 3017 1594 11 2004 1 6350 7506 937 720 663 2320 3786 1400 I1 2005 1 6350 7506 1004 762 690 2456 3786 1264 1! 2006 1 6450 7624 1070 806 716 2592 3786 1246 I! 2007 1 6450 7624 1136 848 732 2716 3786 1122 1

P R E S E N T V A L U E A T : 13 p.cent ....................T o t a I P r o g r a m m e

US $/GCal 24.26 27.07 25.86 20.20 24.35 27.13 22.04US S/MMBTU 6.11 6.82 6.52 5.09 6.14 6.84 5.55Mill.US$ 7917 876 727 636 2239 2725 2953Billion H3 29.67 2.94 2.56 2.86 8.36 9.13 12.18

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS $/GCal 17.65 17.89 19.05 15.58 17.38 17.71US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46Mill.USs 3139 194 180 184 558 2581 .Billion M3 16.17 0.99 0.86 1.07 2.92 13.25

I n c r e m e nt a l b a s i s s t a r t i n g i n 1 9 9 0US $/GCal 32.17 31.70 29.31 22.96 28.08 27.13 n.m.US $/HMBTU 8.11 7.99 7.39 5.79 7.08 6.84 n.m.Mill.USS 4777 682 547 452 1681 2725 372Billion M3 13.50 1.95 1.70 1.79 5.44 9.13 -1.07...................................................................................

P R E S E N T V A L U E A T : 8 p.cent ....................T o t a I P r o g r a m m e.

US S/GCal 23.00 27.67 26.39 20.62 24.93 22.23 22.21US $/MMBTU 5.80 6.97 6.65 5.20 6.28 5.60 5.60Mill.USS 10742 1390 1127 957 3474 3628 4045Billion M3 44.07 4.57 3.88 4.22 12.67 14.84 11.82

C o n t i n u a t i o n o f p r e s e n t s i t u a t I o nUS $/GCal 17.65 17.89 19.05 15.58 17.38 17.71US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46Mill.US$ 430! 266 246 252 765 3537Billion M3 22.16 1.35 1.18 1.47 4.00 18.15

I n c r e m e nt a l b a s i s s t a r t i n g I n 1 9 9 0US $/GCal 28.60 31.78 29.58 23.32 28.41 22.23 n.m.US $/MMBTU 7.21 8.01 7.45 5.88 7.16 5.60 n.m.Mill.USS 6894 1124 881 705 2710 3628 556Billion M3 21.91 3.21 2.71 2.75 8.67 14.84 -1.60

(I) Gas supplied to Steam power plants is the volume of gas remaining after meetingthe needs of non power demand' for the whole Country, and the needs ofof Combined Cycle plants considered as priority gas consumers.

Annex 10- 136 - Page 2 of 5

K Y O N G I N + C H U N G C H O N G A R E A_--- -- ----- ----- ----------------- S c e n a r i o B.

N A T U R A L G A S S U P P L Y / D E M A N D P R O G R A M

I I LNG SUPPLY I DEMAND Million M3/Year I TOTAL I POWER DEMAND II I I I I (1) 1I I K.Tons MilIl.M3 IHouseh Commerc. Industry INON POWER IComb Cyc Steam PI----------------------_----------------------------------------------------------!

I 1988 I 1926 2277 97 56 59 212 2065 11 1989 1 2000 2364 144 125 157 427 1937 II 1990 ! 2000 2364 180 169 210 559 1805 I!1991 ! 2000 2363 216 212 265 692 1671 !1 1992 I 2500 2955 252 253 320 825 384 1746 I1 1993 ! 3000 3546 313 307 395 1015 945 1586 II 1994 I 3500 4137 358 342 430 1130 1480 1527 iI 1995 I 4000 4728 409 381 469 1259 1480 1990 11 1996 1 4150 4906 473 429 505 1407 1480 2019 11 1997 I 4600 5438 537 473 535 1546 1480 2412 11 1998 I 5000 5909 608 533 558 1699 1864 2346 11 1999 1 5400 6383 692 593 585 1869 2248 2265 I1 2000 1 5400 6383 787 652 618 2057 2248 2078 11 2001 1 5450 6442 886 718 661 2265 2248 1929 11 2002 1 5800 6856 981 779 688 2448 3017 1391 11 2003 I 6150 7270 1075 839 718 2633 3017 1620 11 2004 1 7000 8274 1170 901 748 2819 3786 1669 11 2005 1 7000 8274 1263 961 781 3005 3786 1483 iI 2006 I 7100 8393 1355 1023 8i2 3190 3786 1417 II 2007 I 7100 8392 1447 1079 834 3360 3786 1247 I

P R E S E N T V A L U E A T : 13 p.cent ....................T o t a I P r o g r a m m e

US S/GCal 24.43 28.13 26.05 20.28 24.90 27.13 22.10US $IMMBTU 6.16 7.09 6.56 5.11 6.28 6.84 5.57Mill.US$ 8331 1050 841 691 2582 2725 3024Billion M3 31.00 3.39 2.93 3.10 9.43 9.13 12.44

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS $/GCal 17.65 17.89 19.05 15.58 17.38 17.71US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46Mill.USS 3139 194 180 184 558 2581Billion M3 16.17 0.99 0.86 1.07 2.92 13.25

I n c r e m e n t a l b a s i s s t a r t i n g i n 1 9 9 0US $/GCal 31.83 32.33 28.95 22.77 28.28 27.13 n.m.US S/MMBTU 8.02 8.15 7.29 5.74 7.13 6.84 n.m.Mill.US$ 5192 856 661 507 2024 2725 443Billion M3 14.83 2.41 2.08 2.02 6.51 9.13 -0.81

.. ........ ...................... .. ............ .................... ..... I........... ....... .

P R E S E N T V A L U E A T : 8 p.cent ....................T o t a I P r o g r a m m e

US $/GCal 23.27 28.73 26.56 20.70 25.50 22.23 22.27US $/MMBTU 5.86 7.24 6.69 5.22 6.43 5.60 5.61Mlill.US$ 11406 1692 1324 1048 4G65 3628 4171Billion M3 46.36 5.36 4.53 4.60 14.49 14.84 17.03

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS S/GCal 17.65 17.89 19.05 15.58 17.38 17.71US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46Mill.US$ 4301 266 246 252 765 3537Billion M3 22.16 1.35 1.18 1.47 4.00 18.15

I n c r e m e n t a I b a s i s s t a r t i n g i n 1 9 9 0US S/GCal 28.59 32.39 29.19 23.10 28.59 22.23 n.m.US $/MMBTU 7.20 8.16 7.36 5.82 7.21 5.60 n.m.Mili.US$ 7611 1426 1078 796 3300 3628 682Billion M3 24.20 4.00 3.36 3.13 10.49 14.84 -1.13

(I) Gas supplied to Steam power plants is the volume of gas remailning after meetingthe needs of non power demand for the whole Country. and the needsof Combined Cycle plants considered as priority gas consumers.

10Page 3 of 5

- 137 -

K Y O N G I N / CHUNG CHO NG/ Y ONG NAM A R E AS c e n a r i C.

N A T U R A L G 4 S S U P P L Y / O E N A N O P R O G R A M

I I LNG SUPPLY I DEMAND Million M3/Year I TOTAL I POWER DEMAND II I I I I (1) 1I I K.Tons Mill.M3 lHouseh Commerc. Industry INON POWEP IComb Cyc Steam Pi

- . .. I

1 1988 1 1926 2277 97 56 59 212 2065 1! 1989 ! 2000 2364 144 125 157 427 1937 1!i 1990 2000 2364 180 169 210 559 1805 iI1991 ! 2000 2364 216 212 265 692 1672 !1 1992 1 2500 2955 252 253 320 825 384 1746 1I 1993 I 3000 3546 313 307 395 1015 945 1586 I1 1994 1 3500 41j7 358 342 430 1130 1480 1527 I1 1995 1 4000 4727 409 381 469 1259 1480 1989 1! 1996 1 4400 5201 571 528 636 1735 1480 1986 11 1997 1 4900 5792 653 590 692 1934 1480 2378 11 1998 ! 5400 6383 749 668 741 2158 1864 2361 1! 1999 1 5800 6855 862 749 802 2413 2248 2194 1! 2000 I 5800 6856 989 836 875 2700 2248 1908 !! 2001 ! 6100 7211 1128 933 965 3026 2248 1936 11 2002 i 6500 7683 1259 1023 1036 3318 3017 1348 11 2003 1 7000 8273 1393 1110 1111 3614 3017 1643 11 2004 ! 7900 9338 1528 1197 1184 3909 3786 1643 1! 2005 ! 7900 9337 1661 1282 1261 4204 3786 1347 11 2006 I 8200 9692 1794 1370 1336 4500 3786 1407 I1 2007 ! 8200 9692 1924 1453 1401 4778 3786 1128 I

PR E S E N T V A L U E A T : 13 p.cent ....................T o t a I P r o g r a m m e

uS S/GCal 24.57 28.71 26.33 20.64 25.23 27.13 22.07US $/MMOTU 6.19 7.24 6.63 5.20 6.36 6.84 5.56Mill.USS 8875 1270 1009 881 3161 2725 2990Billion M3 32.83 4.02 3.49 3.88 11.39 9.13 12.31

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS S/GCal 17.65 17.89 19.05 15.58 17.38 17.71US $/MMBTU 4.45 4.51 4.80 3.93 4.38 4.46Mill.US$ 3139 194 180 184 558 2581Billion M3 16.17 0.99 0.86 1.07 2.92 13.25

I n c r e m e n t a l b a s i s s t a r t i n g i n 1 9 9 0US $/GCal 31.29 32.24 28.70 22.57 27.93 27.13 n.m.US $/MMBTU 7.89 8.12 7.23 5.69 7.04 6.84 n.m.Mill.US$ 5735 1076 829 697 2602 2725 408Billior. M3 16.66 3.03 2.63 2.81 8.47 9.13 -0.94...................................................................................

P R E S E N T V A L U E A T : 8 p.cent ....................T o t a I P r o g r a m m e

US $/GCal 23.52 29.27 26.80 21.04 25.77 22.23 22.24US S/MMBTU 5.93 7.38 6.75 5.30 6.49 5.60 5.61Mill.USS 12314 2088 1626 1391 5105 3628 4112Billion M3 49.65 6.48 5.51 6.01 18.01 14.84 11.82

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS S/GCal 17.75 19.40 19.05 15.58 18.04 17.71US S/MMBTU 4.47 4.89 4.80 3.93 4.55 4.46Mill.USS 4327 238 164 161 563 3763Billion M3 22.16 1.12 0.78 0.94 2.84 19.32

I n c r e m e r t a 1 b a s i s s t a r t i n g i n 1 9 9 0US $/GCal 28.40 32.27 28.91 22.81 28.16 22.23 n.m.US $/MMBTU 7.16 8.13 7.28 5.75 7.10 5.60 n.m.Mili-USS 8591 1822 1379 1139 4340 3628 619Billion M3 27.50 5.13 4.34 4.54 14.01 14.84 -1.35

...........................................................................

(I) Gas supplied to Steam power plants is the volume of gas remaining after meetinthe needs of non power demand for the whole Country, and the needs ofof Contined Cycle plants considered as priority gas consumers.

-138 - Page 4 of 5

K Y O N G I N / CHUNG CHO NG/ Y ONG NAN A R E AS c e n a r i o C 1.

N A T U R A L G A S S U P P L Y / D E N A N D P R O G R A M--------------- ---------------------- ----------------------------

I I LNG SUPPLY I DEMAND Million 13/Year I TOTAL I POWER DEKAND II I I I I (1) II I K.Tons Mill.M3 IHouseh Cozmrc. Industry INON POWER ICorb Cyc Steam PI

1 1988 I 1926 2277 97 56 59 212 2065 II 1989 I 2000 2364 144 125 157 427 1937 1I 1990 I 2000 2364 180 169 210 559 1805 II 1991 I 2000 2364 216 212 265 692 1672 I1 1992 I 2500 2955 252 253 320 825 384 1746 I1 1993 I 3000 3546 313 307 395 1015 945 1586 II 1994 I 3500 4137 358 342 430 1130 1480 1527 I1 1995 I 4000 4727 409 381 469 1259 1480 1989 II 1996 I 5000 5909 571 528 636 1735 2172 2003 1I 1997 I 5000 5910 653 590 692 1934 2172 1804 II 1998 I 6000 7092 749 668 741 2158 2940 1994 II 1999 I 7000 8274 862 749 802 2413 3325 2537 II 2000 I 7000 8274 989 836 875 2700 3325 2250 1I 2001 I 7000 8274 1128 933 965 3026 3325 1923 II 2002 I 8500 10047 1259 1023 1036 3318 4093 2635 II 2003 I 8500 10047 1393 1110 1111 3614 4093 2340 II 2004 I 9500 11229 1528 1197 1184 3909 4862 2458 II 2005 I 9500 11229 1661 1282 1261 4204 4862 2163 II 2006 110000 11820 1794 1370 1336 4500 4862 2458 II 2007 110000 11820 1924 1453 1401 4778 4862 2179 I

P R E S E N T V A L U E A T : 13 p.cent ....................T o t a l P r o g r a m m e

US S/GCal 24.81 28.71 26.33 20.64 25.23 27.13 22.29US S/MMBTU 6.25 7.24 6.63 5.20 6.36 6.84 5.62Mill.US$ 9913 1270 1009 881 3161 2725 3200Billion H3 36.32 4.02 3.49 3.88 11.39 9.13 13.05

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS $/GCal 17.65 17.89 19.05 15.58 17.38 17.71US $/M8TU 4.45 4.51 4.80 3.93 4.38 4.46Mill.USS 3139 194 180 184 558 2581 .Billion M3 16.17 0.99 0.86 1.07 2.92 13.25

I n c r e m e n ta l b a s i s s t a r t i n g i n 1 9 9 0US $/GCal 30.56 32.24 28.10 22.57 27.93 27.18 n.m.US S/MMBTU 7.70 8.12 7.23 5.69 7.04 6.85 n.m.Mill.USS 6774 1076 829 697 2602 3553 619 .Billion M3 20.15 3.03 2.63 2.81 8.47 11.88 -0.20 .

P R E S E N T V A L U E A T : 8 p.cent ....................T o t a I P r o ara m m e

US S/GCal 23.48 2.a27 26.80 21.04 25.77 22.23 22.52 .US $/MMBTU 5.92 7.38 6.75 5.30 6.49 5.60 5.67Mill.USS 13789 2088 1626 1391 5105 3628 4551Billion M3 55.90 6.48 5.51 6.01 18.01 14.84 11.82

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS S/GCal 17.75 19.40 19.05 15.58 18.04 17.71US $/MIBTU 4.47 4.89 4.80 3.93 4.55 4.46Mill.USS 4327 238 164 161 563 3763Billion M3 22.16 1.12 0.78 0.94 2.84 19.32

I n c r e m e n ta l b a s i s s t a r t i n g i n 1 9 9 0US $/GCal 27.43 32.27 28.91 22.81 28.16 22.27 n.m.US $/MMBTU 6.91 8.13 7.28 5.75 7.10 5.61 n.m.Mill.USS 10184 1822 1379 1139 4340 4781 1063Billion M3 33.75 5.13 4.34 4.54 14.01 19.52 0.22

..............................................................................

(1) Gas supplied to Steam power plants is the volume of gas reraining after meetinthe needs of 'non power demand' for the whole Country. and the needs ufof Combined Cycle plants considered as priority gas consumers.

10Page 5 of 5

- 139 -

K Y O N G I N / CHUNGC H O N G / Y O N G NAN A R E AS c e n a r i o 0 .

N A T U R A L G A S S U P P L Y / D E N A N D P R O G R A M

I I LNG SUPPLY I DEMAND Nillior. M3/Year I TOTAL I POWER DEMAND II I I I I (1) II I K.Tons Mill.M3 IHouseh Coim.rc. Industry INON POWER IComb Cyc Steam Pi

I I I I III 1988 I 1926 2277 97 56 59 212 2065 1I 1989 I 2000 2364 144 125 157 427 1937 I1 1990 I 2000 2364 180 169 210 559 1805 111991 1 2000 2364 216 212 265 692 1672 II 1992 i 2500 2955 252 253 320 825 384 1746 I11993 1 3000 3546 313 307 395 1015 945 1586 II 1994 I 3500 4137 358 342 430 1130 1480 1527 I11995 I 4000 4727 409 381 469 1259 1480 1989 I11996 1 4500 5319 593 550 681 1825 1480 2015 I11997 I 5000 5910 684 620 749 2053 1480 2378 I11998 I 5500 6500 793 710 813 2317 1864 2320 I11999 I 6000 7092 927 810 887 2624 2248 2219 II 2000 I 6000 7093 1077 916 987 2979 2248 1865 I1 2001 1 6400 7565 1246 1037 1114 3398 2248 1919 1I 2002 I 7000 8274 1396 1142 1207 3746 3017 1511 II 2003 I 7400 8746 1550 1243 1305 4098 3017 1631 II 2004 I 8400 9928 1706 1344 1400 4450 3786 1693 1I 2005 I 8400 9929 1860 1443 1501 4804 3786 1339 1I 2006 I 8900 10519 2014 1544 1598 5156 3786 1578 I12007 1 8900 10520 2165 1641 1686 5491 3786 1243 I

P R E S E N T V A L U E A T : 13 p.cent ....................T o t a l P r o g r a m m e

US $/GCal 24.62 28.82 26.43 20.76 25.31 27.13 22.09US $/MNBTU 6.20 7.26 6.66 5.23 6.38 6.84 5.57Mill.US$ 9143 1361 1082 968 3411 2725 3007Billion M3 33.76 4.29 3.72 4.24 12.25 9.13 12.38

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS $/GCal 17.65 17.89 19.05 15.58 17.38 17.71US S/HMBTU 4.45 4.51 4.80 3.93 4.38 4.46Nill.US$ 3139 194 180 184 558 2581Billion N3 16.17 0.99 0.86 1.07 2.92 13.25

I n c r e m e n ta l b a s is s t a r t i n g i n 1 9 9 0US S/GCal 31.03 32.09 28.65 22.52 27.79 27.13 n.m.US $/MMBTU 7.82 8.09 7.22 5.68 7.00 6.84 n.m.Mill.US$ 6003 1167 902 784 2853 2725 426Billion M3 17.59 3.31 2.86 3.17 9.33 9.13 -0.87...................................................................................

P R E S E N T V A L U E A T : 8 p.cent ....................T o t a l P r o r a m m e

US $/GCal 23.61 29.36 26.90 21.16 25.83 22.23 22.27US $/MTBTU 5.95 7.40 6.78 5.33 6.51 5.60 5.61Mill.US$ 12774 2257 1759 1550 5567 3628 4147Billion M3 51.37 6.99 5.94 6.66 19.59 14.84 11.82

C o n t i n u a t i o n o f p r e s e n t s i t u a t i o nUS $/GCal 17.75 19.40 19.05 15.58 18.04 17.71US $/MMBTU 4.47 4.89 4.80 3.93 4.55 4.46Nill.US$ 4327 238 164 161 563 3763Billion M3 22.16 1.12 0.78 0.94 2.84 19.32

I n c r e m e n ta I b a s i s s t a r t i n g i n 1 9 9 0US $/GCal 28.28 32.11 28.83 22.74 27.99 22.23 n.m.US t/HMBTU 7.13 8.09 7.27 5.73 7.05 5.60 n.m.Mill.USS 9088 1991 1513 1298 4802 3628 654Billion H3 29.21 5.64 4.77 5.19 15.59 14.84 -1.22

...............................................................................

(1) Gas supplied to Steam power plants is the volume of gas remaining after metinthe needs of 'non power demand' for the whole Country, and the needs ofof Combined Cycle plants considered as priority gas consuners.

- 140 - A 10

KOREA

GAS UTILIZATION STUDY

Estimt, of Investment Cost

AVERAGE COST OF I NFRASTRUCTURE

Scenar io .A . :KYONGI N AREA

I I C A P I T A L I N V E S T M E N T .OPERATION COSTI I IL DO TERMINAL . PYONG PIPELINES DISTRIB-.I 13 Tanks 1 Tank . TAEK UTION .Terminal Network II… I…- _II Imillion US $ (1) .million US S (1) .million S/Y i

I 1989 II 1990I . 6.5 70.14. 2.4 II 1991 I 9.9 . 19.3 22.0 70.50 . 4.8 II 1992 1 34.1 . 27.4 44.1 70.54 . 7.2 II 1993 I 60.8 17.1 44.0 62.53 . 1.0 9.3 II 1994 I 103.7 6.5 49.47 . 1.4 11.0 II 1995 I 108.0 52.06 . 2.0 12.7 II 1996 I 77.8 19.7 58.61 . 8.4 14.7 II 1997 I 50.0 61.86 . 8.4 16.8 1I 1998 I 6.3 61.63 . 9.6 18.9 1I 1999 1 72.07 . 9.6 21.4 1I 2000 I 76.71 . 9.6 24.0 II 2001 I 7.3 82.17 . 9.6 26.8 II 2002 I 22.1 71.06 . 9.6 29.2 II 2003 I 39.4 72.18 . 9.6 31.6 II 2004 1 46.4 71.91 . 9.6 34.1 II 2005 I 26.4 71.93 . 9.6 36.5 II 2006 I 4.5 72.19 . 11.0 39.0 II 2007 I 65.84 . 12.1 41.2 I

I I T-O TOTAL C O S T . G A S S U P PPL Y II (n c r e m e n t a I ) (I n c r e m e n t a l ) I

I ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I

I Imilon US $ M1i1.M3/Y BCF /Y BCF I

1 1989I . .1 1990 1 76.66 . 76.66. 0I 1991 1 121.65 . 121.65 . -1 II 1992 I 176.18 . 176.18. 591 20.9 21 I1 1993 I 184.44 10.30 . 194.74 1110 39.2 60 II 1994 1159.68 12.38 172.06 1655 58.4 119 II 1995 i 160.04 14.74 . 174.78 2245 79.3 198 II 1996 I 156.13 23.13 . 179.26 2364 83.5 281 I1 1997 I 111.82 25.24 . 137.06 2837 100.1 381 Ii 1998 I 67.89 28.53 . 96.42 3310 116.8 498 11 1999 1 72.07 30.98 . 103.05 3664 129.3 628 I1 2000 I '.71 33.58. 110.29 3487 123.1 751 II 2001 I 89.46 36.37 . 125.83 3665 129.4 880 II 2002 I 93.17 38.79 131.96 4078 144.0 1024 II 2003 I 111.60 41.24 . 152.84 4432 156.4 1180 i1 2004 I 118.36 43.68 . 162.04 5142 181.5 1362 II 2005 I 98.32 46.12 . 144.44 5142 181.5 1543 1I 2006 I 76.73 49.97 . 126.70 5260 185.7 1729 II 2007 I 65.84 53.31 . 119.15 5260 185.7 1915 I

…----… _ I(1)e x c u d i n g t a x e s o n i m p o r t e d m a t e r i a l

(27.5 % of material cost)

I II DISCOUNT RATE % I 0 8 11 . 13 15 1

…- …_ .I

I CUMULATED D C F M.$ I 2505.1 1315.3 1081.4 . 959.9 859.0 II GAS DISCOUNT. VOL BCF I 1915 773 574 . 477 399 1- ……- __I

I A.I.C. (S/ MM8TU) I 1.06 1.38 1.52 1.63 1.74 II (S/ GCal) I 4.21 5.48 6.03 6.47 6.90 II A.I.C. (S/ MCF) I 1.31 1.70 1.88 2.01 2.15 II (W o n / n13) I 30.5 39.8 43.8 47.0 50.1 I--- …-

GAS LHV BTU /CFT 1236 Exchange rate-KCal/M3 11000 660 Won /US S

11- 141 - Page 2 of 10

C O S T O F I N F R A S T R U C T U R E

S c e n a ri o .A . : K Y O N G I N A R E A

I n c l u d i n g T a x e s (1)

t I C A P I T A L I N V E S T M E N E N T .OPERATION COST II I 1L DO TERMINAL 3 rd . PYONG PIPELINES OISTRIB-. I

13 Tanks 1 Tank 1 Termin. TAEK UTION .Terminal Network II…__ _ _I…- _II Imillion US $ .million US $ .million S/Y I

1 1989 1I 19901 . 7.6 70.14. 2.4 1I 1991 1 11.5 . 22.5 23.7 70.50 . 4.8 111992 1 39.8 . 32.0 47.5 70.54 . 7.2 111993 1 70.9 20.0 47.4 62.53 . 1.0 9.3 11 1994 1 121.0 7.6 49.47 . 1.4 11.0 I1 1995 1 126.0 52.06 . 2.0 12.7 111996 1 90.8 23.0 58.61 . 8.4 14.7 11 1997 1 58.3 61.86 . 8.4 16.8 111998 1 7.3 61.63 . 9.6 18.9 11 1999 1 72.07 . 9.6 21.4 112000 1 76.71 . 9.6 24.0 11 2001 1 8.5 82.17 . 9.6 26.8 11 2002 1 25.8 71.06 . 9.6 29.2 11 2003 1 46.0 72.18 . 9.6 31.6 11 2004 1 54.2 71.91 . 9.6 34.1 11 2005 1 30.8 71.93 . 9.6 36.5 1I 2006 1 5.3 72.19 . 11.0 39.0 11 2007 1 65.84 . 12.1 41.2 1

…------

(1) Breakdown of TERMINAL cost Material 52 p.centConstruction 31 p.centEngineering/ 17 p.centOther

PIPELINE cost Material 26 p.centConstruction 56 p.centEngineering/ 18 p.centOther

Taxes are set at 27.5 p.cent of imported material costincluding 22.5 % of customs duty.

S U M M A R Y O F I N V E S T M E N T S C H E D U L E

I I T o t a l T e r m i n a l s II P e r i o d I . PYONG IL 00 3 RD . PIPE OISTRIB- I

I . TAFK TERMINAL. LINES UTION I

I .m i ll i o n U SS I

I ~ ~ ~~I . .II I . .I1 9 9 0 - 1 9 9 3 1 596.6. 82.1 122.2 . 118.6 273.7 1

I I . .I1 I .. II1 9 9 4 - 1 9 9 7 1 648.7. 7.6 419.1 . 222.0 1I I . .II I . .II1 9 9 8 - 2 0 0 1 1 308.4. 8.5 7.3 . 292.6 1I I . .II I . .I12 0 0 2 - 2 0 0 6 1 449.2. 162.1 . 287.1 1I I . .I

I I . .II T O T A L 1 2002.9 . 260.3 548.6 . 118.6 1075.4 1I I . .- II……………………I

Annex 1 1- 142 - Page 3 of 10

A V E R A G E C O S T O F I N F k A S T R U C T U R E

S c e n a r i o 8 : K Y O N G I + C H U N G C H N G REA

I I C A P I T A L I N V E S T H E N T .OPERATION COST iI I IL DO TERMINAL 3 rd . PYONG PIPELINES DISTRIB-. I 13 Tanks 1 Tank I Termin. TAEK UTION .Terminal Network II … I …………_…_--- ----- ----- ----- ----- -- ---I Imillion US $ (1) .million US $ (1) .million $/Y I

I 1989 I11990I . 6.5 70.14. 2.4 1I 1991 I 9.9 . 19.3 18.6 22.0 70.50 . 4.8 II 1992 I 34.1 . 27.4 37.5 44.1 70.54 . 7.2 II 1993 I 60.8 17.1 37.5 44.0 90.05 . 1.0 9.4 II 1994 1 103.7 6.5 54.78 . 1.4 11.3 II 1995 I 108.0 61.00 . 2.0 13.3 II 1996 I 77.8 19.7 5.0 70.56 . 8.4 15.7 II 1997 I 50.0 65.70 . 8.4 17.9 II 1998 I 6.3 73.15 . 9.6 20.4 I1 1999 I 80.52 . 9.6 23.1 II 2000 I 89.28 . 9.6 26.1 II 2001 I 7.3 98.97 . 9.6 29.4 II 2002 I 22.1 86.72 . 9.6 32.3 1I 2003 I 39.4 87.72 . 9.6 35.3 II 2004 I 46.4 88.53 . 9.6 38.3 II 2005 I 26.4 88.50 . 9.6 41.3 I1 2006 I 4.5 87.79 . 11.0 44.2 11 2007 I 80.60 . 12.1 46.9 1

I I T O T A L C O S T . G A S S U P P L Y II I (I n c r e ni e n t a 1 ) (I n c r e m e n t a I ) II ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I

I Imilton US $ Mi11.M3/Y BCF /Y 8CF I

11989 I11990 1 76.66 . 76.66. 0 I11991 1140.22 . 140.22 . -1 I11992 I213.69 . 213.69 . 591 20.9 21 1I 1993 I 249.47 10.41 . 259.88 1182 41.7 63 II 1994 I 164.99 12.65 177.64 1773 62.6 125 I11995 I 168.98 15.31 . 184.29 2364 83.5 209 I11996 1173.10 24.09 . 197.19 2542 89.7 298 II 1997 I 115.66 26.30 . 141.96 3074 108.5 407 II 1998 I 79.40 29.96 . 109.36 3545 125.2 532 II 1999 I 80.52 32.67 . 113.19 4019 141.9 674 II 2000 I 89.28 35.68 . 124.96 4019 141.9 816 II 2001 I 106.26 39.02 . 145.28 4078 144.0 960 II 2302 I 108.83 41.94 150.77 4492 158.6 1119 1I 2003 I 127.14 44.89 . 172.03 4906 173.2 1292 II 2004 I 134.98 47.87 . 182.85 5910 208.6 1500 II 2005 I 114.90 50.86 . 165.76 5910 208.6 1709 II 2006 I 92.33 55.21 . 147.54 6029 212.8 1922 II 2007 1 80.60 59.03 . 139.63 6028 212.8 2135 I

(1)e x c u d i n g t a x e s o n i m p o r t e d m a t e r i a 1(27.5 % of material cost)

I OISCOUNT RATE % I 0 8 11 . 13 15 1

I CUMULATED D C F M.S I 2842.9 1493.9 1229.2 . 1091.6 977.4 II GAS DISCOUNT. VOL BCF I 2135 855 632 . 524 437 i

I A.I.C. (S/ MM8TU) I 1.08 1.41 1.57 1.69 1.81 II (SI GCal) I 4.29 5.60 6.23 6.71 7.18 II A.I.C. (S/ MCF) I 1.33 1.75 1.94 2.09 2.24 II (W o n / M3) I 31.1 40.6 45.2 48.7 52.1 1I…--- - -- - -- - -- -- - -- - -- - -- -- - -- - -- - -- -- - -- - -- - --

GAS LHV BTU /CFT 1236 Exchange rate-KCal/M3 11000 660 Won /US $

11

- 143- Page 4 of 10

C O S T O F I N F R A S T R U C T U R E

S c e n a r i o B : K Y O N G I N * C H U N G C H O N G A R E A

I n c I u d I n g T a x e s (1)I…I I C A P I T A L I N V E S T M E N T .OPERATION COST II I IL DO TERMINAL 3 rd . PYONG PIPELINES OISTRIB-. iI 13 Tanks I Tank 1 Termin. TAEK UTION .Terminal Network I

I Ilmillion US $ .million US $ .million $/Y I

1 1989 1 I11990 1 . 7.6 70.14. 2.4 1I 1991 1 11.5 . 22.5 20.0 23.7 70.50 . 4.8 11 1992 1 39.8 . 32.0 40.4 47.5 70.54 . 7.2 II 1993 1 70.9 20.0 40.4 47.4 90.05 . 1.0 9.4 11 1994 1 121.0 7.6 54.78 . 1.4 11.3 11 1995 1 126.0 61.00 . 2.0 13.3 11 1996 1 90.8 23.0 5.4 70.56 . 8.4 15.7 II 1997 1 58.3 65.70 . 8.4 17.9 II 1998 I 7.3 73.15 . 9.6 20.4 II 1999 I 80.52 . 9.6 23.1 I1 2000 I 89.28 . 9.6 26.1 II 2001 I 8.5 98.97 . 9.6 29.4 I1 2002 I 25.8 86.72 . 9.6 32.3 II 2003 I 46.0 87.72 . 9.6 35.3 I1 2004 I 54.2 88.53 . 9.6 38.3 II 2005 I 30.8 88.50 . 9.6 41.3 I12006 I 5.3 87.79 . 11.0 44.2 II 2007 1 80.60 . 12.1 46.9 I-- …

(1) Breakdown of TERMINAL cost Material 52 p.centConstruction 31 p.centEngineering/ 17 p.centOther

PIPELINE cost :Material 26 p.centConstruction 56 p.centEngineering/ 18 p.centOther

Taxes are set at 27.5 p.cent of imported mnterial costIncluding 22.5 % of customs duty.

S U M M A R Y O F I N V E S T M E N T S C H E D U L E

I ~~~~~~I T a t a I T e r m I n a I s II P e r i o d I .PYONG IL DO 3 RD . PIPE DISTRIB- II I . TAEK TERMINAL. LINES UTION I

I I .mi1l1i on U SS .I

I I m. II ~ ~ ~~I . .I

1 9 9 0 - 1 9 9 3 I 724.9. 82.1 122.2 . 219.4 301.2II I . .II I . .I19 9 4 - 1 9 9 7 I 684.1. 7.6 419.1 . 5.4 252.0 1

I I . II I . .II1 9 9 8 - 2 0 0 1 I 357.7. 8.5 7.3 . 341.9 1I I . .II I . .I12 0 0 2 - 2 0 0 6 I 513.6. 162.1 . 351.5 1I I..I

I I..II T O T A L I 2280.4. 260.3 548.6 . 224.8 1246.7 1I I . . II ---- I

- 144 - Annex 11Page 5 of 10

AVERAGE COSt OF I NFRASTRUCTURE

Scena r io C : K YONG I N/ CHUNGCHONG/ YONGNAM

I I C A P I T A L I N V E S T H E N T .OPERATION COST II I IL 00 TERMINAL 3 rd . PYONG PIPE DISTRIB-. I IPort/Sit Terminal Termin. TAEK LINES UTION .Terminal Network I

… I……- ……II Imillion US S (1) .million US $ (1) .miliion S/Y I

I 1989 I II 1990 I 9.9 . 6.5 70.14 . 2.4 II 1991 I 34.1 . 19.3 40.7 70.50 . 4.8 II 1992 I 60.8 . 27.4 81.6 70.54 . 7.2 II 1993 1 103.7 17.1 130.8 90.05 . 1.0 9.4 I1 1994 I 108.0 6.5 114.7 54.90 . 1.9 11.3 II 1995 I 77.8 19.7 114.7 60.89 . 2.5 13.3 11 1996 I 50.0 5.0 226.16 . 10.4 20.9 1I 1997 I 6.3 7.7 94.74 . 10.4 24.1 1I 1998 I 106.17 . 11.6 27.7 II 1999 I 7.3 121.25 . 11.6 31.8 1I 2000 I 22.1 136.27 . 11.6 36.4 II 2001 I 39.4 154.86 . 11.6 41.6 II 2002 I 46.4 138.69 . 11.6 46.3 I1 2003 I 26.4 140.42 . 11.6 51.0 II 2004 1 4.5 140.31 . 13.0 55.7 1I 2005 I 140.22 . 14.1 60.4 1I 2006 I 140.55 . 14.1 65.2 II 2007 I 132.2? . 14.1 69.6 I

I I T O T A L C O S T . G A S S U P P L II I (I n c r e m e n t a ) (I n c r e m e n t a l ) II ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I

…I …………- ____ IImilion US $ Mill.M3/Y BCF /Y BCF I

I 1989 1 . .Ii 1990 1 86.51 . 86.51. -OI 1991 I 164.56 . 164.56 . -0I 1992 I 240.34 . 240.34 . 591 20.9 21 II 1993 I 3'1.71 10.41 . 352.12 1182 41.7 63 II 1994 I 284.06 13.16 297.22 1773 62.6 125 II 1995 I 273.08 15.81 . 288.89 2363 83.4 209 II 1996 I 281.14 31.33 . 312.47 2837 100.1 309 1I 1997 I 108.71 34.52 . 143.23 3428 121.0 430 II 1998 I 106.17 39.29 . 145.46 4019 141.9 572 II 1999 I 128.54 43.38 . 171.92 4491 158.5 730 I1 2000 I 158.38 47.97 . 206.35 4492 158.6 889 I1 2001 I 194.28 53.19 . 247.47 4847 171.1 1060 II 2002 I 185.14 57.86 243.00 5319 187.8 1248 II 2003 t 166.82 62.59 . 229.41 5909 208.6 1456 II 2004 I 144.85 68.71 . 213.56 6973 246.2 1702 II 2005 I 140.22 74.54 . 214.76 6973 246.2 1949 II 2006 I 140.55 79.27 . 219.82 7328 258.7 2207 II 2007 I 132.22 83.72 . 215.94 7328 258.7 2466 I--- … __I…(I) e x c I u d i n g t a x e s o n i m p o r t e d m a t e r i a 1

(27.5 % of material cost)

I DISCOUNT RATE % I 0 8 11 . 13 15 1

I CUMULATED D C F M.S I 3993.0 2064.9 1687.5 . 1491.7 1329.4 1I GAS DISCOUNT. VOL BCF I 2466 971 714 . 588 489 i

~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~II A.S.C. (S/ MMBTJ) I 1.31 1.72 1.91 2.05 2.20 1

(SI GCal) I 5.20 6.83 7.58 8.13 8.73 1I A.I.C. (S/MCF) I 1.62 2.13 2.36 2.54 2.72 1I (W o n / M3) 1 37.7 49.6 55.0 59.1 63.4 1

GAS LHV BTU /CFT 1236 Exchange rate-KCallM3 11000 660 Won /S S

GAS LHV BTU /CFT 1236 Exchange rate-KCal/M3 11000 660 Won /US $

0 0.08 0.11 0.13 0.15

-145 - Page 6 of 10

C O S T O F I N F R A S T R U C T U R E

S c e n a r i o C : K Y O N G I N / C H U N G C N O N G / Y O N G N A M

I n c l u d i n g T a x e s (1)

I I C A P I T A L I N V E S T M E Nt .OPERATION COST II I IL DO TERMINAL 3 rd . PYONG PIPE DISTRIB-. II 53 Tanks I Tank 1 Termin. TAEK LINES UTION .Terminal Network IS -.. _I--…

Imillion US $ .million US $ .million S/Y I

11989 1 II 1990 1 11.5 . 7.6 70.14 . 2.4 I11991 1 39.8 . 22.5 43.8 70.50 . 4.8 51 1992 1 70.9 . 32.0 87.9 70.54 . 7.2 1I1993 I 121.0 20.0 140.9 90.05 . 1.0 9.4 II1994 1 126.0 7.6 123.5 54.90 . 1.9 11.3 111995 I 90.8 23.0 123.5 60.89 . 2.5 13.3 II1996 I 58.3 5.4 226.16 . 10.4 £0.9 II1997 1 7.3 8.3 94.74 . 10.4 24.1 I1 1998 1 106.17 . 11.6 27.7 1I 1999 1 8.5 121.25 . 11.6 31.8 1I 2000 I 25.8 136.27 . 11.6 36.4 I1 2001 I 46.0 154.86 . 11.6 41.6 11 2002 I 54.2 138.69 . V.6 46.3 II 2003 I 30.8 140.42 . 11.6 51.0 II 2004 I 5.3 140.31 . 13.0 55.7 I1 2005 1 140.22 . 14.1 60.4 11 2006 1 140.55 . 14.1 65.2 I1 2007 I 132.22 . 14.1 69.6 I---------- -

(1) Breakdown of TERMINAL cost :Material 52 p.centConstruction 31 p.centEngineering/ 17 p.centOther

PIPELINE cost : Material 26 p.centConstruction 56 p.centEngineering/ 18 p.centOther

Taxes are set at 27.5 p.cent of inported material costincluding 22.5 % of customs duty.

S U M M A R Y O F I N V E S T M E N T S C H E D U L E

I I T o t a l T e r m i n a l sI P e r i o d I . PYONG IL DO 3 RD . PIPE DISTRIB- II I . TAEK TERMINAL. LINES UTION I

I I .m l l i o n U S $ . I

1 9 9 0 - 1 9 9 3 I 899.1. 82.1 243.2 . 272.6 301.2 5I I . .5

I1 9 9 4 - 1 9 9 7 I 1010.4. 7.6 305.4 . 260.7 436.7 II I . I

I I .~~~ . II1 9 9 8 - 2 0 0 1 1 598.9. 80.3 . 518.6 1I I . .I I..I52 0 0 2 - 2 0 0 6 1 649.9. 90.3 . 559.6 5I I . .

I T O T A L I 3158.3. 260.3 548.6 . 533.3 1816.1 II I . . I

Annex 1 1

- 146 - Page 7 of 10

AVERAGE COST OF I NFRASTRUCTURE

Scenario0 C1. :KY0NGIN/ CHIUNGCHONG/YON6NAM

I I C A P I T A L I N V E S T 1 E N T .OPERATION COST II I IL 00 TERMINAL 3 rd . PYONG PIPE DISTRIB-. II IPort/Sit Terminal Termin. TAEK LINES UTION .Terminal Network II … I…-- - - - - - - - - - - - - - - -II Imillion US $ (1) .million US S (1) .million $/Y I

I 1989 II 1990 I 9.9 . 6.5 70.14 . 2.4 II 1991 1 34.1 . 19.3 40.7 70.50 . 4.8 11 1992 I 60.8 . 27.4 81.6 70.54 . 7.2 I1 1993 I 103.7 17.1 130.8 90.05 . 1.0 9.4 II 1994 I 108.0 6.5 114.7 54.90 . 1.9 11.3 II 1995 I 77.8 19.7 114.7 60.89 . 2.5 13.3 II 1996 1 50.0 5.0 226.16 . 10.4 20.9 11 1997 I 6.3 7.7 94.74 . 10.4 24.1 11 1998 1 106.17 . 11.6 27.7 I11999 1 13.8 121.25 11.6 31.8 11 2000 I 41.4 136.27 . 11.6 36.4 I1 2001 1 66.8 154.86 . 11.6 41.6 112002 1 63.6 138.69 . 11.6 46.3 11 2003 I 32.9 140.42 . 11.6 51.0 II 2004 1 4.5 140.31 . 13.0 55.7 112005 1 140.22 . 15.4 60.4 II 2006 I 140.55 . 15.4 65.2 I! 2007 I 132.22 . 15.4 69.6 I

! -----------------------------------------------------------------------I I TOTAL COST . GAS SUPPLY II i (I n c r e m e n t a 1) (I n c r e m e n t a l ) II ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I!I------ I------------------------------------____-----____ _______I____ ___ __I Imilion US S Mill.H3/Y BCF /Y BCF I!I------I--------------------------------------------------_-_-_________-__- _!1989I . .11990 1 86.51 .86.51. -0 tI1991 1 164.56 164.56. -0 I! 1992 I 240.34 240.34 . 591 20.9 21 I! 1993 I 341.71 10.41 . 352.12 1182 41.7 63 I11994 I 284.06 13.16 297.22 1773 62.A 125 II 1995 I 273.08 15.81 . 288.89 2363 83.4 209 II 1996 I 281.14 31.33 . 3!2.47 3545 125.1 334 1I 1997 I 108.71 ;4.52 . 143.23 3546 125.2 459 1I 1998 1 106.17 39.29 . 145.46 4728 166.9 626 iI 1999 I 135.05 43.38 . 178.43 5910 208.6 834 II 2000 I 177.66 47.97 . 225.63 5910 208.6 1043 II 2001 ! 221.70 53.19 . 274.89 5910 208.6 1252 II 2002 I 202.28 57.86 260.14 7682 271.2 1523 II 2003 1 173.33 62.59 . 235.92 7683 271.2 1794 I12004 1 144.85 68.71 . 213.56 8865 312.9 2107 II 2005 I 140.22 75.84 . 216.06 8865 312.9 2420 II 2006 I 140.55 80.57 . 221.12 9456 333.8 2754 II 2007 I 132.22 85.02 . 217.24 9456 333.8 3087 I

(1)e x c u d i n g t a x e s o n i m p o r t e d m a t e r i a 1(27.5 % of material cost)

I…_-- - -- - -- - -- - -- - -- - - -- - -- - -- - -- - -- - -- - -I DISCOUNT RATE % I 0 8 11 . 13 15 1-- - - - - - - - - - - - - _… - - -_ - - - -_- I

I CUMULATED D C F N.$ I 4073.8 2096.7 1710.3 . 1510.2 1344.4 II GAS DISCOUNT. VOL BCF I 3087 1191 868 . 711 588 I

I A.I.C. (S/ MM6TU) I 1.07 1.42 1.59 1.72 1.85 1I (SI GCal) I 4.25 5.63 6.31 6.83 7.34 II A.I.C. JS/ MCF) I 1.32 1.76 1.97 2.12 2.29 II {M n / M3) 1 30.8 40.9 45.8 49.6 53.3 I

GAS LHV 8TU /CFT 1236 Exchange rate-KCal/H3 11000 660 Won /US S

Annex 11

- 147 - Page 8 of 10

CoST O F I N F R A S T R U C T U R E

S c e n a ri5 o C 1. : K Y O N G I N / C H U N G C H O N G / Y O N G N A H

I n c I u d i n 9 T a x e s (1)I…I I C A P I T A L I N V E S T M E N T .OPERATION COST II I IL DO TERnINAL 3 rd . PYONG PIPE OISTRIB-. II 13 Tanks I Tank 1 Termin. TAEK LINES UTION .Terminal Network I

I Imillion US $ .million US S .million S/Y I

I 1989 . II 1990 I 11.5 . 7.6 70.14 . 2.4 II 1991 I 39.8 . 22.5 43.8 70.50 . 4.8 II 1992 I 70.9 . 32.0 87.9 70.54 . 7.2 II 1993 I 121.0 20.0 140.9 90.05 . 1.0 9.4 I11994 I 126.0 7.6 123.5 54.90 . 1.9 11.3 111995 I 90.8 23.0 123.5 60.89 . 2.5 13.3 II 1996 1 58.3 5.4 226.16 . 10.4 20.9 II 1997 I 7.3 8.3 94.74 . 10.4 24.1 II 1998 I 106.17 . 11.6 27.7 I11999 I 16.1 121.25 . 11.6 31.8 II 2000 I 48.3 136.27 . 11.6 36.4 II 2001 1 78.0 154.86 . 11.6 41.6 II 2002 I 74.2 138.69 . 11.6 46.3 II 2003 I 38.4 140.42 . 11.6 51.0 II 2004 I 5.3 140.31 . 13.0 55.7 II 2005 I 140.22 . 15.4 60.4 II 2006 I 140.55 . 15.4 65.2 II 2007 I 132.22 . 15.4 69.6 I-----

(1) Breakdown of TERMINAL cost :Material 52 p.centConstruction 31 p.centEngineering/ 17 p.centOther

PIPELINE cost : Material 26 p.centConstructiun 56 p.centEngineering/ 18 p.centOther

Taxes are set at 27.5 p.cent of iqorted material costincluding 22.5 t of customs duty.

S U M M A R Y O F I N V E S T M E N T S C H E D U L E

I I T o t a I T e r m i n a sII P e r i o d I .PYONG IL DO 3 RD . PIPE DISTRIB- II I . TAEK TERMINAL. LINES UTION I

I I .m i I i o n U S $ . I

I I . .II I . .I1 9 9 0 - 1 9 9 3 1 899.1. 82.1 243.2 . 272.6 301.2 1

I I . .II I . .II1 9 9 4 - 1 9 9 7 I 1010.4. 7.6 305.4 . 260.7 436.7 1I I . .II I . .II1 9 9 8 - 2 0 0 1 1 661.0. 142.4 . 518.6 1I I . .I

12 0 0 2 - 2 0 0 6 1 677.5 117.9 559.6 1I I . .I

I I . .II T O T A L I 3248.0 . 350.0 548.6 . 533.3 1816.1 1I I .-- II…… …… …

11- 148- Page 9 of 10

A V E R A G E C O S T O F I N F R A S T R U C T U R E

K Y O N G I N / C H U N G C H O N G / Y O N G N A M / H O N A N

S c e n a r i o D

I I C A P I T A L I N V E S T M E N T .OPERATION COST II I IL DO TERMINAL 3 rd . PYONG PIPE DISTRIB-. II IPort/Sit Terminal Termin. TAEK LINES UTION .Terminal Network I

…I-- -- -- -- -- -- -- - -- -- -- -- -- -- -- - -- -- -- -- -- - -II Imillion US $ (1) .million US $ (1) .million S/Y I

… I ……………- _---_-_---------- ---1 1989 1 II 1990 1 9.9 . 6.5 70.14 . 2.4 111991 1 34.1 . 19.3 40.7 70.50 . 4.8 II 1992 1 60.8 . 27.4 81.6 70.54 . 7.2 I11993 1 103.7 17.1 156.8 90.05 . 1.0 9.4 11 1994 I 108.0 6.5 189.5 54.90 . 1.9 11.3 II 1995 I 77.8 19.7 212.3 60.89 . 2.5 13.3 1I 1996 1 50.0 50.5 268.88 . 11.1 22.4 '1 1997 1 6.3 7.7 108.26 . 11.7 26.0 11 1998 1 125.44 . 12.9 30.2 1I 1999 1 7.3 146.02 . 12.9 35.2 1I 2000 I 22.1 168.66 . 12.9 40.8 11 2001 1 39.4 198.74 . 12.9 47.5 112002 1 46.4 165.30 . 12.9 53.1 112003 I 26.4 167.55 . 12.9 58.7 11 2004 I 4.5 166.91 . 12.9 64.4 112005 I 168.15 . 15.4 70.0 11 2006 1 167.14 . 15.4 75.7 112007 1 159.36 . 15.4 81.0 1

_- -- -- -- -- -- -- -- - -- -- -- -- -- -- -- -- - -- -- -- -- -- -- -- -

_ I-------------------------------------------------------------------I I T O T A L C O S T . G A S SU P P L Y I

I (I n c r e m e n t a ) (I n c r e m e n t a l ) II ICAPITAL OPERAT. TOTAL . Yearly Cumulat. I

… …I-------------------------------------------------------------------_II Imilion US $ Mill.M3/Y BCF /Y BCF I

…------I ……………--- -- -- -- -- -- -119891 . . I11990 1 86.51 . 86.51. -011991 1164.56 .164.56 . -0 I1 1992 1 240.34 . 240.34 . 591 20.9 21 11 1993 1 367.71 10.41 . 378.12 1182 41.7 63 1I 1994 I 358.90 13.16 372.06 1773 62.6 125 II 1995 I 370.67 15.81 . 386.48 2363 83.4 209 11 1996 1 369.35 33.47 . 402.82 2955 104.3 313 11 1997 1 122.22 37.71 . 159.93 3546 125.2 438 11 1998 I 125.44 43.14 . 168.58 4136 146.0 584 II 1999 1 153.31 48.06 . 201.37 4728 166.9 751 11 2000 1 190.77 53.74 . 244.51 4728 166.9 918 11 2001 1238.16 60.43 . 298.59 5201 183.6 1102 11 2002 1 211.75 66.00 277.75 5910 208.6 1310 11 2003 1 193.94 71.64 . 265.58 6382 225.3 1535 11 2004 I 171.45 77.27 . 248.72 7564 267.0 1802 I1 2005 1 168.15 85.43 . 253.58 7565 267.0 2069 11 2006 1 167.14 91.06 . 258.20 8155 287.9 2357 11 2007 I 159.36 96.43 . 255.79 8156 287.9 2645 1 '

--- … _ _I… _

(1) e x c I u d i n g t a x e s o n i m p o r t e d m a t e r i a 1(27.5 % of material cost)

I…-- - - - - - - - - - - -I DISCOUNT RATE % I 0 8 11 . 13 151I… II CUMULATED 0 C F M.$ I 4663.5 2387.9 1942.7 . 1711.9 1520.7 1I GAS DISCOUNT. VOL BCF I 2645 1031 755 . 621 515 1-- - - - - - - - - - - -… - - - - - - - - - - II A.I.C. (S/ MMBTU) I 1.43 1.87 2.08 2.23 2.39 1I S/ GCal) I 5.67 7.42 8.25 8.85 9.48 1I A.I.C. (S/ MCF) I 1.76 2.32 2.57 2.76 2.95 1I (W o n / 143) 1 41.2 53.9 59.9 64.2 68.9 1- - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

GAS LHV BTU /CFT 1236 Exchange rate-KCal/M3 11000 660 Won /US S

11- 149 - Page 10 of 10

KY ONG IN/ CHUNG CHO NG/ Y ONG NAM/ HO NAM

S c e n a r i o 0

I n c I u d i n g T a x e s (1)

I I C A P I T A L I N V E S T M E N T .OPERATION COST II I IL 00 TERMINAL 3 rd . PYONG PIPE OISTRIB-. I1 13 Tanks I Tank 1 Termin. TAEK LINES UTION .Terminal Network I

I Imillion US $ .million US S million t/Y I

1 1989 1' 1990 1 11.5 . 7.6 70.14 . 2.4 1I 1991 1 39.8 . 22.5 43.8 70.50 . 4.8 i1 1992 1 70.9 . 32.0 87.9 70.54 . 7.2 11 1993 1 121.0 20.0 168.9 90.05 . 1.0 9.4 11 1994 1 126.0 7.6 204.1 54.90 . 1.9 11.3 11 1995 1 90.8 23.0 228.6 60.89 . 2.5 13.3 11 1996 1 58.3 54.4 268.88 . 11.1 22.4 11 1997 1 7.3 8.3 108.26 . 11.7 26.0 11 1998 1 125.44 . 12.9 30.2 1I 1999 1 8.5 146.02 . 12.9 35.2 11 2000 1 25.8 168.66 . 12.9 40.8 11 2001 1 46.0 198.74 . 12.9 47.5 11 2002 1 54.2 165.30 . 12.9 53.1 11 2003 1 30.8 167.55 . 12.9 58.7 11 2004 1 5.3 166.91 . 12.9 64.4 11 2005 1 168.15 . 15.4 70.0 11 2006 1 167.14 . 15.4 75.7 11 2007 1 159.36 . 15.4 81.0 1- - - - - - -…-- - - - - - - - - - - -

(1) Breakdown of TERMINAL cost :Material 52 p.centConstruction 31 p.centEngineering/ 17 p.centOther

PIPELINE cost : Material 26 p.centConstruction 56 p.centEngineering/ 18 p.centOther

Taxes are set at 27.5 p.cent of imported material costincluding 22.5 % of customs duty.

S U M M A R Y O F I N V E S T M E N T S C H E D U L E

I I T o t a I T e r m i n a Is II P e r i o I . PYONG IL DO 3RO . PIPE DISTRIB- II I . TAEK TERMINAL. LINES UTION I

I .m i i o n U SS . I

…I~~~~~~~~~~~~~~I I . .II I . .I

I 9 9 0 - I 9 9 3 1 927.1. 82.1 243.2 . 300.6 301.2!I I . .II I . .I

II 9 9 4 - 1 9 9 7 1 1301.3. 7.6 305.4 . 495.4 492.9 1I ~ ~ ~~I . .I

I I . .II1 9 9 8 - 2 0 0 1 1 719.2. 80.3 . 638.9 1I I..iI I . I12 0 0 2 - 2 0 0 6 1 758.2. 90.3 . 667.9 1I I

I I..II T O T A L 1 3705.8 . 260.3 548.6 . 796.0 2100.9 1I I . .- II… … … … … … ……_ _…__ _ _I

- 150 -

Page 1 of 10

KOREA

GAS UTILIZATION STUDY

Economic Cost of LNG Supply

Scenario .A. :KYONGIN AREA

I ncrementa l start i ng i n 1 990

LNG Pri ce 1 ( LNG F08 90% Crude Oi l)

I I L N G SUPPLY . G A S V A L U E .L N G .ECONOMIC II .RESIDENT. POIWER . SUPPLY .BENEFIT IITotal Increm. . INDUSTRY TOTAL . COST . I

I I 1000 Tons/Y . M i l l i o n U S $ . Mill. S. Mill. $ I

1 1989 1 2000 2000 . 54.7 26.9 377.4 459.0 . II1990 1 2000 0 . 23.6 11.2 -3.3 31.5 79.1 -47.5 11 1991 1 2000 -O . 51.0 24.1 -8.3 66.8 126.3 -59.6 11 1992 1 2500 500 . 74.3 36.4 129.7 240.5 286.8 -46.3 1! 1993 1 2940 940 95.6 49.0 262.4 407.0 393.5 13.5 11 1994 1 3400 1400 117.8 57.2 406.7 581.7 475.4 106.3 111995 1 3900 1900 141.3 65.9 537.2 744.4 600.2 144.3 1! 1996 1 4000 2000 170.0 74.7 558.6 803.3 641.6 161.6 i11997 1 4400 2400 202.5 83.5 664.8 950.8 709.1 241.7 1! 1998 1 4800 2800 239.7 90.1 790.3 1120.1 785.6 334.5 1! 1999 1 5100 3100 279.4 97.5 873.3 1250.2 881.9 368.3 1! 2000 1 4950 2950 321.4 106.3 798.9 1226.6 865.3 361.3 1! 2001 1 5100 3100 364.6 117.9 813.3 1295.8 935.3 360.6 1! 2002 1 5450 3450 407.6 125.6 923.3 1456.4 1050.5 405.9 1I 2003 i 5750 3750 444.0 132.1 984.0 1560.1 1151.1 409.0 1I2004 1 6350 4350 480.5 138.5 1163.4 1782.4 1320.2 462.2 112005 1 6350 4350 516.4 145.4 1125.6 1787.4 1302.6 484.8 11 2006 1 6450 4450 552.8 152.0 1120.6 1825.4 1311.5 513.9 11 2007 1 6450 4450 588.6 156.1 1086.1 1830.8 1304.0 526.8 1-- - - - - - - - - - - - - - - - - - - -… - - - - - - - - - - - - - - - - - - -Present Value at d.r. Total

13 p.cent Resident.Industry Power Value Cost Benefit

US $/GCal 30.59 22.96 34.93 32.17 25.48 6.69US $/MMBTU 7.71 5.79 8.80 8.11 6.42 1.69W o n / M3 222.1 166.7 253.6 233.6 185.0 48.6Mill.US$ 1229 452 3096 4777 3784 993Billion M3 3.65 1.79 8.06 13.50 13.50 13.50

Presenx Value at d.r.8 p.cent

US $/GCaI 30.7P 23.32 28.73 28.60 24.72 3.89US $/MMBTU 7.76 5.88 7.24 7.21 6.23 0.98W o n / M3 223.4 169.3 208.6 207.7 179.4 28.2Mill.US$ 2005 705 4184 6894 5957 937Billion M3 5.92 2.75 13.24 21.91 21.91 21.91

Annex 12- 151 - Page 2 of 10

E C O N OM I C C O S T O F L N G S U P P L Y

S c e n a r i o .A . :K Y O N G I N A R E A

L N G P r i c e 1 ( L N G F OB 9 0 % C r u d e O i l)

I I L N G SUPPLY .L N G COST CIF . INFRASTRUCTURE .L N G II I . .Pipes Distribution . SUPPLY IITotal Increm. . Incremental .Terminal . COST I

I … _ _ __I…-- - - - - - - - - - - - - - - - -I I 1000 Tons/Y . $/MMBTU Mill. $ . Million S . Mill. S 'I…__ __I… … …_…_…_…_… _…_ …_------ -I1 1989 1 2000 2000 . 3.53 364.3 . II 1990 1 2000 0 . 3.82 0.1 6.5 72.5 79.1 11 1991 1 2000 -O . 3.91 -0.1 51.1 75.3 126.3 111992 1 2500 500 . 4.01 103.5 105.6 77.7 286.8 111993 1 2940 940 4.10 198.7 122.9 71.8 393.5 11 1994 I 3400 1400 4.20 303.4 111.6 60.5 475.4 111995 1 3900 1900 4.34 425.4 110.0 64.8 600.2 11 1996 1 4000 2000 4.48 462.3 105.9 73.3 541.6 11 1997 1 4400 2400 4.62 572.1 58.4 78.7 709.1 111998 1 4800 2800 4.77 689.2 15.9 80.6 785.6 111999 1 5100 3100 4.87 778.8 9.6 93.5 881.9 11 2000 1 4950 2950 4.96 755.0 9.6 100.7 865.3 11 2001 1 5100 3100 5.06 809.4 16.9 108.9 935.3 112002 1 5450 3450 5.16 918.5 31.7 100.2 1050.5 1I 2003 I 5750 3750 5.16 998.3 49.0 103.8 1151.1 I1 2004 1 6350 4350 5.16 1158.2 56.0 106.0 1320.2 1I2005 1 6350 4350 5.16 1158.1 36.0 108.5 1302.6 11 2006 1 6450 4450 5.16 1184.8 15.5 111.2 1311.5 11 2007 1 6450 4450 5.16 1184.8 12.1 107.0 1304.0 1

…--

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL

13 p.cent Pipeline COSTUS $/GCal 18.95 2.84 9.17 25.48US $/MMBTU 4.77 0.72 2.31 6.42W o n I M3 137.5 20.6 66.6 185.0

Mill.US$ 2813 422 549 3784Billion M3 13.50 13.50 5.44 13.50

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL8 p.cent Pipeline COST

US S/GCal 19.21 2.28 8.15 24.72

US $/MMBTU 4.84 0.57 2.05 6.23W o n I M3 139.5 16.6 59.2 179.4

Mill.US$ 4630 550 778 5957Billion M3 21.91 21.91 8.67 21.91

12Page 3 of 10

- 152 -

E C O N O M I C B E H E F I T O f G A S U T I L I Z A T I O N

S c e n a r i o B : K Y O N G I N + C H U N G C H O N G A R E A

I n c r e m e n t a l s t a r t i n g i n 1 9 9 0

L N G P r i c e 1 ( L N G F 0 9 0 % C r u d e 0 1 )

I I L N G SUPPLY G A S V A L U E L N G .ECONOMIC It I .RESTOENT. POWER . SUPPLY .BENEFIT I

ITotal Increm. . INDUSTRY TOTAL . COST . II … l__ I ……_… _…_…_--- --- _---- -- -- _-- - - -I

I 1000 Tons/Y . M 1 1 o n U S $ . Hill. $. Mill. $ II …_ l _ I--- -- --- -- -- --- -- -- --- -- -- --- -- --- -- -- --- -- -- --- -- --1 1989 1 2000 2000 . 54.7 26.9 377.4 459.0 . Ii1990 I 2000 0 . 23.6 11.2 -3.3 31.5 79.1 -47.5 111991 1 2000 -O . 51.0 24.1 -8.3 66.8 144.9 -78.1 I11992 I 2500 500 . 74.3 36.4 129.7 240.5 324.3 -83.9 1

11993 I 3000 1000 112.8 53.5 262.4 428.6 471.4 -42.8 I

1 1994 1 3500 1500 140.3 63.0 412.5 615.8 502.7 113.2 111995 i 4000 2000 170.7 73.9 536.1 780.6 632.2 148.4 I11996 I 4150 2150 209.3 84.6 562.4 856.4 694.2 162.1 I

1 1997 1 4600 2600 248.4 94.6 678.5 1021.6 761.8 259.8 II 1998 I 5000 3000 296.3 103.4 794.1 1193.8 847.6 346.2 1I 1999 1 5400 3400 346.4 112.0 899.9 1358.3 967.5 390.8 1I 2000 1 5400 3400 402.1 122.2 861.8 1386.2 995.1 391.1 1t 2001 1 5450 3450 462.6 135.3 830.4 1428.2 1046.1 382.2 1I 2002 I 5800 3800 521.6 144.5 927.2 1593.3 1162.5 430.8 11 2003 1 6150 4150 573.1 152.1 991.1 1716.3 1277.0 439.3 1

1 2004 1 7000 5000 625.2 159.7 1238.5 2023.4 1514.0 509.3 I

I 2005 I 7000 5000 676.3 168.1 1186.5 2030.9 1496.9 534.0 II 2006 I 7100 5100 727.6 176.0 1168.1 2071.6 1505.4 566.2 112007 1 7100 5100 776.9 181.6 1120.7 2079.3 1497.4 581.8 1

- - - - - - - - - - - - - - - - - - -… - - - - - - - - - - - - - - - - - -Present Value at d.r. Total

13 p.cent Resident.Industry Power Value Cost Benefit

US $/GCal 30.76 22.77 34.60 31.83 25.75 6.08

US $/MMBTU 7.75 5.74 8.72 8.02 6.49 1.53W o n / M3 223.3 165.3 251.2 231.1 186.9 44.1Hill.US$ 1517 507 3168 5192 4200 992

Billion M3 4.48 2.02 8.32 14.83 14.83 14.83

ilresent Value at d.r.

8 p.centUS S/GCal 30.93 23.10 28.58 28.59 24.91 3.68US $/KNBTU 7.79 5.82 7.20 7.20 6.28 0.93W o n / M3 224.6 167.7 207.5 207.5 180.8 26.7Mill.US$ 2504 796 4310 7611 6631 980

Billion H3 7.36 3.13 13.71 24.20 24.20 24.20

Page 4 of 10- 153 -

E C ON NO M I C C O S T O F L N G S U P P L Y

S c e n a r i o B : K Y O N G I N + C H U N G C H O N G A R E A

L N G P r i c e 1 ( L NG F O B 9 0 C r u de O I )

I I L N G SUPPLY .L N G COST CIF . INFRASTRUCTURE .L N G II .Pipes Distribution . SUPPLY I

I ITotal Increm.. Incremental .Terminal . COST I…___ _ I----------------------------------------------------------------------- _-I

I I 1000 Tons/Y . $/MMBTU Mill. $ . Nillion $ . Mill. $ I…__ __ I------------ ----------- ----------- ------------ ----------- -----------

I 1989 1 2000 2000 . 3.53 364.3 II 1990 1 2000 0 . 3.82 0.1 6.5 72.5 79.1 I11991 1 2000 -0 . 3.91 -0.1 69.7 75.3 144.9 1I 1992 I 2500 500 . 4.01 103.5 143.1 77.7 324.3 I11993 I 3000 1000 4.10 211.5 160.4 99.5 471.4 111994 I 3500 1500 4.20 325.0 111.6 66.0 502.7 11 1995 I 4000 2000 4.34 447.9 110.0 74.3 632.2 I11996 I 4150 2150 4.48 497.0 110.9 86.2 694.2 I11997 I 4600 2600 4.62 619.8 58.4 83.6 761.8 1I 1998 I 5000 3000 4.77 738.2 15.9 93.5 847.6 I11999 1 5400 3400 4.87 854.3 9.6 103.6 967.5 1! 2000 I 5400 3400 4.96 870.1 9.6 115.4 995.1 11 2001 1 5450 3450 5.06 900.8 16.9 128.4 1046.1 1I 2002 I 5800 3800 5.16 1011.7 31.7 119.1 1162.5 II 2003 I 6150 4150 5.16 1105.0 49.0 123.0 1277.0 I! 2004 I 7000 5000 5.16 1331.2 56.0 126.8 1514.0 II 2005 I 7000 5000 5.16 1331.1 36.0 129.8 1496.9 1I 2006 I 7100 5100 5.16 1357.9 15.5 132.0 1505.4 II 2007 I 7100 5100 5.16 1357.8 12.1 127.5 1497.4 I-------- ------- ------- ------- ------- ------- ------- ------- ------- -------

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL13 p.cent Pipeline COST

US $/GCal 18.99 2.99 8.59 25.75US S/MNBTU 4.79 0.75 2.16 6.49W o n / M3 137.9 21.7 62.4 186.9Mill.US$ 3097 488 615 4200Billion M3 14.83 14.83 6.51 14.83

Present Value at d.r. LNG CIF TERNINAL DISTRIB. LNG TOTAL8 p.cent Pipeline COST

US $/GCal 19.25 2.35 7.62 24.91US $/MMBTU 4.85 0.59 1.92 6.28W o n / M3 139.7 17.1 55.4 180.8Mill.US$ 5125 626 880 6631Billion M3 24.20 24.20 10.49 24.20

Page 5 of 10- 154 -

E CONOM I C BE NE F I T OF GAS UT I L I ZAT I ON

Scenario C :KYONGIN/ CHUNGCHONG/YONGNAN

I n c r e m e n t a l s t a r t 1 n g i n 1 9 9 0

L N G P r i c e 1 ( L NG F O B 9 0 % C r u de O i )

I I L N G SUPPLY G A S V A L U E .L N G.ECONOMIC II I .RESIDENT. POWER . SUPPLY .BENEFIT II ITotal Increm. . INDUSTRY TOTAL .COST . I

… _ __ I------------------ ------------------ ------------------ --------------- -II I 1000 Tons/Y . M i i o n U S $ . Nill. $. Hill. $ I…_ _ _I------ ------ ------ ----- ------ ------ ------ ----- ------ ------ -----

1 1989 1 2000 2000 . 54.7 26.9 377.4 459.0 . II 120 1 2000 -O . 23.6 11.2 -3.4 31.4 88.8 -57.4 1I 1991 1 2000 -O . 51.0 24.1 -8.2 66.8 169.3 -102.5 11 1992 1 2500 500 . 74.3 36.4 129.7 240.5 351.0 -110.5 I1 1993 1 3000 1000 114.3 53.5 262.3 430.0 563.6 -133.6 11 1994 1 3500 1500 142.0 63.0 412.5 617.6 622.3 -4.7 11 1995 1 4000 1999 172.6 73.9 535.8 782.2 736.6 45.6 11 1996 1 4400 2400 269.1 113.6 554.3 937.0 867.2 69.8 111997 1 4900 2900 320.5 130.3 669.7 1120.4 834.5 285.9 111998 1 5400 3400 383.8 146.2 798.1 1328.0 982.3 345.7 1I 1999 1 5800 3800 451.7 163.6 880.9 1496.1 1126.7 369.5 11 2000 1 5800 3800 527.9 184.3 816.1 1528.3 1178.9 349.4 11 2001 1 610C 4100 613.3 209.9 832.5 1655.6 1317.9 337.7 11 2002 1 6500 4500 696.2 231.2 915.3 1842.7 1441.0 401.7 11 2003 1 7000 4999 769.9 250.1 997.4 2017.4 1560.4 457.0 11 2004 1 7900 5900 844.2 268.5 1231.1 2343.8 1784.3 559.5 11 2005 1 7900 5899 917.2 287.9 1148.8 2353.9 1785.4 568.5 11 2006 1 8200 6200 991.1 306.9 1165.2 2463.2 1870.4 592.8 11 2007 1 8200 6200 1062.5 323.4 1087.7 2473.6 1866.5 607.0 1------ ----- ----- ----- ------ ----- --… -- ----- ------ ----- ----- ----- -----Present Value at d.r. Total

13 p.cent Resident.Industry Power Value Cost Benefit

US $/GCal 30.60 22.57 34.77 31.29 27.28 4.02US S/MBTU 7.71 5.69 8.76 7.89 6.87 1.01W o n / M3 222.1 163.9 252.4 227.2 198.0 29.1Mill.USS 1905 697 3133 5735 5000 736Billion M3 5.66 2.81 8.19 16.66 16.66 16.66

Present Value at d.r.8 p.cent

US $/GCal 30.73 22.81 28.65 28.40 26.20 2.20US $/NMBTU 7.74 5.75 7.22 7.16 6.60 0.56W o n / M3 223.1 165.6 208.0 206.2 190.2 16.0Mill.US$ 3201 1139 4251 8591 7924 667Billion N3 9.47 4.54 13.49 27.50 27.50 27.50

'age i) of 10

- 155 -

E C O N OM I C C O S T O F L N G S U P P L Y

S c e n a r i o C : K Y 0 N G I N / C H U N G C H O N G / Y O N G N A M

L N G P r i c e I ( L N G F O B 9 0 % C r u d e Oi il )

I L N G SUPPLY .L N G COST CIF . INFRASTRUCTURE .L N G II I .Pipes Distribution . SUPPLY I

ITotal Increm. . Incremental .Terminal . COST II… ____I………- II I 1000 Tons/Y . $/MMBTU Mill. S . Million $ . Mill. S Il I -_ I…_…_…_…_-_ -_ -_ -_ - _-_-_-_-__-_-_-____-_-_-_- _--1 1989 I 2000 2000 3.53 364.3 II 1990 1 2000 -0 . 3.82 -0.1 16.4 72.5 88.8 111991 1 2000 -O . 3.91 -0.0 94.1 75.3 169.3 111992 1 2500 500 . 4.01 103.5 169.8 77.7 351.0 11 1993 1 3000 1000 4.10 211.5 252.7 99.5 563.6 111994 1 3500 1500 4.20 325.1 231.1 66.2 622.3 111995 1 4000 1999 4.34 447.7 214.7 74.2 736.6 1I1996 1 4400 2400 4.48 554.7 65.4 247.1 867.2 111997 1 4900 2900 4.62 691.3 24.4 118.9 834.5 111998 1 5400 3400 4.77 836.8 11.6 133.9 982.3 111999 1 5800 3800 4.87 954.7 18.9 153.0 1126.7 11 2000 1 5800 3800 4.96 972.6 33.7 172.6 1178.9 11 2001 1 6100 4100 5.06 1070.5 51.0 196.4 1317.9 1I 2002 1 6500 4500 5.16 1198.0 58.0 184.9 1441.0 11 2003 1 7000 4999 5.16 1331.0 38.0 191.4 1560.4 1I 2004 1 7900 5900 5.16 1570.7 17.5 196.0 1784.3 1I 2005 1 7900 5899 5.16 1570.6 14.1 200.7 1785.4 11 2006 1 8200 6200 5.16 1650.6 14.1 205.7 1870.4 11 2007 1 8200 6200 5.16 1650.6 14.1 201.8 1866.5 1

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL13 p.cent Pipeline COST

US $/GCal 19.08 3.73 8.80 27.28US S/MMBTU 4.81 0.94 2.22 6.87W o n l M3 138.5 27.1 63.9 198.0Mill.US$ 3497 683 819 5000Billion M3 16.66 16.66 8.47 16.66

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL

8 p.cent Pipeline COSTUS $/GCal 19.33 2.85 7.89 26.20US $/MMBTU 4.87 0.72 1.99 6.60W o n l M3 140.3 20.7 57.3 190.2

Nill.USS 5847 861 1216 7924

Billion M3 27.50 27.50 14.01 27.50

12Page 7 of 10

- 156 -

E C O N OM I C 8 E N E F I T O F G A S U T I L I Z A T I O N

S c e n a r i o C 1. : KY ONG IN/ CHUNG CHO NG/ Y ONG NAN

I n c r e m e n t a l s t a r t i n g i n 1 9 9 0

L N G P r I c e 1 ( L NG F O B 9 0 % C r u de O i )I…_-- _-- - -- - -- -- - -- - -- - -- - -- -- - -- - -- - -- -- - _- - -- - -- -

I L N G SUPPLY . G A S V A L U E . L N G .ECONOMIC I

I .RESIDENT. POWER . SUPPLY .BENEFIT II ITotal Increm. . INDUSTRY TOTAL . COSI . II… _ _ ___I………_… _….…_…_-- -- -II I 1000 Tens/Y . Mi i o n U S $ . Mill. $. Mill. $ 'I …__ _ I----- ---- ----- ---- ---- ----- ---- ---- ----- ---- ---- ----- ---- -- -I11989 I 2000 2000 . 54.7 26.9 377.4 459.0 . I11990 I 2000 -O . 23.6 11.2 -3.4 31.4 88.8 -57.4 I11991 1 2000 -O . 51.0 24.1 -8.2 66.8 169.3 -102.5 I11992 I 2500 500 . 74.3 36.4 129.7 240.5 351.0 -110.5 II 1993 I 3000 1000 114.3 53.5 262.3 430.0 563.6 -133.6 I11994 I 3500 1500 142.0 63.0 412.5 617.6 622.3 -4.7 I11995 I 4000 1999 172.6 73.9 535.8 782.2 736.6 45.6 II 1996 I 5000 2999 269.1 113.6 762.1 1144.8 1005.8 139.0 I11997 I 5000 3000 320.5 130.3 728.0 1178.7 858.2 320.5 I11998 1 6000 4000 383.8 146.2 1023.5 1553.4 1129.9 423.5 111999 I 7000 5000 451.7 163.6 1295.5 1910.7 1434.8 475.9 II 2000 I 7000 5000 527.9 184.3 1233.7 1945.9 1505.2 440.7 II 2001 I 7000 5000 613.3 209.9 1155.3 1978.5 1580.2 398.3 II 2002 I 8500 6500 696.2 231.2 1601.1 2528.5 1990.5 538.0 1I 2003 1 8500 6500 769.9 250.1 1518.8 2538.8 1966.4 572.4 II 2004 I 9500 7500 844.2 268.5 1785.4 2898.1 2210.3 687.8 II 2005 1 9500 7500 917.2 287.9 1703.0 2908.1 2212.7 695.4 II 2006 I 10000 8000 991.1 306.9 1785.4 3083.3 2351.0 732.3 II 2007 I 10000 8000 1062.5 323.4 1707.7 3093.6 2347.0 746.6 I---------------------------------------- ---------------------------------------Present Value at d.r. Total

13 p.cent Resident.Industry Power Value Cost Benefit

US $/GCal 30.60 22.57 32.46 30.56 26.08 4.48US $/HMBTU 7.71 5.69 8.18 7.70 6.57 1.13W o n / M3 222.1 163.9 235.7 221.9 189.3 32.5Mill.US$ 1905 697 4171 6774 5780 993Billion M3 5.66 2.81 11.68 20.15 20.15 20.15

Present Value at d.r.8 p.cent

US $/GCal 30.73 22.81 26.92 27.43 25.13 2.30US $/MMBTU 7.74 5.75 6.78 6.91 6.33 0.58W o n / M3 223.1 165.6 195.4 199.2 182.4 16.7Mill.US$ 3201 1139 5843 10184 9328 855Billion M3 9.47 4.54 19.74 33.75 33.75 33.75

Page 8 of 10

- 157 -

ECONOMIC C0ST OF LNG SUPPLY

S c e n a r io C1. :KYONGIN/ CHUNGC HONG/YONGNAM

LNG P r i c e 1 (LNG F O B 9 0 % C r u d e O I )

I L N G SUPPLY .L N G COST CIF . INFRASTRUCTURE . L N G II I .Pipes Distribution . SUPPLY II ITotal Increm. . Incremental .Terminal . COST I

… _ _I…-- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -I 1000 Tons/Y . S/MMBTU Mill. $ . Million s . Mill. S I

I… I …………-I 1989 I 2000 2000 . 3.53 364.3 .

I 1990 1 2000 -0 . 3.82 -0.1 16.4 72.5 88.8 II 1991 I 2000 -O . 3.91 -0.0 94.1 75.3 169.3 II 1992 I 2500 500 . 4.01 103.5 169.8 77.7 351.0 II 1993 I 3000 1000 4.10 211.5 252.7 99.5 563.6 II 1994 I 3500 1500 4.20 325.1 231.1 66.2 622.3 I11995 I 4000 1999 4.34 447.7 214.7 74.2 736.6 I; 1996 I 5000 2999 4.48 693.3 65.4 247.1 1005.8 I11997 I 5000 3000 4.62 715.0 24.4 118.9 858.2 II 1998 I 6000 4000 4.77 984.4 11.6 133.9 1129.9 I11999 I 7000 5000 4.87 1256.4 25.4 153.0 1434.8 I; 2000 I 7000 5000 4.96 1279.6 53.0 172.6 1505.2 1I 2001 I 7000 5000 5.06 1305.3 78.4 196.4 1580.2 II 2002 I 8500 6500 5.16 1730.4 75.2 184.9 1990.5 II 2003 I 8500 6500 5.16 1730.5 44.5 191.4 1966.4 II 2004 I 9500 7500 5.16 1996.7 17.5 196.0 2210.3 II 2005 I 9500 7500 5.16 1996.6 15.4 200.7 2212.7 I1 2006 I 10000 8000 5.16 2129.9 15.4 205.7 2351.0 II 2007 1 10000 8000 5.16 2129.8 15.4 201.8 2347.0 I

---

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL13 p.cent Pipeline COST

US S/GCal 19.22 3.16 8.80 26.08US S/MMBTU 4.84 0.80 2.22 6.57IW o n / M3 139.5 23.0 63.9 189.3Mill.USS 4259 702 819 5780Billion M3 20.15 20.15 8.47 20.15

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL8 p.cent Pipeline COST

US $/GCal 19.45 2.40 7.89 25.13US $/MMBTU 4.90 0.61 1.99 6.33W o n / M3 141.2 17.5 57.3 182.4M1ll.US$ 7220 892 1216 9328Billion M3 33.75 33.75 14.01 33.75

Page 9 of 10

- 158 -

ECONOMIC BENEF IT OF GAS UTIL I ZATION

KYONGIN/ CHUNGCHONG/YONGNAM/HONAM- Scen. D

Incremental starting in 1990

NG Pr i ce 1 ( LNG FOB 90% Crude 0 1i I

I I L N G SUPPLY , G A S V A L U E L N G ECONOMIC II I .RESIDENT. POWER . SUPPLY .BENEFIT I

ITotal Increm. . INDUSTRY TOTAL . COST . II …_ _ _I----- ---- ----- ---- ---- ----- ---- ---- ----- ---- ---- ----- ---- -- -II I 1000 Tons/Y M i I i o n U S $ . Mill. $. N1ll. $ II …_ I------ ------ ------ ------ ------ ----- ------ ------ ------ ------ --- -I1 1989 1 2000 2000 . 54.7 26.9 377.4 459.0 , II 1990 1 2000 -0 . 23.6 11.2 -3.4 31.4 88.8 -57.4 I11991 1 2000 -O . 51.0 24.1 -8.2 66.8 169.3 -102.5 1I 1992 1 2500 500 . 74.3 36.4 129.7 240.5 351.0 -110.5 I11993 1 3000 1000 114.3 53.5 262.3 430.0 589.6 -159.6 11 1994 1 3500 1500 142.0 63.0 412.5 617.6 697.1 -79.5 i11995 1 4000 1999 172.6 73.9 535.8 782.2 834.2 -52.0 111996 1 4500 2500 282.3 123.5 561.4 967.2 980.7 -13.5 111997 1 5000 3000 338.9 143.2 669.8 1151.9 875.1 276.8 II 1998 I 5500 3499 410.6 163.0 787.2 1360.7 1029.8 330.9 111999 1 6000 4000 491.1 183.7 887.7 1562.5 1206.4 356.2 11 2000 1 6000 4000 581.1 211.3 804.6 1596.9 1268.2 328.7 1I 2001 1 6400 4400 685.1 246.4 827.8 1759.4 1447.4 312.0 II 2002 I 7000 5000 780.3 273.8 960.8 2014.9 1608.9 406.0 I1 2003 1 7400 5400 865.3 298.4 994.1 2157.9 1703.1 454.7 11 2004 1 8400 6400 951.0 322.4 1245.0 2518.4 1952.5 565.9 11 2005 I 8400 6400 1035.6 347.8 1146.5 2529.8 1957.4 572.4 11 2006 1 8900 6899 1120.8 372.3 1213.0 2706.1 2095.1 611.1 I1 2007 1 8900 6900 1203.7 394.6 1119.6 2717.9 2092.7 625.2 1

…----- ----- ----- ----- ------ ----- ----- ----- ------ ----- ----- ----- -----Present Value at d.r. Total

13 p.cent Resident.Industry Power Value Cost Benefit

US $/GCal 30.49 22.52 34.69 31.03 28.03 3.00US S/MMBTU 7.68 5.68 8.74 7.82 7.06 0.76W o n / H3 221.4 163.5 251.9 225.3 203.5 21.8Mill.US$ 2069 784 3150 6003 5423 580Billion M3 6.17 3.17 8.26 17.59 17.59 17.59

Present Value at d.r.8 p.cent

US $/GCal 30.61 22.74 28.62 28.28 26.85 1.44US S/NMBTU 7.71 5.73 7.21 7.13 6.76 0.36W o n / M3 222.2 165.1 207.8 205.3 194.9 10.4Nill.USS 3504 1298 4286 9088 8625 462Billion M3 10.41 5.19 13.61 29.21 29.21 29.21

12Page 10 of 10

- 159 -

E C O N OM I C C O S T O F L N G S U P P L Y S c e n a r i o D

KYONGIN/ CHUNGCHONG/YONGNAM/HONAM

L N G P r i c e I ( L NG F OB 9 0 % C r u de 0 l)

I I L N G SUPPLY .L N G COST CIF . [lFRASTRUCTURE .L N G II I . .Pipes Distribution . SUPPLY II ITotal Increm. . Incremental .Termina! . COST I

I I 1000 Tons/Y . S/MMBTU Mill. $ . Million $ . Nill. $ I

I 1989 1 2000 2000 . 3.53 364.3 .I

I 1990 1 2000 -0 . 3.82 -0.1 16.4 72.5 88.8 I11991 1 2000 -0 . 3.91 -0.0 94.1 75.3 169.3 11IM 1 2500 500 . 4.01 103.5 169.8 71.7 351.0 1

1 1993 1 3000 1000 4.10 211.5 278.7 99.5 589.b I1 1994 1 3500 1500 4.20 325.1 305.9 66.2 697.1 11 1995 1 4000 1999 4.34 447.7 312.3 74.2 834.2 11 1996 1 4500 2500 4.48 577.8 111.6 291.2 980.7 111997 1 5000 3000 4.62 715.2 25.7 134.3 875.1 11 1998 1 5500 3499 4.77 861.2 12.9 155.7 1029.8 111999 1 6000 4000 4.87 1005.0 20.2 181.2 1206.4 11 2000 1 6000 4000 4.96 1023.7 35.0 209.5 1268.2 11 2001 1 6400 4400 5.06 1148.8 52.3 246.3 1447.4 I1 2002 1 7000 5000 5.16 1331.1 59.3 218.4 1608.9 11 2003 1 7400 5400 5.16 1437.6 39.3 226.3 1703.1 11 2004 1 8400 6400 5.16 1703.8 17.4 231.3 1952.5 11 2005 1 8400 6400 5.16 1703.8 15.4 238.2 1957.4 11 2006 1 8900 6899 5.16 1836.9 15.4 242.8 2095.1 11 2007 1 8900 6900 5.16 1836.9 15.4 240.4 2092.7 11…--------------------------------------------------------------------------------

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL13 p.cent Pipeline COST

US $/GCal 19.13 4.18 8.90 28.03US $/MNBTU 4.82 1.05 2.24 7.06W o n / M3 138.9 30.4 64.6 203.5Mil .US$ 3701 809 914 5423Billion M3 17.59 17.59 9.33 17.59

Present Value at d.r. LNG CIF TERMINAL DISTRIB. LNG TOTAL8 p.cent Pipeline COST

US SIGCal 19.38 3.19 8.02 26.85US $/JNBTU 4.88 0.80 2.02 6.76W o n 1 M3 140.7 23.1 58.2 194.9Mill.USS 6225 1024 1376 8625Billion M3 29.21 29.21 15.59 29.21

- 160- 13

KOREA

GAS UTILIZATION STUDY

AIR POLLUTION EMISSIONS FROM ENERGY USE

An important perspective in looking at present levels of airpollution in Korea is provided by an examination of the relative as well asabsolute pollution or emission intensity of each fuel together with thecurrent and future role of these fuels in the Korean energy balance.Tables 1 and 2, drawn from various sources, present some figures on theformer.

Table 1: -2 - Uncontrolled Emissions for Selected Fuels

Lower HeatingValue S02 Emissions

Sulfur -------_--- ---------------------------Fuels Content (kcal/ unit) (lb SO /unit) (g 502(Gcal)

Natural Gas 0.02 11,000 /cum 0.0 tlO^6 cft 0Bunker C 1.6Z 9,400 /liter 251.2 /1000 gal 3,204Bunker C 2.5Z 9,400 /liter *92.5 (1000 gal 5,006Bunker C 4.0Z 9,400 iliter 628.0 t1000 gal 8,009Imported Coal 0.72 6,300 /kg 26.6 /ton 2,111Coal Briquettes 2.OZ* 4,167 /kg 76.0 (ton 9,119Diesel - stationary 0.42 8,720 /liter 56.8 /1000 gal 781Diesel - mobile 8,720 (liter 27.0 11000 gal 371Gasoline - mobile 7,867 /liter 5.0 /1000 gal 76

* mission estimate.

Table 2: NOx - Uncontrolled Emissions for Selected Fuels

Lower HeatingValue NOx Emissions

Fuels (kcall unit) (lb NOx /unit) (g NOx/Gcal)

Natural Gas households 11,000 /cum 50 110^6 cft 73commercial 11,000 /cum 100 /10^6 cft 146industry 11,000 /cum 230 110^6 cft 335utility 11,000 /cum 390 110^6 cft 568

Bunker C industry 9,400 /liter 40 /1000 gal 510Bunker C utility 9,400 /liter 105 11000 gal 1,339

Imported Coal indlutil 6,300 /kg 18 (ton 1,429Coal Briquettes hshldlcom 4,167 /kg 6 (ton 720

Diesel - stat. hshld/com 8,720 /liter 12 ('000 gal 165

Diesel - mobile transport 8,720 (liter 370 !'000 gal 5,087Gasoline - m.obile transport 7,867 /liter 183 /'000 gal 2,789

[ORD 21915

U.S.S.R. 128' - 131'

C H I N DEMOCRATIC PEOPLE'S REPUBLICOF KOREA -

-> - _ _ .~ ~ ~ _ _ 32'30 3r30-

REP OF KOREA I 131'

Rfp orKoRIA JAPAN gCunchon 38'

% ~~~~~0t lsan Sanggye

_________________________ TERMINAL SEOUL Tonghae

Inchon :P n nogchon

undang

PYONC1AFK ogtaek -. 3"3r 1W&i taj 0 Chungiu

Onyan

Chngju

Pohang Q<

36'~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~6

ri~~~~~~~~~~~~ag

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f 2 AW J~~~~~~~~~~CiIn°w]usan

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REPUBLIC OF KOREA

PROPOSED GAS SYSTEM- Existing Pipe Line

Planned Pipe Lines

A Gas Terminal 34-4 1 .j, Major Ports

o Selected Cities

Urban Areas

Provinre Boundaries

Cheju LME

;,- ve 0 20 40 60 0 100 120 140 160

0 20 40 60 sO 100tMILES

125s 138' 127' 128' 128't

OCTOBER 1989

IBRD 21983R

'IO llsan Sanggye

No ~~~~~bBundang

)\>L1014'

.SEA

(-N t ...........SUWON CITY

Suwan

REPUBLIC OF KOREA

PROPOSED GAS SYSTEMSeoul Metropolitan Area

and Vicinities

-PROPOSED PIPELINES

-EXISTING PIPELINES

/ PROPOSED GAS TERMINALf 4/

ON(~~~~~~~~ A E~~~~~~~XISTING GAS TERMINAL

0 SELECTED CITIES

URBAN AREAS

Y0LA(.lL.K

d 9 KY( \ EPBLCOFKOE

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00

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JANUARY I 9