Respecto a los patrones geológicos

Pertamina (Indonesia), Petronas (Malaysia), Brunei LNG, Qatar LNG, Oman LNG

Owner and Operator of LNG Terminals and Gas Transmission Pipelines in Korea

Korea Gas Corporation (KOGAS)

Owners and Operators of Gas Distribution Pipelines in Korea

Seoul: Daehan City Gas, Hanjin City Gas, Kangnam City Gas, Kukdong City Gas, Samchully, Seoul City Gas Other Major Cities: Chungnam City Gas, Haeyang City Gas, Incheon City Gas,

Kyongdong City Gas, Pusan City Gas, Taegu City Gas

Kangwon Province: Chambit Wonju City Gas, Kangwon City Gas Chungbuk Province: Chongju City Gas

Chungnam Province: Chungbu City Gas, Hanseo City Gas (Hanbo Energy) Kyongbuk Province: Kumi City Gas, Pohang City Gas, Seorabol City Gas

Kyongnam Province: Kyungnam Energy, ShinA City Gas

Cheonbuk Province: Cheonbuk City Gas, Iksan City Gas, Kunsan City Gas Cheonnam Province: Chonnam City Gas, Daehwa City Gas, Mokpo City Gas

GAS MA R K E T RE F O R M GAS MARKET SKETCHES: KOREA

(SPAs) from KOGAS and free to sign new SPAs going forward. Divisions that deal with maintenance, design and engineering of gas facilities, as well as investment in gas production and tugging of LNG carriers, would also be spun off. KOGAS would then retain its LNG, pipeline and storage facilities but no supply function.102 However, details of the reform plan were still under

discussion in 2003. As an alternative to spinning off KOGAS import and wholesale trade functions, the government is considering allowing the entry of competing private companies into the market for these functions.103

At a later stage, the open access regime is to be extended to gas distribution. The regional distribution monopolies are to be unbundled into separate distribution and retail supply companies. Competing suppliers would then be able to use the distribution grid on non-discriminatory terms to bring gas to small residential and commercial customers. This would be a significant step since small consumers constitute two-fifths of Korea’s gas market.

MARKET MODEL AND COM P E T I T I O N

At present, the gas market in Korea would seem to fit most closely the wholesale competition model, although the extent of competition is rather limited. KOGAS purchases gas from several competing foreign producers and does so from the least cost bidders; in this sense, there is wholesale competition. But all of the foreign producers operate as vertically integrated monopolies in their home markets. And since all major import contracts are on a long-term, take-or-pay basis, there is very limited scope for competition from other producers. While there is some potential retail competition in the sense that large gas consumers are allowed to import LNG for their own use instead of buying it from KOGAS, no consumers had done so as of the end of 2002.

Looking to the future, however, Korea may better fit the customer choice model. As gas demand continues to grow, the market should accommodate imports from additional producers. Open access to LNG terminals, storage facilities and high-pressure pipelines, as envisioned in the gas industry reform plan, would allow effective competition for large industrial customers and electric power generators. Later on, open access to distribution pipelines would allow effective competition for small customers as well.

Korea’s gas and electricity markets are at present vertically integrated to a significant degree, not only because gas is provided to all power producers through a single buyer, but also because gas accounts for a sizeable share of power production and because long-term gas supply contracts are in place with a particular power producer. Natural gas accounted for 11 percent of electricity generation and 26 percent of electric generating capacity in Korea in 2000. A large share of gas use is by independent power producers (IPPs), which accounted for 14 percent of generating capacity. KOGAS has no financial interest in the electricity sector and should thus be willing, in principle, to supply gas to all competing electricity generators on a non-discriminatory basis. However, until 2006, the Korea Electric Power Company (KEPCO) is obliged to purchase a certain amount of gas under take-or-pay arrangements with KOGAS. Although the take-or-pay amount is negotiable, the arrangement apparently requires a greater use of natural gas for power production than would occur in a strict cost-minimising environment. Thus, it may put KEPCO at a competitive disadvantage while also restricting the available supply of gas to other power producers.104

Even after KEPCO’s take-or-pay obligations expire, significant integration will remain between Korea’s gas and power markets as long as KOGAS remains the dominant gas supplier. If all power producers are obliged to obtain gas from the same source, their gas costs are likely to be similar, so the effective scope for competition among their gas-fired power plants will be limited to capital and operating costs. With such a large share of generating capacity designed to use gas, the flexibility of power producers to shift to other fuels in response to higher prices will also be limited. Thus,

102 _{IEA (2002e), pages 101-103. IEEJ (2002a), pages 474-476.} 103 _{Ministry of Commerce, Industry and Energy (2003).}

104 _{IEA (2002e), pages 55 and 57. IPPs had 6,708 MW of generating capacity in 2000, or 14 percent of Korea’s 48,451} MW of generating capacity, of which 2,872 MW was gas-fired, 23 percent of Korea’s 12,698 MW of gas-fired capacity.

KOGAS has considerable market power to pass on inefficiencies that may occur in gas procurement, shipping, and processing, as well as in construction and operation of LNG facilities and pipelines, in higher gas prices to power producers.

Over the longer term, as competing suppliers appear in the gas market and IPPs play a growing role in the power market, the integration of gas and electricity markets should begin to dissipate. Pursuant to electricity industry restructuring plans that have passed the National Assembly, open access is to be provided to the electric transmission network after 2004 and to electric distribution grids after 2009. Thus there will soon be wholesale competition among electricity generators for sales to power distribution companies, and there will later be retail competition among generators for sales to final customers. So if gas market reform plans are implemented, there should be retail competition among gas producers for the business of electricity generators, and resulting savings in gas costs should be passed to both producers and consumers of electricity.

PRICE TRENDS

Natural gas prices in Korea declined steadily in the late 1980s and most of the 1990s, before rebounding in the late 1990s. For industrial customers, the real price in 2000 US$ declined by 26 percent from US$333 per tonne of oil equivalent in 1990 to US$246 per toe in 2000. The real price for households dropped by 18 percent from US$521 to US$427 per toe during the decade.105

Figure 47 Natural Gas Prices in Korea, 1987-2001

0 100 200 300 400 500 600 700 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Price in 2000 USD per toe

Household Industry

Sources: Korea Energy Economics Institute, IEA, IMF, US Department of Commerce

These price trends would appear to be due mainly to trends in international LNG prices according to the terms of long-term import contracts that KOGAS has negotiated. The average commodity price for gas imported into Korea at the start of 2000 was about 288 won per cubic metre, exclusive of handling charges, tariffs, excise taxes and surcharges. Including such additional

105 _{Korea Energy Economics Institute (2002), page 65. Nominal prices in US$ calculated by dividing prices in won per} cubic metre by a heat rate of 10,500 kcal per cubic metre, by prevailing exchange rates of won per US$ from IEA (2002b) page 338 and IMF (2002) page 629, and by 10 million kcal per toe. Real prices in US$ calculated by dividing nominal prices in US$ by implicit GDP deflators from US Department of Commerce.

GAS MA R K E T RE F O R M GAS MARKET SKETCHES: KOREA

items, the commodity price was about 326 won for electricity producers and 335 won for others. By contrast, the average transportation price for gas in Korea at the end of 2001 was just 78 won per cubic metre, including LNG terminal costs, pipeline transmission costs to the city gate and local distribution costs. Thus, direct and indirect LNG commodity costs account for roughly four-fifths of the delivered price of natural gas on average. It follows that changes in the costs of imported LNG dominate fluctuations in overall delivered gas prices.106

GAS MARKET REGULATIO N AND INFRASTRUCTURE POLICY GAS TRANSPORTATION INFRASTRUCTURE

Korea’s gas transportation infrastructure appears to be keeping pace with rapidly growing demand. LNG storage facilities at the end of 2002 included 26 tanks with a total capacity of 2.96 million cubic metres (Mcm). There are plans to substantially more than double LNG storage facilities over the next decade or so to include a total of 55 tanks with a capacity of 7.38 Mcm.107

The gas distribution network in Korea is well developed, and there are no plans to expand it further. The service areas of the city gas companies cover almost all the economy’s territory except for a few sparsely populated rural areas to which pipeline has not been laid.

INFRASTRUCTURE INVESTMENT INCENTIVES

Incentives for investment in new gas transmission infrastructure appear to be quite adequate. In its rates to gas users, KOGAS is allowed to recover all costs of investment in pipelines and LNG terminals, including borrowing costs, plus a 2 percent premium. At present, only KOGAS can invest in gas transmission infrastructure and collect regulated rates for its use. For purposes of ratemaking, gas transmission costs are divided into five functional categories: unloading, storage, regasification and injection, pipelines, and valve stations. Costs in each category are then allocated between power generating companies and city gas supply companies.108

Investment incentives for enhancement of gas distribution grids also appear to be sufficient. The distribution costs of city gas companies are typically recovered in rates through a cost-plus methodology in which a market-based rate of return is allowed on equity. Rates for each city gas company must be approved by the local government that has jurisdiction in its area.109

106 _{APERC (2002c), pages 30-31. Transportation charges vary by time and type of customer. They ranged from 26 to 46} won per cubic metre for electricity generators at the start of 2000, depending upon the season. They were 33 won for industrial customers, 46 won for commercial customers, and 107 won for residential heating and 134 won for residential cooling at the end of 2001.

107 _{Ministry of Commerce, Industry and Energy (2003).} 108 _{Ibid. APERC (2001a), page 66.}

M A L A Y S I A

GAS MARKET SETTING110

Malaysia is a major gas producer and exporter, with gas supplied to the economy almost entirely from domestic production.

n Gas production is projected nearly to double from 34.2 Mtoe in 2000 to 65.0 Mtoe

in 2020, but net exports as a share of production are projected to decline markedly from 48 percent to 38 percent due to growth in domestic demand and imports.

n Primary supply of gas to the domestic economy is projected to more than double

from 17.7 Mtoe in 2000 to 40.4 Mtoe in 2020, with average annual growth of 3.5 percent in the decade from 2000 to 2010 and 5.0 percent from 2010 to 2020. Figure 48 Evolution of Natural Gas Use in Malaysia, 1980-2020

1.2 9.6 13.1 24.0 2.8 4.0 6.3 5.3 7.7 10.1 1.0 2.0 3.9 0 5 10 15 20 25 30 35 40 45 1980 1990 2000 2010 2020

Million Tons Oil Equivalent

Other

Industrial

Electric

Very nearly all of Malaysia’s natural gas use is devoted to energy transformation and industry. About five-sixths of the economy’s gas is used in energy transformation. Of this portion, two- thirds goes to electricity generation and one-third to gas production, with the relative importance of electricity generation expected to grow over time. Almost all the remaining gas use is by industry.

n Use of gas for electric power generation is projected to substantially more than

double from 9.6 Mtoe in 2000 to 24.0 Mtoe in 2020, so that the power sector’s share of overall gas demand increases from 54 percent to 59 percent.

110 _{Data from APERC (2002a) and more detailed internal energy balance tables. Historical data for 1980 and 1990 were} compiled by the International Energy Agency (IEA). Projections for 2000, 2010 and 2020 were made by APERC.

GAS MA R K E T RE F O R M GAS MARKET SKETCHES: MALAYSIA

n Industrial use of gas is also expected to more than double from 2.8 Mtoe in 2000

to 6.3 Mtoe in 2020, while its market share remains just below 16 percent.

n “Other” gas use, primarily for gas production, is projected nearly to double from

5.3 Mtoe in 2000 to 10.1 Mtoe in 2020, while its share of the gas market falls from 30 percent to 25 percent.

GAS MARKET STRUCTURE AND OPERAT I O N