NED0-IC-00ER24

FEASIBILITY STUDY ON ENERGY SAVING AND THE REDUCTION OF C02 EMISSION AT PETROCHEMICAL CORPORATION OF SINGAPORE

March. 2001

New Energy and Industrial Technologies Development Organization (NEDO) Entrusted to JGC Corporation 020005071-4 BASIC SURVEY PROJECT FOR JOINT IMPLEMENTATION, ETC. 2000

FEASIBILITY STUDY ON ENERGY SAVING AND THE REDUCTION OF C02 EMISSION AT PETROCHEMICAL

CORPORATION OF SINGAPORE (PRIVATE) LIMITED

ENTRUSTED ORGANIZATION JGC CORPORATION

MARCH 2001

Study Purpose:

This report is for a project to execute revamping of units in order to save energy and reduce C02 based on data which were collected by the site surveys for the No, 1 Naphtha cracker and the related utility facilities in the plant of Petrochemical Corporation of Singapore (Private) Limited in Singapore. Preface

This report summarizes the results of the study on energy conservation and C02 reduction in the naphtha cracker and the related utility facilities in Complex I of the Petrochemical Corporation of Singapore (hereafter referred to as “PCS”) that was commissioned to the JGC Corporation by the New Energy and Industrial Technology Development Organization (NEDO) as a basic study for promoting joint implementation in fiscal 2000.

As a backdrop to this study, the third session of the Conference of the Parties to the United Nations Framework Convention on Climate Change (COP3) was held in Kyoto, Japan, in December 1997. At the session, the target of reducing greenhouse gas (e.g., CO?) emissions to prevent global warming was established in the Kyoto Protocol. The target for industrialized nations is to reduce their average emissions from 2008 through 2012 to levels at least 5% below their 1990 levels. Japan ’s target was set at 6%. The Kyoto Protocol also established various joint activities implemented by the industrialized nations, the Clean Development Mechanism, and emission trading with developing countries as mechanisms for attaining the targets. Japan intends to attain its target by maximizing the effect of these mechanisms.

In the naphtha cracker and the related utility facilities in Complex I of PCS (the Singaporean partner of this study), energy can be saved and a significant reduction of CO? (a greenhouse gas% will be possible. These results can be achieved in several ways. (1) Through the reconfiguration of the energy-balance of the entire complex system using pinch technology. (2) Through the introduction of the Advanced Recovery System (ARS). The ARS was designed by Stone & Webster (hereafter referred to as “S&W”), who licensed the technology to PCS at the time of the initial complex construction. (3) By adopting cogeneration system using a gas turbine generator (GTG) for the boiler which supplies steam to the naphtha cracker.

This study is intended to detect and ascertain projects to which the above Clean Development Mechanism can be applied, in order to confirm that the naphtha cracker and the related utility facilities can be functionally optimized and made more efficient by improving their heat-recovery/combustion systems, and to investigate their economic efficiencies.

- 1 - The study would not have been possible without the assistance of PCS, the government of Singapore, and all other parties concerned. We would like to express our gratitude for their support.

March 2001 Yoshihiro Shigehisa President & Representative Director JGC Corporation

- 2 - A report on the study concerning energy conservation and C02 reduction efforts at PCS

Contents Page Overview 1

1. BASICS OF PROJECT 1-1

1.1 Conditions of the Partner Country 1-1 1.1.1 Political, economic, and social conditions 1-1 1.1.2 Energy situations 1-13 1.1.3 The Need for Projects with Clean Development Mechanisms 1-24 1.2 The Need for Industries to Introduce Energy Conservation Technologies 1-25 1.3 Demand for, Significance of, and Impact of the Project, and Deployment of Output 1-26 in Similar Industries

2. IMPLEMENTATION OF THE PROJECT PLAN 2-1

2.1 Project Plan 2-1 2.1.1 Overview of project target area 2-1 2.1.2 Project details 2-4 (1) Merbau plant 2-4 (2) Project details 2-9 (3) Onsite study 2-9 2.1.3 Greenhouse gas under study and related issues 2-15 2.2 Overview of Implementation Sites (Companies) 2-15 2.2.1 On-site Interest 2-15 2.2.2 Facility conditions at Project site (company) 2-16 (General Outline, Specifications, Operating Conditions) 2.2.3 Project implementation capabilities of implementation sites (companies) 2-29 (1) Technical prowess 2-29 (2) Management 2-30 (3) Management infrastructure and management policy 2-30 (4) Financial support capability 2-30 (5) Personnel support capability 2-31 (6) Implementation system 2-31 2.2.4 Contents of Project for Project site (Company) and Specifications of 2-31 Facilities after Modifications 2.2.5 Split of Scope of Work and Supply between both parties for funds, facilities, 2-89 and services for project implementation 2.2.6 Preconditions and problems in project implementation 2-90 2.2.7 Project implementation schedule 2-90 2.3 Implementation of Financing Schedule 2-95 2.3.1Financial schedule for project implementation (required funds and 2-95 financing methods) 2.3.2Financing prospectus (plans of parties commissioned to 2-95 study financing plans and implementation sites (companies) 2.4 Conditions and Issues Related to the Clean Development Mechanism 2-95 2.4.1Coordination with the Recipient Country for Setting Conditions for Project 2-95 Execution and Assignment of Responsibility for Implementing Clean Development Mechanisms Based on the Project Site Conditions 2.4.2Coordination with the Recipient Country for Setting Conditions for Project 2-98 Execution and Assignment of Responsibility for Implementation of Clean Development Mechanisms Based on the Project Site Conditions

3. PROJECT EFFECTS 3-1

3.1 Energy savings 3-1 3.1.1 Technological basis for energy savings 3-1 3.1.2 Baseline used to estimate energy savings and assumptions made in 3-2 calculations of normal energy consumption (i.e., without modifications) 3.1.3 Estimate of actual energy savings, expected timeframe, and accumulation 3-3 3.1.4 Verification of energy savings (monitoring methods) 3-9 3.2 Reduced greenhouse gas emissions 3-10 3.2.1 Technological basis for reductions in greenhouse gas emissions 3-10 3.2.2 Baseline used to estimate reductions in greenhouse gas emissions 3-10 (i.e., without modifications) 3.2.3 Estimate of actual reduction in greenhouse gas emissions, anticipated timeframe, 3-11 and cumulative benefits 3.2.4 Verification of reductions in greenhouse gas emissions (monitoring methods) 3-17 3.3 Productivity improvements 3-18

4. EARNINGS POTENTIAL 4-1

4.1 Recovery of investment 4-1 4.1.1 Investment calculation method 4-1 4.1.2 Required level of investment 4-1 4.1.2 Breakdown of total investment 4-2 4.1.4 Recovery of investment 4-3 4.2 Cost-benefit analysis (Energy savings, and Cost versus greenhouse gas reductions) 4-14 4.2.1 Energy savings 4-14 4.2.2 Cost versus project benefit 4-15 4.2.3 Cost versus greenhouse gas reductions 4-16

5. LOCAL DIFFUSION OF THE TECHNOLOGIES 5-1

5.1 Possibility of local diffusion of technologies to be introduced in this project 5-1 5.2 Benefits including diffusion effects 5-2 5.2.1 Energy saving 5-2 5.2.2 Greenhouse gas reduction effects 5-2

6. OTHER BENEFITS 6-1

Other environmental, economic, and social effects related to the project; changes are also realized in energy conservation and greenhouse gas emission reduction

7. CONCLUSIONS

References Attachment Overview

Adopted at the third Conference of the Parties to the UN Framework Convention on Climate Change (COP3) in Kyoto in December 1997, the Kyoto Protocol seeks to combat global warming by encouraging industrialized nations to reduce emissions of greenhouse gases such as carbon dioxide. The basic target is an average reduction in greenhouse gas emissions of at least 5% below the 1990 levels for the period 2008 - 2012. The target for Japan was set at 6%.

The Conference also agreed on various mechanisms that would introduce more flexibility in efforts to attain these goals, including Joint Implementation (JI) by two or more industrialized nations, whereby participants share the benefits of overall greenhouse gas reductions, and Clean Development Mechanisms (CDM), implemented by industrialized nations in partnership with developing nations. However, the issue of trading emission credits was not discussed in depth at COP6 in 2000, and details are not expected to be finalized until COP7.

Japan is eager to utilize these mechanisms in order to achieve its designated target.

This investigation involved a feasibility study on the Petrochemical Corporation of Singapore (PCS) plant on the island of Merbau. The feasibility study identified potential energy savings and reductions in greenhouse gases (primarily CO2) emissions that could be achieved using energy-saving technology developed by JGC Corporation. The investigation also examined prospects for linking the project to a Clean Development Mechanism (CDM).

The comprehensive feasibility study examined potential energy savings and C02 reductions in the naphtha cracker I - a plant with which we are very familiar - and in utility facilities. The three best options identified in the study are described below.

1. Improvement of the heat recovery system using pinch technology

One method for reducing carbon dioxide emissions from the plant is to decrease the boiler load. Doing so requires reducing the amount of steam consumed by the plant. Heat recovery improvement analysis focused on reducing the steam consumed to heat fluids and drive compressors.

Within the constraints imposed by existing facilities, we have conducted , through pinch analysis, an overall analysis of utility sources such as steam, fuel, and electricity, by which determination of the optimum supply-demand balance in each process, development of a detailed strategy for

-1 - reducing energy consumption (incorporating more effective uses for low-pressure steam and reduced consumption of fuel gas and electricity) and quantitative evaluation of the strategy will become possible.

2. Advanced Recovery System (ARS)

The basic design of the Merbau Plant was created by Stone and Webster (S&W) of the USA in early 1980. The Advanced Recovery System (ARS), also designed by S&W at a later date, is suitable for retro-fitting to existing plants, as well as installation in new plants. Installation of the ARS would markedly reduce energy consumption at the Merbau Plant.

3. Cogeneration system featuring a gas turbine power generator

Cogeneration systems are the most popular solution worldwide for reducing overall energy consumption and C02 emissions for an entire facility. Substantial energy savings may be achieved at the Merbau Plant by shutting down the existing boiler and installing a cogeneration system incorporating a new gas turbine power generator. This would reduce the current reliance on purchased electricity and contribute significantly to the overall reduction of C02 emissions .

According to the findings of this study, implementation of the energy-saving project (described hereunder) in the PCS’s naphtha cracker I will lead to a potential reduction in carbon dioxide emissions of up to 150,000 tons per year.

Initiatives to reduce emissions of greenhouse gases are eligible for consideration as Clean Development Mechanisms (CDM). Furthermore, lower greenhouse gas emissions also imply lower emissions of sulfur oxides and nitrogen oxides generated by fuel combustion, contributing significantly to Singapore ’s efforts to protect the local environment.

The project described below will help to protect the state of the environment in Singapore, promote efficient energy use across the entire petroleum industry, and reduce greenhouse gas emissions.

-2- CHAPTER 1 BASICS OF PROJECT

This chapter presents the current status of the partner country, clarifies the necessity of introducing energy conservation technologies, and outlines the significance of the project.

1.1 Conditions of the Partner Country

1.1.1 Political, economic, and social conditions

(1) Government

1) Form of government Singapore is a democratic socialist republic that proclaimed independence from Malaysia on August 9, 1965 (Independence Day).

2) Head of state The head of state is the president, who is elected by direct popular vote for a term of six years. S.R. Nathan took office on September 1, 1999 as the sixth president of Singapore.

3) Cabinet The cabinet is comprised of one office and 14 ministries. Lee Kuan Yew, who has long served the country after independence, resigned as the prime minister in November 1990, and has since assumed the office of Senior Minister.

4) Legislature and Electoral system The legislature is a one-house parliament consisting of 83 popularly elected members serving five-year terms. The electoral system is comprised of the nine single-seat constituencies and 15 group representative constituencies (GRC). The former allows individuals to be candidates, and the latter is contested among groups of candidates formulated by political parties.

Since the present election system tends to favor bigger political parties, particularly the People ’s Action Party (PAP), there is a special “consolation system” in which a maximum of six losing candidates can be elected in accordance with the numbers of votes garnered by each opposition party, if opposition parties have gained less than three seats (Non-Constituency Members of parliament). At present, three legislators have been elected in this way.

- 1 - 1 - In addition, as a means of introducing new ideas in parliamentary deliberations, the parliament can contain appointed civilian members. A special selection committee comprised of parliamentary members recommends candidates to the president, who appoints these nominated members of parliament (NMP).

5) Political parties The People ’s Action Party (PAP) has been the dominant ruling party since the country ’s independence. In the January 1997 general election, the PAP won 81 out of 83 parliamentary seats. Among the opposition parties, one Singapore People ’s Party and one Worker’s Party candidate each secured a seat (excluding non-constituency members of parliament).

(2) Economy

1) Overview The Singaporean economy is supported by less than four million people, limiting the possibility of large-scale growth led by domestic demand. In 1999, exports amounted to S$194,289.6 million, 1.3 times the GDP of the country. The national economy is highly dependent on meeting external demand through exports.

The small population poses another structural problem: labor shortage. While the stable political environment, highly efficient industrial and social infrastructure, and active governmental incentives for foreign investment have helped attract many foreign companies in various advanced technological fields, the same conditions have accelerated the labor-shortage problem, pushing up labor costs as the country continues its rapid economic growth. In 1999, per-capita national income (per-capita GNP) amounted to S$39,721 (US$23,085), the highest level in the world.

Due to the potentially damaging effect of labor shortages and high labor costs on Singapore ’s international competitiveness, the government is emphasizing the development of a sophisticated, high-added-value industrial structure. In this transformation of industrial structures, assembly lines of white goods and AV (audio and video) equipment have almost disappeared from the country. The production has instead been moved to other countries such as Malaysia, Thailand, and Indonesia. Although the country has consistently opened its market to foreign companies in most industrial fields, there are certain business areas that are not fit for operation in the Singaporean market. Some foreign companies believe that certain industries can only grow in these unique conditions by maximizing the potential of tangible and intangible infrastructures that can quickly and efficiently respond to the ever-changing international business environment.

-1-2- The mid-to-long-term industrial policies of the government are intended to enhance the bases of manufacturing industries, with particular emphasis on high-value-added fields and research and development capabilities in such areas as electronic parts, petrochemical, and precision engineering. Government policies also emphasize Singapore ’s development into a major Asian and global business center through the development of its financial and business services. The country continues to attract capital and human resource investments from abroad, and has been actively promoting deregulation and liberalization of the financial sector in the wake of the recent currency and economic crises.

2) GDP growth rate by industry The industrial structure of Singapore is supported primarily by the dual pillars of financial/business services and manufacturing. In 1998, the financial and business service sector accounted for 30.9% of the GDP, nearly double the 1970 figure of 16.4% (value-added basis). This performance has been made possible by improvements in the financial infrastructure (centering on offshore banking and financial futures markets) at rates that have outstripped the rest of Asia, and by a strong cash demand due to high economic growth in Asia.

The manufacturing industry accounted for 23.8% of the GDP in 1970 and increased to 28.3% in 1980. In the 1990s, when the labor shortage and labor costs became serious management problems, existing production and assembly lines were moved out to other countries, resulting in a downward trend in recent years (23.4% in 1998). Recognizing that maintaining certain levels of manufacturing is indispensable to economic growth, the government actively invites foreign investment in high-value-added and technology-intensive sectors such as electronic devices, computers, information/communication, and petrochemicals (including medical products and biotechnology).

In the commercial sector, which accounted for 18.6% of the GDP in 1998, entrepot trade is growing due to Singapore ’s status as a Asian trading center. In addition, the tourism, hotel, retail, and convention business sectors are supported by foreign tourists and business travelers (over seven million annually). The transportation and communication industries, accounting for 13.9% of the GDP, have expanded recently through greater business opportunities in electronic and multimedia services, based on Singapore ’s sophisticated information/communication infrastructure.

-1-3- 3) Macro economic indicators (a) Economic growth rate Real GDP in 1998 maintained positive annual growth at 1.5% over the previous year, although it registered negative growth in the third and fourth quarters. Singapore has not suffered a currency crash or economic crisis, but residual damage from the recent crises that rocked the rest of Asia has been more serious than in the 1985 recession, as its economy is closely linked to the rest of Asia through trade and investments. Since 1999, as business conditions in Asia exhibited signs of recovery with certain positive economic indicators, the overall confidence in Singapore has also become increasingly positive. The government has announced that it expects economic growth in 1999 to increase 0-0.2% over the previous-year rate, in addition to a continued positive outlook of 3-4% growth thereafter.

(b) Balance of payments The balances of payments in Singapore have consistently achieved surpluses. After the revisions in the Balance of Payments Manual by the International Monetary Fund (IMF), the merchandise balance has been greatly improved, and the international trade in services has also posted net gains, resulting in consistent current account surpluses (the surplus for 1998 was S$29,479 million).

Backed by this current account surplus, Singapore has become a global provider of capital through securities investments and loans. Consequently, the capital and financial accounts have long been in the red.

(c) Foreign currency reserves The foreign currency reserves total S$124,584.4 million, the equivalent of 8.8 months of commodity imports. In Singapore, which has almost no natural resources, foreign currency reserves represent an essential defense against national emergencies, and are under strict government control.

(d) Commodity prices The consumer price index (CPI) edged up by approximately 2% over the previous-year ’s levels. However, since June 1998, it has decreased compared with the same term of the previous year, resulting in a negative annual growth of 0.3% over the previous year.

This can be attributed to the following factors: (1) sluggish domestic consumption due to the Asian currency and economic crises, and the resultant intensifying price competition, (2) reduction in public services charges dictated by government policy as a measure to stimulate the

-1-4- economy, and (3) stagnant crude oil prices. On the other hand, the prices of certain consumer spending items, such as educational and medical costs, have moved upward. Nevertheless, the domestic supply price index (DSPI: utilized as wholesale price index), which indicates price trends of imports and domestic industrial goods, was hard hit in 1998 by the stagnating crude oil and fuel prices and decreased by 3.1% compared with the previous year.

(e) Employment While a steep rise in labor costs due to labor shortages has become a serious management problem, Singapore is still widely regarded as a favorable investment environment by foreign companies. Investments in Singapore have increased steadily, and helped contain the unemployment rate at 1.8% in 1997 (seasonally adjusted). High rates of employment have long been the norm.

In 1998, Asia was hit by a regional economic crisis that triggered production and employment adjustments by primarily foreign companies. The number of layoffs reached 28,300, greatly exceeding the 19,529 layoffs in the 1985 recession. Employment conditions in Singapore have deteriorated considerably, pushing the unemployment rate to 4.5% as of September 1998.

In November 1998, the government announced a measure to reduce business costs through a 15% cut in gross wage costs as a means of alleviating the negative effects of further employment adjustments. Items included in the gross wage cost reductions are a 10% reduction in employer contributions to the employee Central Provident Fund (CPF). This measure has been favorably accepted by the National Trades Union Congress (NTUC).

(f) Fiscal performance Prior to 1998, Singapore consistently achieved government budget surpluses thorough rationalization and improvements in the efficiency of central government agencies. In 1998, however, fiscal revenue was reduced from a surplus of S$4,748 million in the previous year to a deficit of S$5,110 million by the supplementary budget (part of the economic stimulus package) to counter the intensifying negative sentiment among companies operating in Singapore due to the Asian economic crisis. In addition, reduction of and exemption from corporate taxes (caused by tax reforms introduced in the previous year), sluggish business performance, and reduced public utility charges were also responsible for the deficit.

-1-5- 4) Trends in foreign trade In 1998, exports from Singapore (on a customs-clearance basis) totaled S$183,763.3 million, a 1.0% reduction from the previous year, while imports totaled S$169,863.5 million, a 13.6% reduction from the previous year.

Local exports (57.6% of all exports) amounted to S$105,917.6 million, a 1.5% reduction from the previous year, and re-exports amounted S$77,845.7 million, a 0.3% reduction from the previous year. Local exports of petroleum products (mineral fuels comprising 12.7% of all local exports), hit hard by sluggish crude oil prices, totaled S$13,472.9 million, a 15.3% reduction from the previous year, and non-petroleum products (comprising 87.3% of the local exports) remained nearly unchanged, recording an increase of 0.9% (S$92,444.7 million).

Foreign trade in Singapore (on a customs-clearance basis) has four distinct characteristics: first, the national trade account is always marked by a deficit. This is due to (1) Singapore ’s dependence on imports for most of its food, daily commodities, and durable consumer goods, and (2) its assembly- and processing-dependent industrial structure, which requires increased imports of high-quality industrial goods and parts in order to expand exports. In 1998, imports declined by 13.6% from the previous year due to the currency and economic crises, and trade performance made a positive turnaround, which should be regarded as a temporary phenomenon.

Second, non-petroleum products account for as much as 87.3% (1998) of local exports, which in turn comprise 57.6% of total exports. Specifically, electronics products and parts are Singapore ’s primary exports; the five major items are ICs, disc drives, printed circuit board assemblies (PCBAs), PCs, and printers, accounting for 45.1% of all local exports (in 1998). Disc drives and PCs are mostly exported to the European market, while ICs and PCBAs are exported in great quantity as essential parts for Asian production sites.

Third, as an entrepot, Singapore records a relatively high rate of re-exports, which can be regarded as a major portion of overall exports (42.4% of all exports in 1998). This is because Singapore ’s sophisticated port infrastructure makes it a major shipping hub. Important sea-lanes connecting Southeast Asia with the rest of the world start in Singapore, and many parts and raw materials required for production activities in Southeast Asia, as well as products manufactured in the region, are transported through Singapore.

Finally, more than 90% of foreign trade is conducted with Asia, the U.S., and Europe (92.9% of exports and 96.1% of imports). 1998 export statistics by country and region indicate that exports to the U.S., the biggest export market, amounted to S$36,557 million (19.9%), followed

-1 - 6 - by 15 EU nations at S$29,088.6 million (15.8%), Malaysia at S$27,998.9 million (15.2%), and Hong Kong at S$ 15,418.3 million (6.6%).

As for imports, the U.S. replaced Japan as the biggest import source in 1998. Imports from the U.S. amounted to S$31,253.3 million (18.4%), those from Japan amounted to S$28,434.5 million (16.7%), Malaysian imports totaled S$26,252.4 million (15.5%), and imports from 15 EU nations totaled S$23,592.7 million (13.9%).

5) Trends in acceptance of foreign investment in manufacturing sector While declining international competitiveness due to increasing labor costs is a growing concern, investments in the manufacturing sector (based on commitments; without distinction between overseas and domestic capital) have increased steadily every year. Specifically, since commencement of the Jurong Island Initiative to build a major petrochemical/chemical industrial base in Asia, direct investments in the sector have increased steadily since 1995.

In 1998, due to the negative effects of the currency and economic crises, investments in the manufacturing sector totaled S$7,829.4 million, a 7.8% reduction from the previous year. Foreign capital totaled S$5,213.5 million (66.6%) and local capital was S$2,615.9 million (33.4%). The ratio of foreign to local capital is about seven to three. The breakdown of foreign capital indicates that the U.S. stands as the biggest investing country at 44.0%, followed by Japan (34.8%) and the EU (16.9%).

By industrial sector (without distinction between foreign and local capital), the electronics and petroleum sectors accounted for over 75% of all investments. In the electronics industry, primarily led by investments in pre-processing for semiconductors, investment reached a record high of S$3,858 million in 1997, accounting for 44.8% of the total. In 1998, the economic and currency crises suppressed the investment to S$3,047.8 million (38.9% of the total), a reduction of 19.9% from the previous year. In contrast, the chemical industry has attracted increased investment as the Jurong Island Initiative progressed. In 1998, investments in this sector reached S$2,913.7 million, about 2.3 times the 1994 level. The ratio in the total investments increased from 22.7% to 37.2%, almost comparable to the level of the electronics sector.

6) Trends in direct foreign investment Direct foreign investment by Singaporean companies has also increased rapidly. The contributing factors may be (1) desire to maintain and enhance international competitiveness in the manufacturing sector, (2) economic developments in Asia, (3) government incentives for

-1-7 - promoting overseas investment (the regionalization policy), and (4) the enhanced aspiration of domestic companies to seek new business expansion opportunities overseas, especially in the areas of development and management operations of the industrial infrastructure, industrial parks, and hotels.

The outstanding balance of direct foreign investment (acquisition of shares and equity, and loans) as of the end of 1996 was S$55,712.4 million, about 3.3 times the level at the end of 1990 (the average annual growth rate from 1990 through 1996 was 22.0%). The number of local subsidiaries and branches established in the same period increased from 2,391 in 1990 to 5,892 in 1996. The average investment per case increased from S$7.1 million in 1990 to S$9.5 million in 1996.

Looking at the figures by country and region, Asia accounts for 58.1% of all Singaporean direct overseas investments; specifically, ASEAN represents the largest group, with 55.6% of all investments in Asia. The top five investment markets are (1) Malaysia (S$10,753 million), (2) Hong Kong (S$6,326.5 million), (3) China (S$5,339.6 million), (4) UK (S$4,344.6 million), and (5) Indonesia (S$3,914.5 million).

Malaysia’s prominence is due to the active expansion of Singaporean manufacturing firms, mainly electric/electronic parts companies, as well as banks and financial firms, into Johore. Additionally, investments in China and Indonesia have also been expanding rapidly. As of the end of 1996, China became the third biggest investment market after Malaysia and Hong Kong. Singaporean companies have advanced into the industrial parks developed in Jiangsu Province (Suzhou and Wuxi Cities) by the government and government-affiliated companies. Construction of infrastructure and real-estate developments at various locations have also contributed to the upsurge of investments in China. In Indonesia, investments have increased in the manufacturing businesses in Batam and Bintan Islands in Riau of Indonesia, which, together with Singapore and Malaysia (Johore), comprises the “Growth Triangle. ”

7) Economic development strategies for the 21st century The government of Singapore has implemented the following economic policies since the 1990s to increase the sophistication and value of its industries, and to enhance its position as an Asian business hub.

-1-8- (a) Industry 21 Plan (121) In June 1998, the government of Singapore announced the “Industry 21 Plan (121),” which lays the foundation for the new industrial policies. 121 focuses on six areas: (1) enhancement of the bases for technology/knowledge-intensive industries, (2) fostering of world-class local enterprises, (3) the search for technological innovations, (4) promotion of the international business hub initiative, (5) attracting more companies with enhanced regional control functions, and (6) the development/accumulation of human resources. Through these efforts, the country intends to make itself a center of technology-intensive and knowledge-intensive companies and to enhance its regional control functions.

Policy targets specified in 121 include (1) attainment of a 40% ratio for 121-related industries (on a value-added basis) (25% for the manufacturing industry and 15% for exportable services), (2) creation of 20,000-25,000 new jobs annually (15,000 for the manufacturing industry and 5,000-10,000 for exportable services), and (3) increase in the ratio of knowledge/technology-intensive workers in the newly created jobs (66% for the manufacturing industry and 75% for exportable services). (The targets for industries and sectors were made public in January 1999.)

(b) Information Technology 2000 Plan (IT 2000) This plan announced in 1992 promotes development and dissemination of information technologies (IT) in order to help transform the country into an intelligent island. More specifically, the following themes have been adopted: (1) enhancing the functions expected of an international hub for product design, R&D, marketing, and regional integration by using high-speed communication networks, (2) making the country an international transportation hub by providing high-quality services based on sophisticated IT for air/sea-port operations, (3) enhancing overseas development of remote learning systems to make the country a base for regional education and business training, (4) providing services such as e-mail, video conference, and bulletin board systems (BBS) to allow overseas and domestic individuals to have a wider communication link, and (5) improving quality of life by simplifying tax payments and administrative proceedings, TV shopping, and cashless transactions. The operations of IT 2000 are based on “Singapore One, ” a broadband multimedia service network. The commercial services have already been started.

(c) International Business Hub 2000 Plan (IBH 2000) To enhance the ability of the country to serve as a gateway connecting the Asian region with the world, the government will attempt to attract regional headquarters of multinational service companies, and establish a sophisticated and high-quality infrastructure. The plan covers such

-1-9- areas as regional headquarter operations, financial services, physical distribution/transportation, information/communication, electronic commodity trades, international conferences/trade fairs, and cultural/artistic activities.

(d) Regionalization 2000 The plan is designed to promote and support the Asia-wide operational developments of domestic companies through overseas direct investment in order to overcome the country ’s limited economic scale and facilitate further economic growth.

To create local investment environments similar to those in Singapore, Singapore-style industrial parks will be constructed in neighboring countries through inter-governmental collaboration. At the initiative of government-affiliated major corporations, positive sentiment in favor of corporate participation will be nurtured. Incentives such as subsidies and low-interest loans have already been introduced.

(3) Society

1) Structure of population As of July 1998, Singapore had a population of 3,163,500 residents. (If long-term (longer than one year) foreign residents are included, the figure reaches 3,865,600.) Due to rising living and educational costs, the birth rate has been declining steadily. In 1998, the rate of population increase (Singapore nationals and permanent residents) was 1.9% over the previous year. In contrast, due to advancements in medical services and improved hygiene, the average life expectancy has increased steadily (75.2 years for men and 79.3 years for women in 1998). The average age of the population was 32.9 years in 1998, and the average age of the population is expected to increase.

Tablel.1-1 Singapore nationals by ethnicity (Unit: 10,000 persons; %) 1997 1998 Component Rate of Component Rate of Population Population ratio increase ratio increase Chinese 239.42 77.2 1.8 243.56 77.0 1.7 Malay 43.79 14.1 0.8 44.49 14.1 1.6 Indian 23.06 7.4 3.8 23.97 7.6 3.9 Others 4.08 1.3 5.7 4.33 1.4 6.1 Total 310.35 100.0 1.9 316.35 100.0 1.9 Sources: Yearbook of Statistics Singapore 1997, Statistics Bureau Monthly Digest of Statistics Singapore, March 1998, Statistics Bureau

- 1 - 10 - 2) Language On August 9, 1965, Lee Kuan Yew proclaimed Malay as the national language in the proclamation of Independence from Malaysia. Due to the ethnic diversity of the country, English, Malay, Chinese (Mandarin), and Tamil were all designated as official languages. To promote the peaceful coexistence of such a diverse population, English has constantly been emphasized in public education, and most people born after the WWII can speak, read, and write English fluently.

3) Religion Due to the diverse nature of the population, followers of Buddhism, Christianity, Islam, Hinduism, and Taoism coexist harmoniously in Singapore.

4) Educational system Although education is not compulsory in Singapore, the attendance rate at primary schools is nearly 100%. Plans to make primary and lower secondary education compulsory are now under deliberation. As of 1996, about 92.2% of Singaporeans are literate in at least one of the official languages.

The ages at which students can be promoted to higher education vary widely, depending on results of unified tests at each stage. The shortest educational course takes 15 years to complete (six years for primary school, four years for junior high, two years for senior high, and three years for university). Those who fail to enter the general education course can go to one of four higher vocational schools called polytechnics, which generally feature three-year curricula. Graduates of polytechnics can obtain diplomas.

Singapore has two universities: the National University of Singapore and Nanyang Technological University. A business college modeled on American business schools is currently under construction. The government is actively soliciting major overseas universities to build campuses in the country.

-1 - 11 - 5) Media (a) Major newspapers and other media There are eight daily newspapers in the country as shown in Tablel.1-2. They are affiliated with Singapore Press Holdings, a government-affiliated holding company.

Table 1.1-2 Daily Newspapers in Singapore

Circulation Daily newspaper Type (Monday through Saturday) The Straits Times English 391,000 The Business Times English 32,000 The New Paper English (Evening paper) 113,000 Lianhe Zaobao Chinese 200,000 Shin Min Daily News Chinese 121,000 Lianhe Wanbao Chinese (Evening paper) 137,000 Berita Harian Malay 52,000 Tamil Murasu Tamil 9,000 Source: Research conducted by JETRO Singapore Center

(b) TV stations As indicated in Table 1.1-3 below, the TV stations are in operation in addition to Malaysian broadcasts (TV1, TV2, TV3). In addition, Singapore Cable Vision (SCV) provides cable TV broadcasting (pay TV).

Table 1.1-3 TV Stations in Singapore

TV station Channel Remarks Television Corporation of Singapore Channel 5 English broadcasting (TCS) Singapore Television Twelve (STV12) Channel 8 Chinese broadcasting Channel News Asia (affiliated with Prime 12 Mainly sport programs TCS) Premier 12 Multi-lingual broadcasting (entertainment and education) News Asia News and informational programs about Asian affairs (24 hours a day); started in March 1999

6) Residential conditions To provide high-quality and low-priced residences, the government established the Housing & Development Board (HDB) in 1960. As of the end of 1998, the HDB has provided over 834,000 units, raising the percentage of those living in the public housing units from 9% (1960) to 86%. Since 1968, the contribution system of the Central Provident Fund (CPF) has been available for purchasing public housing units, and improving the home ownership rate.

-1-12- To realize a modem urban environment through urban re-development, the government established the HDB’s urban renovation department in 1966, and the Urban Re-development Authority (URA) in 1974. These agencies have conducted comprehensive re-development projects, including expropriation of land and relocation of residents. In order to recover greenery lost in these re-development efforts, the government has systematically and actively promoted and maintained tree-planting operations (Clean and Green Policy). Partly because of the tropical climate’s influence in helping plants grow relatively faster, the downtown and public areas in public housing complexes are now filled with greenery.

Since 1989, the government has designated historical and cultural preservation districts for future generations and regulated development and construction in these areas. Chinatown, Little India, and Arab Street have been among those areas designated as preservation districts.

1.1.2 Energy Situations

(1) Energy policies

Established jointly by the Ministry of Trade and Industry (MITI), the Economic Development Board (EDB), the Trade Development Board (TDB), the Public Utilities Board (PUB), the Ministry of Environment, the Jurong Town Corporation (JTC), and various other organizations, Singapore ’s energy policies are intended to foster industries based on free-market and free-trade ideals, with minimal governmental interference.

To promote diversification, to conserve energy, and to reduce carbon dioxide emissions, domestic electric power generating facilities are currently switching from petroleum to natural gas. The nation has also implemented energy conservation policies modeled on their Japanese counterparts.

Since Singapore has no choice but to implement intensive, economic development policies, directed toward processing trade, the country strives to encourage the investment of foreign capital, promoting exports through infrastructure improvements and preferential taxation systems.

As part of its “Manufacture 2000 Plan, ” which targets a manufacturing industry output (in GDP) of 25% or more, Singapore is currently promoting the “Chemical Island Concept, ” which calls

-1-13- for land reclamation around the seven islands located in the southern part of Singapore, including Merbau Island, in order to establish a vast petrochemical zone with a total area of 2,800 ha.

(2) Chemical Island Concept

1) Overview In Singapore, chemical products account for S$33 billion annually, or approximately 25% of the S$135 billion (US$77 billion) manufacturing economy. Singapore is currently seeking to boost this figure to 30% by the year 2010. The category of chemical products includes the following, by portion of the industry: 15% petrochemical products, 16% special chemicals, and 15% pharmaceuticals. Petroleum products account for 41% of the chemical products industry, the largest single product area.

The Jurong Island Concept calls for the consolidation of seven small islands off the southern coast of Singapore at a cost of S$7 billion. Large-scale land reclamation work (approved in 1991 and begun in 1995) has increased the previous land area of 991 hectares in two stages to 1,673 hectares.

When the two construction stages are completed by the end of 2001, an additional 977 hectares will be reclaimed at the western side of the island.

Approximately 80 hectares of the area has been set aside as an integrated logistics hub (scheduled for completion in 2002), which will house facilities representing a total investment of S$8 billion. These facilities will include chemical tanker berths, storage tanks, cargo sorting sites, packing facilities, and product warehouses.

The government of Singapore has also concluded a contract to add a site of 550 hectares, which is scheduled for completion in 2006. A contract totaling S$5,140 million signed in June 2000 calls for the expansion of Jurong Island and the reclamation of 1,908 hectares at Tuas View (a district located at the western end of Singapore, where pharmaceutical manufacturing complexes currently operate).

On Jurong Island, 55 companies have established facilities, representing a total investment of S$21 billion and S$15 billion in production. Primarily major Japanese, European, and American chemical concerns, these companies employ a total of 6,500 people.

-1-14- 2) Expansion of ethylene production capacity Singapore intends to rapidly expand its chemical-related operations over the next several years. By 2010, EDB plans to increase the ethylene production capacity of the plants on the island from the current annual figure of 1,800,000 tons to 3,000,000 tons. This will be achieved by upgrading two existing PCS crackers and the start of operations of the ExxonMobil ’s unit.

According to EDB estimates, completion of the third-stage reclamation will enable the construction of five of the world ’s largest crackers on Jurong Island. Naphtha and heavy oil, the raw materials for the new crackers, will be procured from oil refinery facilities in Singapore, supplemented by light condensed oil which is easily obtained from the Middle East, according to EDB.

A number of companies (BASF, Shell, Mitsui Petrochemical, ExxonMobil, etc.) have already expressed interest in investing in the construction of new crackers in Southeast Asia.

3) Cooperation of chemical-related companies (chemical chains) The establishment of new crackers will inevitably increase demand for raw materials and encourage additional investment in downstream facilities. EDB is pursuing a strategy of marketing the construction of chemical chains to prospective investors. Current candidate products include acetyl, acrylic, ethylene oxide derivatives, oxochemicals, phenol resins, and styrene resins. EDB is also targeting the future development of several new chemical chains involving engineering polymers and fine chemical products.

EDB’s current target figures call for 150 companies stationed on Jurong Island by 2010, with investment totaling S$40 billion. When the investment cycle is complete, the number of employees on the island is expected to increase from the current figure of 6,300 to approximately 15,000.

For the integrated chemical hub project, the government of Singapore is inviting investment not only from petrochemical manufacturers, but from business sectors that support the chemical industry, including utility companies (steam, water, electricity), logistics companies (Vopak, Katoen Netie, Oiltanking, etc.), and gas companies (SembGas, Air Products, Messer/Texaco).

The flow of natural gas from the West Natuna gas field off the coast of Indonesia to Jurong Island is expected to commence by next April. The gas will be supplied over a distance of approximately 640 km. This natural gas supply will be used in place of petroleum to generate

-1-15- electric power, and will also be used in the new cogeneration systems and synthetic gas devices currently under construction on the island.

The island will also provide engineering services and waste disposal facilities (including refuse incineration and wastewater treatment facilities). To facilitate the transport of raw materials, products, and water through pipelines, a Singaporean company, SembCorp Utilities Terminals (SUT), is building product service ducts on the island.

4) Policies that encourage investment from petrochemical companies As Singapore ’s chemical hub, Jurong Island is the site of numerous projects funded by investments from petrochemical companies.

In 1999, Eastman Chemical, DuPont, Teijin, Kuraray, and Nippon Synthetic Chemical Industry commenced operating their respective manufacturing facilities. In 2000, Croda and Celanese are expected to follow suit. In 2001, ExxonMobil will establish a large-scale cracker, as well as polyethylene, polypropylene, and oxoalcohol chemical complexes to further boost the scale of the chemical hub. Basell Eastern, Mitsui Petrochemical, Teijin, Asahi Chemical, Mitsubishi Gas Chemical, and other companies also plan to implement their own large-scale projects, including plant construction.

The success of the Jurong Island chemical hub, the Chemical Island Concept, in appealing to multi-national manufacturers is largely the result of farsighted plans on the part of the government. These plans are promoted primarily by the Economic Development Board (EDB) and the Jurong Town Corporation (JTC). EDB is charged with responsibility for soliciting overseas investment, while JTC is responsible for supervising and managing infrastructure investments for the “chemical island. ”

Although Singapore itself lacks inexpensive raw materials, it has created attractive sites for petrochemical investment through the government ’s preferential policies for companies, and through strategic plans to enhance infrastructures and thereby increase the appeal of the location.

For example, no import duty is imposed on chemical products, and 100% ownership of business is permitted. This allows all profits to be returned to the companies ’ home countries. In some cases, EDB directly purchases company stocks to provide financial support in the initial stage of the projects. For instance, EDB invested 10% in the new Teijin polycarbonate facility.

According to EDB, the keys to the successful establishment of the chemical hub were the

-1-16- establishment of the integrated manufacturing infrastructure and the availability of raw materials, utilities, and logistics services. These factors offer significant economic benefits for overseas companies and boosts the competitive edge of Singapore ’s chemical hub.

Singapore ’s geographical location, sea routes, and easy access to the Asian market are also attractive features for overseas investors. The government of Singapore plans to achieve national economic growth by drawing on its knowledge-intensive leadership and its world-class chemical hub.

5) Application of information communications technology As part of the large project concept based on IT and knowledge bases, EDB and JTC have recently begun building a Jurong Island intranet. All companies on the island are already linked by broadband optical fiber networks. In the initial stage, this intranet will be used to integrate island activities related to logistics, maintenance, repair, and engineering. Future plans include application of the intranet for information services, as well as medical, safety, and environmental modules.

Ultimately, the intranet will form an Internet portal site for all companies on the island. Since EDB’s role is to provide supplementary functions, the project will eventually operate on a commercial basis.

A broadband fiberoptic network has been laid throughout Jurong Island, and Internet connectivity is an important step toward information consolidation for the seven islands.

The Internet revolution and the advent of electronic commerce is expected to dramatically alter business modes, both here and elsewhere.

Internet connectivity has created a general Web site for Jurong Island that provides information on business, industry, and community matters. This Web site also includes links to Web sites of local companies, government offices, and telecommunications companies on the island.

Thanks to the integrated logistics management module, companies on Jurong Island can access suppliers, customers, transportation companies, harbors, and government offices to optimize supply chain management.

-1-17 - (3) Petroleum resources

Lacking any native fossil fuel reserves, Singapore relies entirely on imports to meet its petroleum demands.

Its total 1995 petroleum imports were 1,020,000 bbl/d, an increase of some 160% from 1985 levels of 640,000 bbl/d, and representing an annual rate of increase of 3.4%. The largest supplier nation is Saudi Arabia (430,000 bbl/d), followed (in order) by the United Arab Emirates (U.A.E.), Kuwait, Malaysia, and Qatar. In terms of regions, 84% of the supply comes from the Middle East, 12% from Asia, and 4% from other areas. The crude oil processed in Singapore consists primarily of Saudi Arabia ’s Arabian Light and U.A.E.’s Murban.

The volume of petroleum products exported by Singapore totals 940,000 bbl/d, while imports of such products amount to 550,000 bbl/d. While this translates to a net export of 390,000 bbl/d, Singapore supplies a large amount of heavy bunker oil. Including a bunker supply of 300,000 bbl/d, the actual net amount of petroleum products exported from the country is nearly 700,000 bbl/d.

(4) Natural gas

Since 1992, the Senoko Power Plant in Singapore operated by the Public Utilities Board (PUB) has received natural gas through a pipeline from Malaysia. The total amount of imported natural gas is 1.5 billion m3 over a 15-year contract period.

Singapore currently uses a large amount of heavy oil for thermal power generation and must meet significant additional bunker demands. Because heavy oil processed in the country cannot meet demand, Singapore imports additional heavy oil - totaling 300,000 bbl/d - from the Middle East.

The Singapore government plans to step up its imports of natural gas, seeking to promote the use of this clean energy source in line with its environmental policies. Imports of LNG and use of natural gas as raw materials for petrochemical products are also being studied.

-1-18- (5) The current status of energy consumption and greenhouse gas emissions

The improved standard of living brought about by continuing industrialization and technological progress will likely raise Singapore ’s domestic energy consumption, which in turn is expected to increase emissions of greenhouse gases such as carbon dioxide.

Carbon dioxide (C02) accounts for the largest portion of the greenhouse gases discharged by Singapore. To ensure sustainable economic growth while reducing greenhouse gas emissions, the Singapore government is encouraging the active introduction of new technologies.

1) Current state of greenhouse gas emissions With limited natural resources of its own, Singapore relies on imports of fossil fuels for energy sources to support its economic activities. It depends largely on fossil fuels for primary activities such as power generation and transportation.

Singapore currently has no regenerative energy sources with which it can use to reduce its dependency on fossil fuels. It lacks hydroelectric or geothermal energy sources. Nuclear power facilities cannot be built for safety reasons. The sea around Singapore is relatively placid, making wave-generated power impractical. Due to its limited land area, Singapore ’s biomass does not represent a potential energy source. Finally, wind power is impractical due to its limited land area and Singapore ’s relatively weak winds.

The only possible regenerative energy source for Singapore is solar power. But Singapore believes that current levels of technology are inadequate to build and operate such facilities profitably, and its limited land area again makes this a less than feasible option. Solar power generation is not likely to be promoted an alternative energy source.

In 1994, Singapore ’s total carbon dioxide emissions amounted to 26,800 giga-grams. The energy sector was responsible for 99% of total power consumption. The power generating industry and the manufacturing industry accounted for 48.7% and 33.5% of total emissions, respectively. Carbon dioxide emissions discharged by the transport sector represented 15.4% of total figures, while emissions from businesses and households accounted for 2.4% of the total.

The combustion of fossil fuels is Singapore ’s largest single source of carbon dioxide emissions.

2) Current status of the power generation sector

-1-19- In 1994, 4,580,000 tons of fuel-equivalent energy sources were consumed to generate 20,675,600,000 kW of electric power. The total amount of carbon dioxide discharged was 12,989.64 giga-grams. Of this amount, 74% was produced by the combustion of fuel oil and diesel oil, with natural gas accounting for the remaining 26%.

Sales of electric power that year reached 18,901,300,000 kW. The manufacturing industry was by far the largest consumer (45%) of electric power, followed by other industries (37%), and households (18%).

(a) Industrial sector Singapore is neither a petroleum or natural gas producing nation, but nevertheless maintains large-scale oil refineries and petrochemical centers to process crude oil imported from the Middle East and other oil producing countries. The petroleum refineries and petrochemical industry discharge 7,026.08 giga-grams of carbon dioxide. Other industries emit 1,896.25 giga-grams.

(b) Transportation sector The carbon dioxide discharged by land transportation operations accounts for 15.4% of the total emissions produced by the energy sector. In 1994, Singapore ’s public road network measured 3,027 km in total length, and 611,600 vehicles were in operation. These vehicles use diesel fuel and gasoline. The annual diesel fuel consumption was 682.1 kilotons, while the annual gasoline consumption was 628.9 kilotons. The combustion of these fuels generated 4,099.99 giga-grams of carbon dioxide emissions.

© Private sector (businesses and households) Total carbon dioxide emissions from businesses and households account for only 2.4% of total emissions, the majority of which are generated by air conditioners and water-heating systems, which operate on liquefied petroleum gas (LPG) and city gas. In 1994,1,045,800,000 kWh of city gas and 145 kilotons of LPG were consumed, accounting for 327.8 giga-grams of carbon dioxide emissions.

(6) Deregulation of the energy sector

The electric power industry in Singapore has long been vertically integrated. For more than 30 years, the legally appointed Public Utilities Board (PUB) has controlled the generation, transmission, and distribution of electric power supplied to consumers. PUB was reorganized on October 1,1995. The restructuring added new responsibilities to PUB’s governing

1-20- functions for the electric power and pipeline gas supply companies. PUB is now responsible for ensuring supply stability and price fairness for consumers.

Following PUB’s reorganization, its electric power and gas divisions were established as corporate entities. Additional reforms led to the establishment of two power generation companies, one power transmission/distribution company, and one power dispatching company. In the first quarter of 1999, the third power generation company, Tuas Power, began operating. Another company, Semb Corp Cogen Pte. Ltd., has recently obtained a license for power generation.

The restructuring of the power industry is intended to encourage competition and prevent declines in overall industrial efficiency resulting from a gradual increase in total power generation capacity. The reforms target stimulation of the cost-cutting efforts of power companies, based on competition and the promotion of new technologies, for continued improvements in power generating efficiency.

In April 1,1998, Singapore Electricity Pool (SEP) began operations as an electric power trade market, in which power generation companies and power sales companies are free to seek the best deals available to them. Price regulations are to be enacted if the market fails to provide an arena of free competition.

(7) Shifting from petroleum to natural gas

Singapore depends heavily on petroleum for its primary energy needs - fuel oil remained its only source of power until 1992. Since it recognizes that natural gas produces fewer carbon dioxide emissions than petroleum per unit of energy generated, Singapore is now promoting the replacement of fuel oil with natural gas.

Since 1992, the Senoko Power Station has been using natural gas imported from Malaysia in some of its power generating operations. Significant improvements have been seen in the supply stability of natural gas, a crucial consideration in the decision to convert to natural gas.

In January 1999, Semb Corp Gas concluded an agreement with Pertamina (Indonesia ’s government-owned company) for the supply of natural gas (imported to Jurong Island in Singapore from West Natuna in Indonesia). Supply is slated to start in the second quarter of 2001. According to the contract, 325 MSCFD of gas will be supplied to Singapore.

- 1 - 21 - Additionally, Pertamina and Singapore Power are negotiating the procurement of natural gas from Sumatran gas fields. When concluded, this agreement will enable Pertamina to incrementally increase the amount of natural gas it supplies. According to the plan, the initial amount of 150 MSCFD in 2002 will be increased progressively to 350 MSCFD by 2008.

(8) Improving power generation efficiency

Singapore boasts high power generating efficiency. In the World Competitiveness Report 1992, Singapore ranked second (only slightly behind Denmark) in power generating efficiency and reliability. The power generating efficiency rates of the ordinary, new, medium-size steam plant and the combined-cycle gas turbine (CCGT) are 35 to 40%, and 45 to 50%, respectively.

The advantages offered by CCGTs are widely recognized, and recent technological advances have notably improved the reliability of CCGT units. Power Senoko Ltd. replaced four 128 MW gas turbine units with two 425 MW combined-cycle plants, which began commercial operation in February 1997.

Following Singapore ’s deregulation of the electric power industry, the adoption of power generation technologies by power companies is determined by market conditions.

Power companies keep the most efficient plants on line, keeping less-efficient units for reserve generation capacity. As older plants are superceded and new capabilities added, power companies will continue to examine power generation technologies that promise higher efficiency.

Power Senoko plans to replace its Stage-I oil burning steam plant, in operation since 1975, with a 600 MW combined-cycle plant, as soon as a natural gas supply is secured.

(9) Efforts for effective energy utilization

The industrial sector in Singapore is conducting business in a highly competitive international market, and a large portion of its products are exported, providing further impetus for promoting effective energy use. As described below, Singapore ’s unique circumstances have led to various corporate efforts across a wide range of business fields.

In 1995, Shell, Singapore ’s largest oil refining company, invested S$50 million in the construction of a cogeneration plant. This plant generates 24 MW of electricity and produces

-1 - 22 - 56 tons of steam per hour using fuel gas. The plant has successfully achieved a combined efficiency of 77%, a significant increase of 35% over the average efficiency of ordinary power plants.

ST Microelectronics ’s wafer plant in Singapore has set a corporate target to reduce annual energy consumption by at least 5%.

ST Microelectronics has established and maintains an excellent environmental management system. From 1991 to 1996, the company attained a 14% reduction in energy consumption per wafer, far exceeding the company ’s initial target.

The Shangri-La Hotel in Singapore recently upgraded its air-conditioning plant. The hotel formerly operated the plant at 3,252 refrigerating tons (RT) (average efficiency: 1.22 kW per RT). Following the system upgrade, the hotel ’s air-conditioning plant boasts performance levels of 2,600 RT (average efficiency: 0.68 kW per RT), for a daily reduction of 14,400 kWh.

(10) Increasing sea levels due to climate change

UNFCCC’s Article 4.8 stipulates that Parties to the Convention must give full consideration to the actions necessary to meet the specific needs and concerns of developing country Parties arising from the adverse effects of climate change and/or the impact of the implementation of response measures. Singapore is among the nations meeting the following three conditions listed in the Article:

1. Small island countries

2. Countries with low-lying coastal areas

3. Countries whose economies are highly dependent on income generated from the production, processing and export, and/or on consumption of fossil fuels and associated energy-intensive products.

As a small archipelago nation with low-lying coastal areas, Singapore is likely to suffer directly any consequences resulting from increasing sea levels, and climate changes that raise sea levels are likely to pose a serious threat.

-1 - 23 - (11) Preferential tax systems

A number of preferential tax systems have been implemented to promote the use of technologies that increase energy efficiency and to encourage the installation of energy-efficient equipment. Local companies are able to take advantage of the Local Enterprise Technical Assistance Scheme (LETAS). LETAS promotes the modernization and upgrading of facilities through the application of external specialized knowledge and technologies, and includes energy efficiency improvement in its scope of application. Local companies are eligible for financial assistance of up to 70% (a maximum of S$40,000) for consultation expenses. Companies are also able to use the Investment Allowance Scheme, which exempts an amount equal to a certain percentage of new investment from their taxable income.

Another preferential tax system offers accelerated depreciation of highly energy-efficient equipment, allowing business owners to shorten the equipment depreciation period from the customary three years to one year.

This tax system targets the stimulation of investment in highly energy-efficient technologies (e.g., heat recovery systems, variable-speed motors), seeking to encourage companies to replace existing power-consuming air conditioning systems, boilers, pumps, and other equipment with newer, more advanced systems.

(12) Conclusion

The improved standard of living brought about by continuing industrialization and technological progress will likely raise Singapore ’s domestic energy consumption, which in turn is expected to increase emissions of greenhouse gases such as carbon dioxide.

As a small island nation acutely aware of greenhouse gas emissions as a global environmental issue, Singapore is striving to reduce its greenhouse gas emissions by and by incorporating new technologies that allow the efficient use of energy.

1.1.3 The Need for Projects with Clean Development Mechanisms

In comparison to advanced industrial nations, Singapore ’s economy remains in the process of development. Further economic growth is expected to lead to increased energy consumption. Since Singapore lacks its own energy reserves, the nation ’s energy policies are likely to remain dependent on fossil fuels.

- 1 - 24 - Singapore has been active in implementing measures to mitigate global warming. The Singapore government has based its environmental preservation measures on environmental efforts examined and implemented by Japan, modifying them to suit the specific conditions of the country.

The government emphasizes both industrial development and environmental preservation and plans to ensure an optimal balance between the two. The nation plans to implement various energy conservation measures that minimize carbon dioxide emissions while enabling industries to improve the soundness of company management through fuel consumption reductions.

The Kyoto Protocol proposed in COP3 clarified the details of the Clean Development Mechanism. Singapore is willing to discuss with Japan the use of the Clean Development Mechanism when it is considered beneficial for both countries.

Based on the recognition that Singapore is still a developing country, Singapore is aware of the application of the Clean Development Mechanism (CDM) to emissions trading with advanced industrialized nations such as Japan.

In the past, Singapore has enthusiastically set about introducing advanced energy conservation technologies. If the nation considers it possible to achieve both economic growth and greenhouse gas emission reductions, it is also likely to implement the Clean Development Mechanism.

1.2 The Need for Industries to Introduce Energy Conservation Technologies

With its large-scale oil refineries and petrochemical centers, Singapore imports crude oil from the Middle East and other oil producing countries. The country relies heavily on fossil fuels. In 1994, C02 emissions in Singapore reached 26,800 giga-grams, 99% of which was produced by the combustion of fossil fuels.

Singapore currently has no regenerative energy sources with which to reduce its dependency on fossil fuels. It lacks hydroelectric or geothermal energy sources. Nuclear power facilities cannot be built for safety reasons. The sea around Singapore is relatively placid, making wave-generated power impractical. Due to its limited land area, Singapore ’s biomass does not represent a potential energy source. Finally, wind power is impractical due to Singapore ’s limited land area and relatively weak winds.

-1 - 25 - The only feasible method available to Singapore to reduce its greenhouse gas emissions is through higher energy efficiency in the operations of its oil refineries and petrochemical centers.

The industrial sector in Singapore is conducting business in a highly competitive international market, and a large portion of its products are exported, providing further impetus for the promotion of effective energy use.

1.3 Demand for, Significance of, and Impact of the Project, and Deployment of Output in Similar Industries

Products manufactured in the industrial complex are in high demand within the complex itself. Both the ethylene facility and the downstream polyethylene and polypropylene facilities maintain high operating rates and generate stable profits.

(1) Significance of the project

PCS places a high priority on improved corporate profitability and environmental issues. Equipment modification plans that will achieve both energy conservation and greenhouse gas reductions are likely to be implemented, once their economic benefits have been confirmed.

The Petrochemical Complex I on Merbau Island is an industrial complex consisting of PCS’s ethylene plant and the downstream facilities of four companies. The complex began operations in 1984. Using naphtha as its primary raw material, the core ethylene plant boasts an annual production capacity of 450,000 tons of ethylene and 225,000 tons of propylene.

(2) Deployment of project achievements in similar industries

The ethylene plant uses more fuel than any other system in the petrochemical complex. The majority of energy used by the ethylene facility is consumed by the cracker. The compressors used in the refining and separation processes also use significant amounts of electric power. Improving the energy efficiency of these fuel-consuming systems will reduce the fuel expenses that account for a large part of manufacturing costs.

- 1 - 26 - Table 1.2-1 Singapore’s ethylene production capacity and facility expansion plans

Current capacity Expansion plan Company Location License (t/yr) (t/yr) PCS (Complex I) Merbau 450,000 S&W PCS (Complex II) Merbau 515,000 85.000 s&w ExxonMobil Chawan 800.000 Kellogg Economic Development Board of Jurong 800,000 Singapore/Mobil

Table 1.2-2 Singapore’s propylene production capacity and facility expansion plans Current capacity Expansion plan Company Location License (Vyr) (t/yr) PCS (Phase I) Merbau 225,000 S&W PCS (Phase H) Merbau 257,000 42,500 S&W ExxonMobil Chawan 400,000 Kellogg Economic Development Board of Jurong 400,000 SineaDore/Mobil

The project being examined here includes the introduction of the advanced recovery system (ARS) to the existing equipment. The ARS was developed by Stone & Webster Company (S &W), after completion of PCS’s Complex I. It is therefore convenient to apply the ARS to Complex I. The system is patented by SWEC, and JGC Corporation has extensive experience with the system as an approved contractor, inclusive of PCS-II Complex.

Pinch analysis may be applied to all of the plants described above. Our company has applied pinch analysis to many domestic oil refineries and petrochemical companies to achieve energy use reductions.

Particularly in the ethylene plant, energy reductions must be achieved in each process. The project seeks to reduce carbon dioxide emissions by reducing the loads placed upon the boilers that generate steam to power (primarily) the cracked gas compressors, as well as the propylene and ethylene refrigerant compressors. The examination focused on improvements in heat recovery systems, introduction of the advanced recovery system (ARS), and installation of a gas turbine cogeneration.

Pinch Analysis enables comprehensive consideration of each utility source, such as steam, fuel, and electricity, within the various constricting conditions of the existing facility, making it possible to plan an optimum balance between the demand and supply sides. Pinch analysis is a powerful tool that allows quantitative verification of proposed measures for effective use of

-1 - 27 - low-pressure steam and reductions in fuel gas and electric power consumption.

Held in Kyoto in December 1997, the Third Session of the Conference of Parties to the United Nations Framework Convention on Climate Change (COP3) announced a commitment to the enforcement of legal responsibilities for reducing average annual emissions of greenhouse gases (carbon dioxide, methane, nitrous oxide, HFC, PFC, SF6) to 1990 levels during the period from 2008 to 2012.

The Kyoto Conference adopted “joint implementation, ” “clean development mechanisms, ” and “emissions trading ” as ways to lend flexibility to the numerical targets. The energy conservation project for PCS is applicable to the Clean Development Mechanism.

-1 - 28 - Chapter 2 Implementation of the Project Plan

Described below is the energy conservation plan, its contents, schedule, and budget for the Petrochemical Corporation of Singapore, for which the project is designed. Also included in this chapter are outlines of financial plans, fund procurement prospects, profitability, and the Singapore government ’ s assessment of and interest in the project.

2.1 Project Plan

2.1.1 Overview of project target area

(1) General outline of Singapore ’s natural environment

The Republic of Singapore is located between 103 degrees 38 minutes and 104 degrees 25 minutes east longitude and between 1 degree 9 minutes and 1 degree 29 minutes north latitude. It is an island country just north of the equator, situated at the southern end of the Malay Peninsula where the Malacca Strait meets the South China Sea.

The main island of Singapore is a geological extension of the Malay Peninsula, but is physically separated from the Peninsula by the narrow Johore Strait. The country features central and northern granite-ground plateaus, with Bukit Timah being the highest point at 177 m in elevation. The southwestern section has hilly areas with valleys, while the eastern part is lowland. From Bukie Timah, the Singapore River, Jurong River, and Geylang River flow south, and the Kranji River and Serangoon river flow east. These are all narrow rivers. Located on the central plateau, Singapore ’s remaining forests are designated as a watershed areas and forest preserves. The Seletar naval base is located near the deep waters in the east section of the Johore Strait. On the west side, the Johore Strait is generally shallow. Coral growth has been observed in the Singapore Strait, south of the island.

Two causeway bridges allow crossing to the Asian Continent by car or by rail. At the end of 1999, the land area of Singapore measured approximately 659.9 km2, roughly equivalent to Tokyo ’s 23 wards. This land area continues to increase as a result of large-scale land reclamation.

(2) Climate

Singapore ’s hot and humid tropical oceanic climate is partially attributable to seasonal monsoons. The annual average highest daytime temperature is 27.1°C. There are no pronounced dry or rainy

-2- 1 - seasons, and average, annual precipitation is 2,282 mm. Major Indonesian forest fires are capable of causing haze over Singapore.

(3) General outline of the Jurong area (history of Singapore ’s petrochemical complexes)

Singapore ’s petrochemical industry recorded production of S$4,961 million in 1999, a 15.1% increase over the previous year. Although this figure is slightly more than 1/3 of the total production of the oil refining industry, taking into account the industrial value added by this industry makes it a clear leader in manufacturing. With an annual production capacity of 800,000 tons of ethylene, the core product of the petrochemical industry, Exxon Mobil Chemical ’s cracker is to be soon completed, making Singapore the top ASEAN nation in this business sector. While Mobil ’s project (other than the above 800,000 cracker project) is unlikely to be realized due to the merger with Exxon, PCS, the leader in Singapore ’s petrochemical industry, has expressed its intention to construct a large cracker to augment its two existing crackers. This would result in a figure close to the three million tons of ethylene production capacity by the year 2010 envisaged by the Economic Development Board of Singapore. Backed by the extensive infrastructure represented by the Chemical Island Concept, currently in its final stage of completion, as well as its unparalleled logistics capabilities, Singapore is sharpening its competitive edge as Asia’s leading petrochemical center to rival the oil-producing nations of the Middle East.

1) Stage 1 (1971 -1984) Singapore ’s petrochemical industry is supported by a large-scale oil refining base that ranks among the world ’s largest (after those in Houston and Rotterdam). Nevertheless, it has a brief history of less than 30 years.

Singapore produced chemical products in the 1960s, but with limited production, both in scope and volume. In December 1971, the Singapore government took the first step toward full-scale development of the petrochemical industry by requesting the cooperation of Sumitomo Chemical, a leading Japanese chemical company, in the construction of a petrochemical complex.

At the time, the Japanese petrochemical industry was seeking to expand its overseas presence. These ambitions were embodied in a number of high-profile projects such as the Iran-Japan Petrochemical (IJPC) project led by the Mitsui Group, which later collapsed as a result of the Iran-Iraq War.

In response to the request from the Singapore government, Sumitomo Chemical concluded an FS contract in April 1974. In 1977, the Japanese government approved it as a national project.

-2-2- PCS was established in August 1997. A ground-breaking ceremony was held the following year to mark the project launch. In February 1984, PCS’s crackers began full-scale commercial operations producing their main derivatives (excluding EO/EG).

2) Stage 2 (1985 -1996) Having begun operating in the harsh business environment surrounding the petrochemical industry after the second oil crisis, PCS initially suffered through deficit operations due to low facility operating rates. However, within one to two years, the business took a favorable turn. An additional cracker was installed in 1989, and the success of this national project was lavishly praised, especially in light of the failure of the IJPC project.

In December 1992, a surprising event took place. In line with its privatization policies, the Singapore government sold its shares in PCS, resulting in Shell increasing its holdings to 50%. Shell thus gained the dominant shareholder position over Sumitomo Chemical, which had invested 23.11% of the initial capital and had to that point served as the largest shareholder.

In July 1994, American-based DuPont built a plant on Sakra Island with an annual production capacity of 110,000 tons of adipic acid. In 1995, it began producing nylon 66 polymer compound and boosted its spandex production, forming a large production base in Singapore.

3) Stage 3 (1997 - present) Several projects, including PCS’s Complex II (completed in 1997), marked the beginning of a new era for Singapore ’s petrochemical industry.

Singapore boasts an annual ethylene production of one million tons (when a regular overhaul is not performed). Various other value-added products are also manufactured, including: (1) Seraya Chemicals and Basell Eastern ’s PO/SM - polyol; (2) Celanese ’s vinyl acetate (VAM) - Poval Asia’s PVA; (3) an acrylic acid/acrylic acid ester (high-absorbency resins and MMA) made by Sumitomo Chemical and other SMAG groups; (4) phenol - BPA - polycarbonate resins made by Mitsui-Teijin and other groups; and (5) OXO Chemicals made by Eastman and other companies. The construction of Exxon Mobil Chemical ’s large cracker, which will be the company ’s third, is currently on schedule. Asahi Chemical-Mitsubishi Gas Chemical has begun producing new value-added products such as 2,6-xylenol - denatured PPE. In sum, Singapore ’s petrochemical industry is now entering a new phase of development.

As for the infrastructure supporting the petrochemical industry, the Chemical Island Concept launched in March 1995 has entered its final phase, and orders have been placed to the consortium formed by

-2-3- Penta-Ocean Construction Company. The project is scheduled for completion in early 2002. Singapore ’s esteemed logistics infrastructure will soon be further refined.

Figure 2.1-1 shows the location of the Singapore Petrochemical Complex. Figure 2.1-2 shows the overall of Merbau Island.

2.1.2 Project details

(1) Merbau Plant

The Complex I naphtha cracker of the Merbau Plant of Petrochemical Corporation of Singapore (PCS) is located in the Petrochemical Complex I on Singapore ’s Merbau Island.

PCS’s ethylene plant and four downstream process companies comprise the petroleum complex that began operating in 1984. The core ethylene facility uses naphtha as its primary raw material and has an annual production capacity of 450,000 tons of ethylene and 225,000 tons of propylene.

This facility maintains a high operating rate, thanks to expanding product demand in the complex. Since the commencement of operations, the demand from downstream companies has remained high, requiring several de-bottle-necking processes for the naphtha cracker in order to boost production capacity. In 1989, an additional naphtha cracker was added. In 1999, PCS strove to increase the production of both ethylene and propylene with the aim of improving naphtha cracker productivity and reducing costs.

To respond to increased demand, PCS has also undertaken the Singapore Complex II expansion on the island. (An account of this development falls outside the scope of the present study.)

Figure 2.1-3 shows the layout of the Complex I and Complex II Petrochemical Complex zones on Singapore ’s Merbau Island. Fig. 2.1-4 is a scheme of the overall complex.

-2-4- SINGAPORE PETROCHEMICAL COMPLEX Pulau Ayer tofeibeu

Figure 2.1-1 Location of Singapore Petrochemical Complex

-2-5 -

SINGAPORE PETROCHEMICAL COMPLEX Figure

2.2-3

Layout

of

the

Singapore -2-7-

Petrochemical

Complex on Merbau

Island

COMMON MATH Feedstocks Upstream Company Downstreams Companies

Petrochemical Corporation The Polyolefin Company ■QlSingapore (Pte) Ltd___ (Singapore) Pte Ltd LDPE 250,000 T.T.DPF______150,000

Chevron Phillips Singapore Chemicals (Pte! Ltd LPE 390,000 Ethylene 1,010,000 Seraya Chemicals Singapore (ElslLtd SM 315,000

Naphtha Ethylene Clycols Gas Oil (Singapore) Pte Ltd EO 45,000 LPG EG 122,000 EO Derivatives 35,000

Ethoxylates Manufacturing Pte Ltd Ethoxylates______18,000

Celanese Singapore Pte Ltd YAM 170,000

The Polyolefin Company (Singapore) P.te Ltd PP 350,000

Seraya Chemicals Singapore Propylene 505,000 (Pte)Tid PO 140,000 Polyols 78,000 Propylene Glycol 30,000

Singapore Acrylic Pte Ltd Acrylic Acid 60,000

Acetylene Denka Singapore Pte Ltd Acetylene Black 12,000

Kureha Chemicals (Singapore) Pte Ltd MBS 17,000 C4 Fractions Tetra Chemicals (Singapore) Pte. Ltd MTBE 55,000

Singapore MMA Monomer Thermal Cracked Gasoline Pte Ltd Benzene 270,000 MMA Monomer 50,000 Toluene 145,000 Xylene 95,000 Unit: Ton/Year

Figure 2.1-4 Scheme of the Overall Complex

-2-8- (2) Project details

The project is intended to achieve energy conservation and CO? reduction in the naphtha cracker and the related utility facilities in Complex I at PCS’s Merbau plant. The three pillars of the project are indicated below. Additional details are presented in 2.2.4.

1. The first improvement plan employs pinch technology analyses for better heat recovery performance. 2. The plant was originally designed in early 1980 by Stone & Webster (hereafter referred to as “S&W”). The second improvement plan introduces the ARS (Advanced Recovery System) modified and improved by S&W for energy conservation purposes. 3. The third improvement plan introduces the gas turbine generator cogeneration fueled by methane gas and heavy oil

Each of the above improvement plans can be implemented as a separate project, and the owner of each plant shall select the most appropriate one for their site. The most appropriate improvement plan can be determined in accordance with selection priorities, such as investment costs, economic effects of ROI, energy conservation effects, or greenhouse-gas reduction effects.

(3) Onsite study

Three onsite studies were conducted on the energy conservation measures to be taken at the PCS’s Merbau plant for the purpose of reducing a greenhouse gas (C02).

1) First-stage study For the first-stage study, the study team, comprised of five specialists from JGC Corporation and one specialist from the Singapore Office of JGC Corporation, visited the PCS’s Merbau plant in Singapore from September 18 through September 21,2000. They obtained relevant documents and information, and studied the operational conditions of the existing facilities. The results revealed possible ways of improving the heat recovery system.

(a) Members of the study team Mr. Ryosaku Saito (Project Manager, JGC Corporation) Mr. Masato Yanada (Engineering Manager, JGC Corporation) Mr. Takashi Tanaka (Furnace Engineer, JGC Corporation) Mr. Kazunobu Saito (Process Engineer, JGC Corporation) Mr. Tsuyoshi Yamamoto (Process Engineer, JGC Corporation)

-2-9- Mr. Koji Sakurai (Manager, Singapore Office, JGC Corporation)

(b) Study schedule Study schedule Start: September 18, (Monday) 2000 End: September 21, (Thursday) 2000.

Date Destination Study item September 18 Departing from Tokyo, arriving at (Monday) Singapore September 19 Merbau plant Explanation of study objectives and (Tuesday) schedule September 20 Merbau plant Study objectives (Wednesday) September 21 Arriving at Tokyo (Thursday)

(c) List of interviewees Interviews were conducted with the following personnel at PCS’ Merbau plant. Mr. Akinori Kuroki General Manager Mr. Tadaki Matsuo Manager, Manufacturing Planning Mr. Yoshito Seo Senior Technical Advisor Mr. Chong Ming Cheong Technical Manager Mr. Ng Chee Wai Olefin-1 Assistant Manager Mr. S K Joshi Engineering Principal Planner Mr. Bernard Leong Lian Wah Process Principal Planner Ms. Tan Peck Luan Process Engineer

(d) Study details The first-stage study was primarily designed to obtain basic data and conduct relevant research on the naphtha cracker Complex I, the target equipment of the study.

-2-10- Prior to the study, the team had obtained various design-related documents, operational data, and reference materials from Singapore. After noting missing materials and ambiguities, the study team left for Singapore. The team acquired the missing data and clarified ambiguous points. It investigated operational conditions of the target equipment, as well as the installation conditions. It also photographed the equipment.

Documents used to explain the study objectives for the partner are included as attachments.

2) Second-stage study For the second-stage study, the study team, comprised of five specialists from JGC Corporation and one specialist from the Singapore office of JGC Corporation conducted the onsite study at PCS’s Merbau plant for four days from December 6 through December 9,2000.

(a) Members of the study team Mr. Ryosaku Saito (Project Manager, JGC Corporation) Mr. Masato Yanada (Engineering Manager, JGC Corporation) Mr. Hisato Aoyama (Planning Engineer, JGC Corporation) Mr. Takeshi Koyama (System Engineer, JGC Corporation) Mr. Tsuyoshi Yamamoto (Process Engineer, JGC Corporation) Mr. Koji Sakurai (Manager, Singapore Office, JGC Corporation)

(b) Study schedule Study schedule Start: December 6, (Wednesday) 2000 End: December 9, (Saturday) 2000.

Date Destination Study item December 6 Departing from Tokyo, arriving at (Wednesday) Singapore December 7 Merbau plant Study objectives and interim study (Thursday) Government of Singapore report Study on the government ’s stance on greenhouse gas emissions December 8 Merbau plant Study objectives and interim study (Friday) report December 9 Arriving at Tokyo (Saturday)

-2 - 11 - (c) List of interviewees Interviews were conducted with the following personnel at PCS’s Merbau plant. Mr. Akinori Kuroki General Manager Mr. Tadaki Matsuo Manager, Manufacturing Planning Mr. Yoshito Seo Senior Technical Advisor Mr. Ng Chee Wai Olefin-1 Assistant Manager Mr. S KJoshi Engineering Principal Planner Mr. Bernard Leong lian Wah Process Principal Planner Ms. Tan Peck Luan Process Engineer

(d) Study details The interim report presented the results of studies using the basic data obtained during the first-stage study. Additional basic data were obtained and onsite studies were also conducted.

The study team reported on the results of the modifications required for energy conservation, and discussed the details with their partner. It was confirmed that the final review should proceed in accordance with the results of this interim report.

The interim report on the second-stage study conducted in cooperation with the partner is included as an attachment.

The following are the minutes of the discussion with the partner. a) Heat recovery improvement by pinch technology The results suggest the minimum differential temperature is 3.5°C for propylene refrigerant; but the impact of temperature changes should also be studied; e.g., if the temperature is changed to 3°C or 2.5°C.

The steam balance allows for low-pressure steam from external OSBL, however the reduction of this steam has been found to be effective for energy conservation. Therefore the low-pressure steam

- 2 - 12 - reduction will also studied.

The study team obtained the missing data on the basics of the boiler water-supply lines, and the pinch study on the hot end shall be completed using that data.

b) Improved efficiency of the cracking furnace Studies were conducted on whether it is possible to conserve energy by enhancing the economizer of the cracking furnace. Significant energy savings were not detected, as the temperature of the boiler feed water is 140°C (preheated at medium pressure after being released from the deaerator to maintain the steam balance). c) Results of gas turbine cogeneration studies The study on power demands within the premises revealed that additional electric energy required for Downstream Plant (nearly 30MW) must be provided. As a result, the case study (Case 2 below) shall be added to the current study (Case 1 below).

Case 1: 70 ton/h of ultra-high pressure steam (SU) are generated by heat recovery steam generation (HRSG) and GTG is 17 MW when the entire power demand at the PCS-1 Plant is limited to 16-17 MW.

Case 2: When GTG is used to generate the combined 47 MW required by PCS-1 and Downstream Plant, steam is generated using HRSG at the rate of 120 ton/h. However, since this rate may fluctuate, duct firing is used to supplement the steam supply.

The partner favors the establishment of the gas turbines. They would like to implement the project to reduce the unit requirements and C02 emissions.

3) Third-stage study For the third-stage study, the study team, comprised of five specialists from JGC Corporation and one specialist from the Singapore office of JGC Corporation conducted the onsite study at PCS’s Merbau plant for four days from February 28 2001 through March 3,2001.

(a) Members of the study team Mr. Ryosaku Saito (Project Manager, JGC Corporation) Mr. Masato Yanada (Engineering Manager, JGC Corporation) Mr. Hisato Aoyama (Planning Engineer, JGC Corporation) Mr. Takeshi Koyama (System Engineer, JGC Corporation)

-2-13- Mr. Tsuyoshi Yamamoto (Process Engineer, JGC Corporation) Mr. Koji Sakurai (Manager, Singapore Office, JGC Corporation)

(b) Study schedule Study schedule Start: February 28, Wed., 2001 End: March 3, Sat., 2001

Date Destination Study item February 28 Departing from Tokyo, arriving at (Wednesday) Singapore March 1 Merbau plant Study objectives and final study report (Thursday) March 2 Merbau plant Study objectives and final study report (Friday) March 3 Arriving at Tokyo (Saturday)

(c) List of interviewees Interviews were conducted with the following personnel at PCS’s Merbau plant. Mr. Tadaki Matsuo General Manager Mr. Yoshito Seo Senior Technical Advisor Mr. Ng Chee Wai Olefin-1 Assistant Manager Mr. SKJoshi Engineering Principal Planner Mr. Bernard Leong Lian Wah Process Principal Planner Ms. Tan Peck Luan Process Engineer

(d) Study details The final report was presented on the studies using the basic data obtained in the first and second stage studies. Onsite studies were conducted to confirm the final modification plan.

The study team reported on the results of the modifications required for energy conservation, and

-2-14- discussed the details with their partner.

The final report on the third-stage study conducted in cooperation with the partner is included as an attachment.

The study results of ceramic coating for an existing cracking furnace radiant tube in a domestic ethylene plant were reported. Although the thermal efficiency of radiant section is improved, the overall furnace efficiency is not improved after ceramic coating since stack gas temperature is the same as before ceramic coating. We came to the conclusion that ceramic coating does not contribute to reduce C02 emission, and decided no further study.

The projects of improvement in heat recovery systems and cogeneration with a gas turbine generator are expected to be the fruitful implementations for the purpose of reducing energy consumption.

2.13 Greenhouse gas under study and related issues

The greenhouse gas to be considered in this project is carbon dioxide (C02). Carbon dioxide is emitted through combustion from the cracking furnaces and boilers comprising the ethylene plant. In the cracking furnace, fuel gas is used to reach the temperatures required to obtain olefin by cracking naphtha. As for the boilers, fuel gas and fuel oil are used to produce the steam necessary to power the compressors that compress the cracked gas produced at the cracking furnace, and for the refrigerant compressor (propylene refrigerant and ethylene refrigerant) used to separate and refine the cracked gas. The fuel gas and fuel oil are composed of various hydrocarbons. When combusted, they produce water (steam) through oxidation of the hydrogen in the fuel, and C02 through oxidation of carbon.

2.2 Overview of Implementation Sites (Companies)

23.1 On-site Interest

Alongside the electronics industry, Singapore ’s petrochemical industry (including oil refineries) occupies a vital strategic position in the nation ’s economic engine. A qualitative expansion of the petrochemical industry is currently being promoted, based on an articulated strategy in line with 1-21, the Singapore government ’s economic vision for the first decade of the 21st century. The ethylene center at the project site consists of PCS’s Complex I (450,000-ton plant), which began operations in 1984, and Complex II (515,000-ton plant) that commenced operations in 1997. The number of companies receiving ethylene directly from PCS is around 10, and PCS is responsible for supplying this important raw material. Downstream, several dozen chemical companies operate their plants

-2-15- relying on ethylene, propylene, and other derivatives as raw materials.

PCS has previously upgraded both the ethylene plants I and II. PCS’s Complex I has been operational for more than 16 years, and the company is actively seeking ways to improve plant efficiency, promote environmental preservation, and reduce greenhouse gas emissions. These considerations represent significant guiding principles for the modifications and improvements for Complex I, which plays such an important role in Singapore ’s strategic industry.

2.22 Facility Conditions at Project Site (Company) (General Outline, Specifications, Operating Conditions)

(1) Configuration of the Complex I naphtha cracker facility

The processing of raw naphtha begins with preheating. Preheated naphtha is supplied to the crackers (F-110 - F-190) together with dilution steam for thermal cracking. This process produces hydrogen, methane, ethylene, propylene, C4 fractions such as butadiene, gasoline fractions such as BTX, and cracked fuel oil. The cracked gas is sent to the transfer line exchanger (TLE), where it rapidly cools and generates ultra high pressure steam. It is then fed to the T-210 (Quench Oil Fractionator) to separate the cracked fuel oil. Following this process, it is sent to the T-220 (Quench Water Tower), where direct cooling by the quench water liquefies and condenses the cracked gasoline and dilution steam. The cracked gas is then sent to the cracked gas compression process.

The two towers used for the above processes generate significant heat. Heat produced by the Quench Oil Fractionator is recovered in the quench oil and pan oil. Heat generated by the Quench water Tower is recovered in the quench water. The recovered heat energy is used to generate dilution steam and as a heat source for distillation reboilers.

The cracked gas is pressurized by the C-300 (Cracked Gas Compressor) and sent to separation processes that compress and cool the gas for gas liquefaction, low-temperature separation, and distillation to produce various products. The compressor has four compression stages, with the T-350 (Caustic Scrubber) removing acidic vapor from the cracked gas. The caustic scrubbing process removes C02 and H2S from the cracked gas.

The compressed cracked gas is dehydrated by the molecular sieve, and then sent to the low-temperature separation process, where it is cooled to a temperature of -160°C for hydrogen separation. The resulting hydrogen is passed through the R-460 (Methanator) to remove the CO, and the resulting product is refined into hydrogen for hydrogenation and product hydrogen.

-2-16- The condensate separated from the hydrogen gas in the liquefaction process is fed to the T-420 (Demethanizer), where methane is extracted as the overhead product.

The bottom product in the Demethanizer is sent to the T-430 (Deethanizer). Since the overhead product in the Deethanizer contains ethylene and ethane as well as acetylene, it is sent to the Acetylene Recovery Unit, where DMF absorbs and collects the acetylene. Following removal of the acetylene, the ethylene and ethane fractions are supplied to the T-440/450 (Ethylene Column) to separate ethylene as a product. After heat energy is recovered from the ethane of the bottom product of the column, the ethane is recycled to the crackers.

Using propylene and ethylene refrigerants, the cooling operations in the low-temperature separation process have high power requirements. The multi-fluid plate core heat exchangers collect energy from various cryogenic fluids, while the low-temperature distillation boilers recover energy from other fluids. The refining system features measures, such as these, to improve efficiency.

The bottom product of the Deethanizer is sent to the T-510 (Depropanizer). Since the overhead product contains propylene, propane, methyl acetylene and propadiene, the R-520/522/523 (C3 Hydrogenation Reactor) is used for selective extraction of propylene. The crude propylene from the C3 Hydrogenation Reactor is sent to the T-530 (Secondary Deethanizer) to remove light fractions (methane, ethane), and then fed to the T-540/550 (Propylene Column) to produce product propylene.

The material extracted from the bottom of the Depropanizer is delivered to the T-560 (Debutanizer), in which C4 fractions are extracted from the overhead product and gasoline fractions are removed from the bottom of the tower.

Figure 2.2-1 is a schematic flow diagram of the Complex I naphtha cracker facility, and Figure 2.2-2 is a photograph. Figures 2.2-3 to 2.2-6 show the main systems of the facility.

-2-17- T-510 I--.35Q FURNACE QUENCH OIL QUENCH DISTILLATE WATER STRIPER CRACKED GAS CAUSTIC FRACTIONATOR WATER TOWER STRIPPER COMPRESSOR SCRUBBER

PAN OIL USER

QW USER

NAPHTHA

FUEL OIL

T-440/450 DEMETHANIZER DEETHANIZER ETHYLENE COLUMN

CG METHANE ETHYLENE DEHYDRATOR C-600 CHILLING PROPYLENE REFRIGERANT SECTION COMPRESSOR ACETHYLENE

T-380 ACETHYLENE CONDENSATE R-460 RECOVERY STRIPPER METHANATOR D-370 UNIT LIQUID DRYER C-65Q ETHYLENE REFRIGERANT COMPRESSOR FOW-UJ

ETHANE

HYDROGEN

DEPROPANIZER PROPYLENE COLUMN C4's PROPYLENE

T-530 SECONDARY T-560 R-520/522/523 DEETHANIZER DEBUTANIZER C3 HYDROGENATION REACTOR

@BsnMcmiiBaaaRPORHnoNi

SCHEMATIC FLOW DIAGRAM

No. 1 Naphtha Cracker C3 LPG GASOLINE

Figure 2.2-1 Schematic Flow Diagram of the Complex I Naphtha Cracker Facility

• 13 (a) tenants. nesn^ocn. nvaczeuenaTueseu Figure 22-2 Complex I Naphtha Cracker Plant

Figure 2.2-3 Quench Oil Fractionator (right) and Quench Water Tower (left)

2-21 Figure 2.2-4 Compressor Shelter

Figure 2.2-5 Low-temperature Distillation Towers (viewed from the west)

2-22 Figure 2.2-6 Low-temperature Distillation Towers (viewed from the southeast)

(2) Utilities and weather conditions

1) Steam Table 2.2-1 shows the steam conditions used in the Merbau Plant.

Table 2.2-1 Steam Conditions at Merbau Plant Steam Pressure (Kg/cmzG) Temperature (°C) SU Ultra High Pressure Steam 106.3 482 SH High Pressure Steam 40.4 375 SM Medium Pressure Steam 14.0 239 SL Low Pressure Steam 3.5 160

Condensate Steam Condensate (#200) - 142 Steam Condensate (#50) - 100 Cold Condensate - 50

Ultra-high pressure steam (SU) is generated from the boilers (2 units) and by heat recovery at the crackers. The majority of this heat energy is used to operate the compressors (steam turbines).

- 2 - 23 - Extracted from the compressor-driving steam turbines, high pressure steam (SH) is used to operate the main pumps and is also consumed in the reboilers of the distillation towers. Some of the SH is exhausted from the system.

Extracted from the compressor-driving steam turbines, medium pressure steam (SM) is used to generate dilution steam for use by the crackers and is also consumed in the reboilers of the distillation towers. Some of the SM is exhausted from the system.

Low pressure steam (SL) is extracted from the compressor-driving steam turbines. Additional SL is received from OSBL, to be consumed primarily in the reboilers of the distillation towers.

2) Fuel gas Table 2.2-2 shows the characteristics of the fuel gas used in the Complex I naphtha crackers.

Table 2.2-2 Characteristics of Fuel Gas for Complex I Naphtha Crackers LEV, kcal/Nm3 8,134 Pressure, Kg/cm2G 2.5 Temperature, °C 54

In the process of separating and refining cracked gas, the Demethanizer separates methane, which is used as a fuel gas. It is burned to reach the temperatures required to obtain olefin by cracking naphtha and gas oil. It is also used as a fuel for boilers. Some of the methane is exhausted from the system.

3) Fuel oil Table 2.2-3 shows the characteristics of the fuel oil used in the Complex I naphtha crackers.

Table 2.2-3 Characteristics of Fuel Oil for Complex I Naphtha Crackers SPGR 1.03 LEV, kcal/kg 9,773

Cracked gas is rapidly cooled in the Quench Oil Fractionator to separate cracked fuel oil from the cracked gas. The cracked fuel is used, in part as a fuel for boilers; the rest is sent to a fuel oil pool.

4) Conditions of other utilities Table 2.2-4 shows the conditions of the other utilities used by the Complex I naphtha crackers.

- 2 - 24 - Table 2.2-4 Conditions of Other Utilities Condition Sea Water Supply, °C 29.6 Sea Water Return, °C 37.4 Ultra High Pressure BFW 140°C, 138 Kg/cm2G Medium Pressure BFW 140°C, 34.6 Kg/cm2G Pure Water 40°C, 10.0 Kg/cm2G Industrial Water, Kg/cm2G 4.0 Drinking Water, Kg/cm2G 2.0 Fire Fighting Water, Kg/cm2G 10.0 Instrument Air, Kg/cm2G 6.5 Service Air, Kg/cm2G 6.5 Nitrogen, Kg/cm2G 6.5

Industrial water, drinking water, and electric power are supplied by the PUB (Public Utilities Board).

5) Weather conditions Table 2.2-5 shows the weather conditions at the Merbau Plant. 3

Table 2.2-5 Weather Conditions and Other Related Factors Wind Pressure, kg/m2 Height from Ground Level (m) Up to 10 85 20 100 30 110 40 120 50 127 60 133 Over 60 139 Seismic Factor No Consideration Relative Humidity, % 85 Dry Bulb Temperature, *C 31.2 Wet Bulb Temperature, ‘C 28.4 Rain Fall, mm/h General 117 (30minutes) Diked Area 20 (6hours) Snow Load No Consideration Barometric Pressure, mmHg Year Average 757 Maximum 763 Minimum 753

(3) Analysis of current operations

1) General The raw materials fed to the crackers are naphtha, recycled C4, and raffinate.

- 2 - 25 - The products output from the crackers are hydrogen, methane, fuel gas, acetylene, ethylene, propylene, C4 fractions, cracked gasoline, and fuel oil. The gross production rate of ethylene is 1,340 ton/day, propylene 780 ton/day.

2) Utility Summary Figure 2.2-7 indicates the externally supplied utilities used by the Complex I naphtha crackers and the utilities output by the crackers.

Fuel Gas j SU sy i SL ! #200 sg ^1 i j UP BFW No.1 NAPHTHA CRACKER #50 sp i MP BFW COLD CON% 5 LP BFW t------DEMIfl

Electricity ------ENERGY CONSUMPTION ENERGY GENERA TED

Figure 2.2-7 Utilities Used and Output by Complex I Naphtha Crackers

As in many other ethylene plants, the crackers consume the majority of the energy.

The amount of energy used for thermal cracking accounts for about half of all the energy used by the plant per production unit (energy consumed to produce 1 kg of ethylene). The process with the second largest energy consumption is the supply of SU (Ultra High Pressure Steam).

The crackers bum fuel gas, and the boilers burn fuel gas and fuel oil to generate SU. Both processes produce carbon dioxide, a greenhouse gas.

3) Cracker operating conditions There are a total of nine crackers, F-110 to F-190. At any given time, eight crackers are operated, and one is either being decoked, or in a hot standby condition. The F-190 is an ethane cracker.

All crackers operate at above 100% of the design load, indicating their high operating rates.

The exhaust gas temperatures for crackers F-110 through F-180 are around 180°C. Considering the use of fuel gas to heat the furnace, this temperature is relatively high.

- 2 - 26 - Upgrades for the economizer (preheater for boiler feed water) may be considered to improve cracker efficiency.

Economizer performance can be improved by adding an economizer coil between the IDF and the top convection section. This requires the replacement of the breeching section shown in Figure 2.2-8. However, since the temperature of the boiler supply water is 140°C, even extensive modifications would fail to produce notable improvements. Improving cracker efficiency from current levels will be difficult.

-2-21 - Figure 2.2-8 Cracker Breeching Section

- 2 - 28 - 4) Cracked gas compressor The quench section cools crack gas to near ambient temperatures. Cracked fuel oil, cracked gasoline, and dilution steam in cracked gas are condensed and separated, after which the cracked gas compressor pressurizes the gas and sends it to the low-temperature separation system.

The cracked gas compressor has four compression stages and is driven by a steam turbine. The turbine is a combined condensation/extraction steam type. The turbine uses SU and extracts SM.

5) Ethylene refrigerant compressor The low-temperature separation and low-temperature distillation systems use coolants other than sea water. An ethylene refrigerant is used as a cold refrigerant less than -40°C.

The ethylene refrigerant compressor consists of three stages and is driven by an extraction steam turbine. The turbine uses SU and extracts SM.

6) Propylene refrigerant compressor The low-temperature separation and low-temperature distillation systems use coolants other than sea water. A propylene refrigerant is used as a refrigerant above -40°C but below ambient temperatures.

The propylene refrigerant compressor consists of four stages and is driven by a condensation/extraction steam type turbine. The turbine uses SU and extracts SH.

2.2.3 Project implementation capabilities of implementation sites (companies)

(l) Technical prowess

PCS’s technical prowess is based on more than twenty years of experience and their excellent track record in the construction and operation of ethylene plant and various downstream petrochemical facilities. This ensures that PCS maintains significant levels of technological prowess in all relevant areas including engineering, plant operation, and facility maintenance. PCS should have no significant technical problems in owning and running the project considering its experience in past projects.

- 2 - 29 - (2) Management

The ultimate responsibility for management of Petrochemical Corporation of Singapore (Private) Limited belongs to the Managing Director and under his direction and supervision, the corporate organization consists of business division and production division. The business division is in charge of corporate administration, public relations, purchasing and corporate IT infrastructure while the production division is in charge of olefins production. The production division is directed by the General Manager, Plant and consists of Olefin 1 department in charge of operation of the Complex 1, Olefin 2 department in charge of operation of the Complex 2, Offsite department in charge of operation of offsite/utilities facilities, Facilities department and Projects department.

(3) Management infrastructure and management policy

PCS was established on August 10, 1977 as a joint venture between the Government of Singapore and Japan-Singapore Petrochemicals Company, Ltd. (lead-manager: Sumitomo Chemical Co., Ltd.) with the shareholding ratio of 50:50 in accordance with Singapore ’s policy to nurture the petrochemical sector. In 1984, the company established Complex I, which is centered on ethylene plant with an annual production capacity of 300,000 tons (subsequently expanded to 450,000 tons). In 1997, PCS began the operation of Complex II, which features ethylene plant with an annual production capacity of 515,000 tons. Both of these plants are still successfully operating. The shares held by the Singaporean government were subsequently transferred in 1989 and 1992 to Shell, a leading global petroleum company. Currently, the company is incorporated as a joint venture with a shareholding ratio of 50:50 between Japan-Singapore Petrochemicals Company and Shell Eastern Chemicals. The authorized capital now stands at S$750 million; the paid-up capital is S$343,353,000. The venture ’s 400 employees comprise mostly Singaporeans. The management objective is to be the regional leader in manufacturing and sales of petrochemical products primarily through sales to downstream companies in Singapore Petrochemical Complex. PCS is committed to a reliable supply of cost-effective quality products, high standard in safety and environmental protection, and social corporate responsibilities.

(4) Financial support capability

Necessary funds are expected to be financed from external loans. Judging from the favorable management environment, there appears to be no problems concerning the company ’s financial support capability once the project is implemented. The implementation of the project is

- 2 - 30 - expected to require approximately 460 million to 9.60 billion Japanese Yen depending on the cases to be implemented.

(5) Personnel support capability

Judging from PCS’s historical production and sales performance, there should be no significant problems in these areas. PCS is highly capable of researching, evaluating, and handling new technologies.

(6) Implementation system

The organization of the company compares favorably with that of similar petrochemical plants in Japan, presenting no problems in this area.

2.2.4 Contents of Project for Project Site (Company) and Specifications of Facilities after Modifications

The project seeks to reduce carbon dioxide emissions by reducing the loads placed upon the boilers that generate steam to power (primarily) the cracked gas compressors, as well as the propylene and ethylene refrigerant compressors. The examination focused on improvements in heat recovery systems, introduction of the advanced recovery system (ARS), and installation of a gas turbine cogeneration. Given below is a detailed account of this examination.

(1) Examination of heat recovery improvement plans based on pinch technology

One method for reducing carbon dioxide emissions from the plant is to decrease the boiler load.

Reducing stream consumption is required in order to do it. Heat recovery improvement analysis focused on reducing the steam consumption to heat fluids and drive compressors.

Enthalpy changes in the heated fluids and cooled fluids were individually plotted and composite curves produced, after which the temperature difference (DTmin) at the location where the two curves are closest (pinch point) was analyzed. Figure 2.2-9 shows the existing composite curves of the ethylene plant. As shown in the diagram, the temperature range is very broad. Given the impracticality of examining all the regions together, they were divided into three sections, as shown below.

-2-31 - 1. Ethylene refrigerant system 2. Propylene refrigerant system 3. Hot end (other than above)

Hot End ~| Hot Composite Curve

Cold Composite Curve

Propylene Refrig

Ethylene Refrig Cold End

Auto-Refrig

Enthalpy[MMkcal/hr]

Figure 2.2-9 Composite Curves of the Ethylene Facility

1) Ethylene refrigerant system (a) Existing analysis of the heat recovery conditions First, the conditions of the current heat recovery operation were studied to evaluate the possibility of improving heat recovery from the ethylene refrigerant system.

Figure 2.2-10 shows the composite curves of the current operation. In general, the optimum DTmin is about 3°C. The diagram shows a DTmin value of 1.5°C, indicating adequate heat recovery efficiency.

Figure 2.2-11 shows the grand composite curves for current facility operations. This diagram was used to examine utility placement. The diagram also gives the enthalpy curves of the process and utility (ethylene refrigerant; hereafter indicated as C2R). As shown in Figure 2.2-11, there are three levels of C2R, which are C2R-1, -2 and -3. The diagram suggests that low-temperature C2R consumption can be reduced by partially shifting C2R refrigeration to higher temperature levels.

- 2 - 32 - (b) Examination of heat recovery improvement plans An analysis was performed to estimate the energy-savings attained through optimum C2R distribution. Since DTmin is currently low enough, the target DTmin was set at the current value of 1.5°C. The results of the analysis are shown in Table 2.2-6. The expected decrease in compressor power consumption was about 7.0 KW.

Since analysis indicated that heat was recovered efficiently from the equipment, it was determined not to undertake a detailed examination of the ethylene refrigerant system to improve heat recovery.

Table 2.2-6 Expected Energy-saving Modification Chilling Duty Saving [MMkcal/hr] Total 0.0 Power Saving [kW] Total 7.0

-2-33- 0 O

C2R-1

C2R-2

DeC1 OVHD C2R-3

Pinch Point

Enthalpy[MMkcal/hr]

Figure 2.2-10 Composite Curves of the Ethylene Refrigerant System (Existing)

Potential of changing levels

Process Grand Composite Curve

C2R-1

C2R-2

DeC1 OVHD C2R-3

Utility Grand Composite Curve

Auto-refrigerant section

Enthalpy[MMkcal/hr]

Figure 2.2-11 Grand Composite Curves of the Ethylene Refrigerant System (Existing)

-2-34- 2) Propylene refrigerant system (a) Existing analysis of the heat recovery conditions The current heat recovery conditions in the propylene refrigerant (hereafter indicated as C3R) systems were analyzed by using composite curves and grand composite curves as same as the ethylene refrigerant systems analysis.

Figure 2.2-12 shows the composite curves of the current facility operation. In general, optimal DTmin in a propylene refrigerant system is about 3 to 4°C. The diagram shows a DTmin value of 3.5°C, apparently indicating sufficient heat recovery efficiency.

Figure 2.2-13 shows the grand composite curves for current operations. There are four levels of C3R, which are C3R-1, -2, -3 and -4. The curve of the C2R extends to the left side of the temperature axis, indicating that more than the minimum required amount of utility is used.

The gray areas formed by the overlap of the process curve in Figure 2.2-13 suggest the potential for inter-process heat recovery. In the propylene refrigerant systems, the distillation tower reboiler and condenser use C3R for heating and cooling. However, the grand composite curves indicate the excellent compatibility of cracked gas, demethanizer feed, and distillation tower condenser with the distillation tower reboiler. The heat recovery by using this combination may reduce C3R consumption - that is, makes the compressor of the propylene refrigerant system more efficient. Based on these existing analysis results, a heat recovery improvement plan was formulated.

- 2 - 35 - Figure

Figure Temperature[°C]

2.2-13 Condensing Utility Ethylene CT440. D630

2.2-12

D640 D640

C3R-2 Grand

VAP T442) Grand C3R-1

Pinch Rectifier

VAP LIQ Condensing

C3R-4

Composite DeC1 DeC2

OVHD Composite

Point

Sub-cooling

Condensing

Composite

Feed OVHD, C3R-3

Curve

Curves

Curves t3R-3

Enthaply[MMkcal/hr] of EnthalpytMMkcal/hr] - Cracked DeC3

2

Propylene

of -

OVHD, 36

Propylene

/

Gas Ethylene Reboiler Ethylene

Process -

Cracked Ethylene Cracked

Refrigerant

Rectifier(T440, Rectifier(T440) DeCt DeC3 Grand Ethylene DeC?

C3R-4 Gas Refrigerant

Rectifier(T440) Gas

Reboiler

Reboiler Ethylene OVHD. from OVHD.

from Composite

Stripper(T450.

C300-4th

T441) DeCl. C300-4th

DeC1 Stripper(T450,

System

Reboiler

Feed

OVHD

Feed

System Curve DeC1

T442)

(Existing) Reboiler

T442)

Reboiler

(Existing)

(b) Heat recovery improvement plan Since the current DTmin value is sufficiently low, it was determined that the target DTmin was set at the existing value of 3.5°C for study on the heat recovery system. Several plans are described below and the energy savings provided by different combinations of these methods compared. a) Heat recovery improvement plan 1 (INT-1) This plan focuses on the recovery of heat from the cracked gas (refrigerant: C3R-1 and the demethanizer (T-420) reboiler (heat source: C3R vapor). According to CD in Figure 2.2-13, the fluids showed excellent heat recovery potential. Recovery of heat from them makes it possible to reduce the cooling load imposed by C3R-1.

Figure 2.2-15 shows a schematic flow diagram for this improvement plan. The present cracked gas cooler (E-342AB) and demethanizer reboiler (E-420AB) are removed, and a new reboiler (E-420CD) using cracked gas is installed as the heat source. b) Heat recovery improvement plan 2 (INT-2) This plan calls for heat recovery between the distillation towers of the depropanizer condenser (refrigerant: C3R-2) and the ethylene stripper (T-450) reboiler (heat source: C3R vapor), which is shown in (D of Figure 2.2-13. Recovery of heat from this source would reduce the cooling load imposed by C3R-2.

Figure 2.2-16 shows a schematic flow diagram for this improvement plan. The existing ethylene stripper reboiler (E-450) is replaced with a new reboiler (E-450B) that uses depropanizer OVHD vapor as a heat source.

Since the reboiler cannot meet the total cooling demand of the depropanizer condenser, the existing condenser (E-515) is used to provide supplementary cooling. c) Heat recovery improvement plan 3 (INT-3) This plan involves heat recovery from the demethanizer feed (refrigerant: C3R-2,3,4) and the ethylene rectifier (T-440) reboiler (heat source: C3R vapor). According to (B) in Figure 2.2-13, the matching between them indicate excellent heat recovery potential. Recovery of heat from this source makes it possible to reduce the cooling load imposed by C3R-2,3,4.

Figure 2.2-17 shows a schematic flow diagram for this improvement plan. A new ethylene rectifier reboiler (E-440B) that uses the demethanizer feed as its heat source is installed. Since

- 2 - 37 - the demethanizer feed cannot meet the total heat demand, the existing reboiler (E-440) is also used to provide heat. d) Heat recovery improvement plan 4 (INT-4) (D and (3) in Figure 2.2-13 indicate two potential methods of heat recovery. One method is described in INT-3 above. The other method is to exchange heat between the demethanizer feed (refrigerant: C3R-2,3,4) and de-deethanizer (T-430/432) condenser, and between the ethylene stripper (T-442) reboiler and ethylene rectifier (T-440) reboiler (heat source: C3R vapor). This heat recovery system can reduce the cooling load imposed by C3R-2,3,4.

Figure 2.2-18 shows a schematic flow diagram for this improvement plan. New reboilers (E-440B/C) that use demethanizer OVHD vapor and demethanizer feed as heat sources are replaced instead of the present ethylene rectifier reboiler (E-440).

At the same time, an ethylene stripper reboiler (E-442B) using the demethanizer feed as its heat source is installed. Since the demethanizer feed cannot meet the total heat demand, the existing reboiler is also used to provide heat. e) Heat recovery improvement plan 5 (INT-5) Under the existing configuration, the fluid at the outlet of the C3R compressor is cooled by vaporization of ethane product installed in parallel with the cooler using sea water. Due to the lower temperature fluid of the ethane product, it is preferable to install the vaporizer at the cold end of the cooling path. Thus, the location of ethane vaporizer is moved downstream of the existing methane vaporizer. Figure 2.2-19 shows a schematic flow diagram for this improvement plan.

(c) Comparison of energy savings Energy-saving results in a propylene refrigerant system are evaluated based on reductions in power consumed by the propylene compressor. While a number of combinations of the different methods are available, compressor power demand was calculated for the following combinations. An analysis was then performed to determine the most suitable combination of methods.

- 2 - 38 - Case Combination of heat recovery methods CASE-1 INT-2 CASE-2 INT-2 & 3 CASE-3 INT-1, 2,3 & 5 CASE-4 INT-1, 2, 4 & 5

Table 2.2-7 shows the energy savings in individual cases. The graph in Figure 2.2-14 indicates the relationship between the required additional heat transfer area and the compressor power consumption reduction. In CASE-2 and subsequent combinations, the power-consumption reduction rate decreases relative to the additional heat conducting area. Although only the additional heat conducting areas were evaluated and compared, when piping modifications are considered, the energy savings achieved by combining a larger number of methods are expected to be smaller than indicated in the graph of Figure 2.2-14. Based on these results, CASE-2 or CASE-3 appears to be the most suitable heat recovery system.

Table 2.2-7 Energy Savings in Individual Cases CASE-1 CASE-2 CASE-3 CASE-4 Chilling Duty Saving [MMkcal/hr] Total 4.76 9.50 12.67 15.64 Power Saving [kW] Total 507 868 1,104 1,394 Steam Saving [ton/hr 1 Total 3.7 6.4 8.1 10.2

CASE-

CASE-3

CASE-2

CASE-1

Incremental Area

Figure 2.2-14 Relationship between Reduction of Compressor Power Consumption and Required Additional Heat Transfer Area

- 2 - 39 - Figure 2.2-20 shows a schematic flow diagram for the propylene refrigerant system of the existing facility, while Figure 2.2-21 shows a schematic flow diagram for the CASE-2 modified system. Providing heat to the ethylene stripper (T-442) requires modification of the C3R vapor piping.

Figure 2.2-22 shows a schematic flow diagram for the CASE-3 modified system. Providing heat to the ethylene stripper (T-442) requires modification of the C3R vapor piping. The composite curves and grand composite curves in Case 3 are shown in Figures 2.2-23 and 2.2-24. The curves of the current operation are also plotted. As shown in Figure 2.2-24, the C3R curve’s protrusion is small, indicating a decrease in consumption.

The reduction of compressor power consumption is expected to range from approximately 870 to 1,100 kW. This is equivalent to a reduction of 6.4 to 8.1 ton/hr in steam consumption, thereby a reduction in the boiler load required for SU generation is expected.

Based on the modification plans and the reduction of compressor power consumption, CASE-3 appears to be the realistic and best heat recovery system.

- 2 - 40 - Existing

1420 Demethanizer

D345

C3R C3R-1 C300 4th E342AB E341AB

E420AB

Modification

T420 Demethanizer

C3R-1 C300 4th E342AB E341AB

E420CD E420AB (NEW)

Figure 2.2-15 Schematic Flow Diagram of Heat Recovery Plan 1 (INT-1) (top: existing system,

bottom: modified system)

-2-41 - Existing

C3R-2

E515 T510 Depropanizer

T450 Ethylene Stripper

C3R

E450

Modification

C3R-2

T510 Depropanizer T450 Ethylene Stripper

E450B E450 1NEW1

Figure 2.2-16 Schematic Flow Diagram of Heat Recovery Plan 2 (INT-2) (top: existing system,

bottom: modified system)

-2-42- Existing

1440 Ethylene Rectifier

C3R E402

I T I » C3R-2 C3R-3 C3R-4

E440

Modification

1440 Ethylene Rectifier

C3R-2 C3R-3 C3R-4

E440B E440

Figure 2.2-17 Schematic Flow Diagram of Heat Recovery Plan 3 (INT-3) (top: existing system,

bottom: modified system)

-2-43- E401 E402 E403 :------► Existing ! | I D411

1441 Ethylene Stripper C3R-2 C3R-3 C3R-4

T430/T432 C3R-2 C3R Deethanizer ,

Nr

£442 E440

Modification

1441 Ethylene Stripper C3R-2 C3R-3 C3R-4

T430/T432 C3R-2 Deethanizer T440 Ethylene Rectifier

E442B E440C E440 E440B (NEW) (NEW) (NEW)

Figure 2.2-18 Schematic Flow Diagram of Heat Recovery Plan 4 (INT-4) (top: existing system,

bottom: modified system)

-2-44- Existing Modification

C600-4th C600-4th

Ethane

E641A/E E451B E641A/E

~) D640 D640

D635

Ethane HP,MP Ethylene

Methane Methane

E451C

Ethane

Figure 2.2-19 Schematic Flow Diagram of Heat Recovery Plan 5 (INT-5) (left: existing

system, right: modified system)

-2-45- C600-1st C60Q-2nd C600-3rd C600-4th

E451B

< (' Ethane ----- 1 ►' E641A/E E420AB

D640

D610 D620 D630

Ethane HP,MP-Ethylene Users Users Users Users i—►

Methane

E404F(upper) E404S(upper) E453(upper) E454

E451 flower) E452(lower) E404Tf lower)

Figure 2.2-20 Propylene Refrigerant System Schematic Flow Diagram in Existing Facility

-2-46- C600-1st C600-2nd C600-3rd C600-4th

0610

E404F(upper) E404S(upper) E453(upper) E454

E451 (lower) E452(lowerl E404T(lower) Figure 2.2-21 CASE-2 Propylene Refrigerant System Schematic Flow Diagram

-2-47- C600-1st C600-2nd C600-3rd C600-4th

E440 Re-piping E451B E641A/E E420AB

D640

D610 D630 D635

E455

Users Users Users Users

— Methane

E451C —1*><-

- Ethane

E404F(upper) E404S(upper) E453(upper) E454

E451 (lower) E452(lower) E404T(lower)

Figure 2.2-22 CASE-3 Propylene Refrigerant System Schematic Flow Diagram

2-48 Figure Temperature[°c] Figure Utility

2.2-24 Ethylene (T440.T442) D630

D64Q D640 2.2-23 VAP Grand Pinch

Rectifier Grand

VAP LIQ Condensing C3R-4

DeC2 DeCI Existing Composite OVHD

Point

Composite Sub-cooling

Condensing.

OVHD, Feed

Composite

Condition C3R-1;

Curve C3R-3

Curves C3R-3 Cracked DeC3

Curves Enthaply[MMkcal/hr] Crac Enthalpy OVHD,

-2-49- of

Gas k

/ ed

CASE-3 of Rebailer Ethylene

Ga Ethylene

[MMkcal/hr] s CASE-3 Process

from Reboiler Ethylene Cracked Ethylene

Rectifier(T440)

C Propylene

3 Rectifier(T440, DeC1 00-4t DeC3

Ethylene Grand DeC2

C3R-4 Stripper(T450, Gas

Propylene

Rectifier(T440)

h

Reboiler

OVHD, from OVHD, DeC1

Composite

Stripper(T450.

C300-4th C3R-1

Refrigerant Reboiler T441) DeC1

DeC1

T442)

Refrigerant

Reboiler

Feed

OVHD Feed

Curve

T442)

Reboiler System

System 3) Hot end

(a) Existing analysis of heat recovery conditions

The heat recovery conditions in the hot end were studied.

As for the refrigerant systems, we constructed composite curves and grand composite curves, shown in Figure 2.2-25. In general, the optimal DTmin value is approximately 15°C at the hot end. The diagram shows a DTmin of 12.7°C, apparently indicating sufficient heat recovery efficiency.

Figure 2.2-26 shows the grand composite curves for the existing facility. The consumption curves of the high-pressure steam (SU, SH) and medium-pressure steam (SM) almost touch, indicating optimum

SU, SH and SM distribution. In contrast, the low-pressure steam (SL) consumption and BFW preheat curves extend to the left side of the temperature axis. Since SL is currently used as a heat source for several distillation tower reboilers, SL consumption can be reduced by changing the reboiler heat source to process fluids.

Quench Oil

DSG Reboiler Pinch Point

Propylene Column Reboiler

Enthalpy[MMkcal/hr]

Figure 2.2-25 Hot-end Composite Curves (Existing System)

-2-50- Utility Grand Composite Curve

Process Grand Composite Curve

Quench Oil Pinch Point

Pan nil Oiipnrh Water

DeC3. Distillate Stripper Reboilers Quench Water

Propylene Column Reboiler

E nthal py [M M keal/hr]

Figure 2.2-26 Hot-end Grand Composite Curves (Existing System)

(b) Examination of heat recovery improvement plans Figure 2.2-26 shows the possibility of heat exchange between the depropanizer (T-510)/distillate stripper (T-250) reboilers and quench water/pan oil. Based on these findings, we considered various heat recovery improvement measures. The targeted DTmin value was set to the current value of 12.7°C. The improvement plans are described below. a) Heat exchange between quench water circuit-1 and depropanizer reboiler Part of the quench water circuit ! used for naphtha preheating and reboiler heating is used to heat the depropanizer reboiler.

Figure 2.2-27 shows the current quench water circuit flow. The improvement plan is shown in Figure 2.2-28. The existing depropanizer reboiler (E-510AB) is removed and a reboiler (E-510CD) using quench water circuit-! as the heat source is installed. To ensure sufficient heating capacity, the quench water used for the naphtha preheater (E-101) and bypassed quench water is sent to the depropanizer reboiler. b) Improvement of naphtha preheating capacity with quench water circuit-1 In the current plant configuration, the naphtha supplied to the crackers is preheated (E-101) by

-2-51 - quench water circuit-1. The quench water returned to the quench water tower is cooled by the sea water cooler (E-225G). These heat sources can be used to preheat naphtha. The efficiency of the naphtha preheating operation can be improved by using part of the quench water presently being cooled by the sea water cooler to preheat naphtha before it is fed to the E-101.

Figure 2.2-28 illustrates this improvement plan. A new naphtha preheater (E-101B) is installed in parallel with the sea water cooler. To ensure sufficient naphtha preheating capacity, the connection of the demethanizer (T-419) reboiler is switched to quench water circuit-2. c) Heat exchange between pan oil circuit and distillate reboiler Improving naphtha preheating efficiency with quench water allows part of the preheating capacity of the pan oil to be used to heat other fluids. To make this possible, distillate stripper (T-250) Reboiler is installed on the pan oil circuit to function as a heat source.

Figure 2.2-29 illustrates this improvement plan. A branch line is provided in the pan oil circuit, and a new distillate stripper reboiler (E-250B) is installed. Since the pan oil cannot meet the total heating demand, the existing reboiler (E-250) is also used, while the SL provides the majority of the heating energy.

(c) Energy savings Figures 2.2-30 and 2.2-31 show the composite curves and grand composite curves of the modified system. Figure 2.2-31 shows that the utility curve and process curve are close to each other, indicating reduced SL consumption. The modification will reduce SL consumption by 10.25 tons/hr - equivalent to a heating value of 5.28 MMkcal/hr.

4) Examination of hot-end steam level The following examination of the hot-end steam level improvement does not account for inter process heat recovery. Figure 2.2-32 shows a sink-source profile for current operation condition in hot-end. To draw this graph, we measured fluids heated or cooled by various utilities (steam, sea water, etc.) in the hot end, and plotted the curves on the heating and cooling sides.

In Figure 2.2-32, the SL and process curves are widely separated. This suggests the possibility that some of the process liquids currently heated by SL can use low-level steam instead.

-2-52- The improvement plan calls for the installation of a new SLL main and a SL-»SLL turbine to produce electric power. SLL is also used as a heat source for the depropanizer (T-510) and condensate stripper (T-380) reboiler.

Figure 2.2-33 is a schematic diagram of the modified system. The power obtained by the newly installed turbine is estimated to be 138 kW. Using this power to drive pumps reduces plant electric power consumption. At this stage we have not examined which specific pieces of equipment would use this power.

-2-53- .(Wy A.v }* >v E226 E225

T220 -ct}*- E225G to E102 A E419 E353AB

T510 E105N

-A.. - E541

Naphtha — ~K X from E101B h SL E530 3

E107 E510AB

P220ABC

P225AB

Quench Water to T260

Circ.-1 Circ.-2

Figure 2.2-27 Schematic Flow Diagram of Quench Water Circuit (Existing System)

-2-54- E225G to E102

E353AB

E105N

r E101 Naphtha - from E101B E101B E530

E431AB E510CD E510AB ----- H \ t E419 Re-pipi

P220ABC E540AB P225AB Quench Water to T260

Circ.-1 Circ.-2

Figure 2.2-28 Schematic Flow Diagram of Quench Water Circuit (Modified System)

-2-55- Existing Modification T21Q T210

T260 Feed - T260 Feed

----- BFW

Naphtha Naphtha from E101 T250 from E101B T250

T270 Feed T270 Feed

E250B

Figure 2.2-29 Schematic Flow Diagram of Pan Oil Circuit (left: Existing System, right: modified system)

- 2 - 56 - Figure Temperature[°c] Pinch Figure Utility

Point 2.2-31

Grand

2.2-30

Hot-end

Composite

Hot-end Pinch

Grand Curve

Point

Composite luench

Composite Pan Enthalpy[MMkcal/hr] DSG Enthalpy[M

Water Dll Propylene

Reboiler Onanrh DeC3,

Curves Propylene

M

Column Water Curves Distillate

kcal/hr] Quench

Process of

Column Reboiler

Stripper the

Oil of DSG

Quench Modified

the Grand Reboiler

Existing Reboilers Reboiler

Modified

Oil

Composite

Condition

System

System

Curve Temperaturefc] Figure Heat

2.2-33

Existing Source install Potential

Process SL

Steam Figure Users

of

new Curve. BFW

System

2.2-32

turbine Others

Pre-heating SL-GEN Heat

Hot-end (left:

-2-58- Duty[MMkcal/hr]

Existing W=138kW

Sink-source

System, 0 Modification

Profile

right:

modified Heat Process Utility

Sink

system) Curve

Curve Others 5) Distillation column thermal analysis Since distillation towers are among the most energy-demanding facilities within the plant, optimizing their thermal efficiency will lead to significant energy savings. The following analysis focuses on potential thermal efficiency improvements in the high-load distillation towers.

(a) Ethylene stripper/rectifier (T-441/442) Column grand composite curves (CGCC) were used for thermal analysis of the distillation towers. Figure 2.2-34 shows CGCC of ethylene stripper/rectifier for current operating conditions. In Figure 2.2-34, the internal tower enthalpy change (Ideal CGCC) under ideal thermal conditions is plotted together with the curve (Real CGCC) of the actual heating and cooling operations. The portion where Ideal CGCC is close to the temperature axis indicates the distillation tower’s feed stage. Note that the vertical orientation is inverted from the actual distillation tower condition in order to indicate the temperatures on the vertical axis.

As indicated in Figure 2.2-34, Real CGCC on the stripping section is nearly parallel to the enthalpy axis, indicating that the thermal load is high in that temperature range. The addition of a side reboiler to the existing tower permits use of heat sources of different temperature ranges.

According to Figure 2.2-34, 47% of the heating duty in the existing reboiler can be shifted to the side reboiler. The side reboiler can be heated using C3R Vapor or the de-deethanizer OVHD vapor referenced in the examination of the propylene refrigerant system.

Figure 2.2-34 shows a schematic flow diagram in which C3R Vapor is used in the same way as in the existing ethylene rectifier (T-440). A new reboiler (E-442) is installed for the ethylene rectifier. This improvement plan is estimated to reduce propylene refrigerant compressor power consumption by 240 kW and SU consumption by 1.8 tons/hr.

(b) Deethanizer (T-430) Figure 2.2-35 shows the deethanizer ’s CGCC for the existing operating condition. The de-deethanizer has two reboilers, which one is the SL reboiler heated by SL and another one is the QW reboiler heated by QW. The side reboiler ’s Real CGCC and Ideal CGCC are widely separated, indicating that an increase in the heating capacity of the QW reboiler may reduce the SL reboiler load.

The CGCC indicates that a heating value of approximately 27% in SL reboiler can be shifted to

-2-59- QW reboiler. This improvement can reduce SL consumption by 1.9 tons/hr. To achieve this improvement, we need to increase the flow rate of quench water circuit-1 used as the heat source of the side boiler.

(c) Propylene stripper/rectifier (T-540/550) We can also apply the distillation tower thermal analysis to a consideration of the reduction of vapor and liquid flow rates in the distillation towers. Figure 2.2-36 shows the CGCC of the propylene stripper/rectifier. On the recovery side, the CGCC is almost parallel to the enthalpy axis, suggesting potential room for improvements in feed preheating operations or feed stage optimization. However, it is not possible to improve the feed preheating further considering both the feed temperature and the internal temperature of tower. Thus, feed stage optimization was studied.

Shifting the feed stage over eight theoretical stages to the top tower side can reduce the reboiler and condenser loads by approximately 0.7 MMkcal/hr. Figure 2.2-37 shows the vapor and liquid flow ratios under the modified conditions. In both the condensation and recovery sections, the internal vapor and liquid flow rates were reduced by 2%. However, since the propylene stripper (T-540) is currently at the top stage, this proposal was discarded.

6) Summary of investigation based on pinch technology A study of the refrigerant systems shows that the ethylene refrigerant system had been optimized and offers no room for further energy savings. However, for the propylene refrigerant system, it was discovered that there was a potential for energy savings through inter process heat recovery. The expected reduction is 6.4 to 8.1 ton/hr of SU.

An examination of the hot end showed that energy could not be conserved by reducing SU, SH and SM consumption. But the consumption of SL can be reduced by inter-process heat recovery. The anticipated reductions are 10.25 ton/hr in SL consumption. The examination also indicated that steam level optimization and installation of an additional turbine would reduce electric power consumption by 138 kW.

Analysis of the distillation tower revealed the possibility of optimizing operational conditions in the two distillation towers. One is an installation of new side-reboiler in the ethylene rectifier. The other is optimizing distribution of reboiler duties of the reboiler and side-reboiler in the deethanizer. The expected reduction is 1.8 ton/hr in SU steam consumption and 1.9 ton/hr in SL consumption respectively applying these modifications.

-2-60- T441 T442 Ethylene Stripper Ethylene Rectifier > to E-445

Reboiler

Potential of side-reboiler heating

Ethane <- >,ed-Stage

OVHD Condense - E-442 E-441 (New)

Enthalpy[MMkcal/hr]

Figure 2.2-34 Ethylene Stripper/Rectifier (T-441/442) CGCC (right) and Schematic Flow Diagram of Improvement Plan (left)

- 2 - 61 - >to E-435

T430 Deethanizer SL Rebpil

Reboiler

Potential of shifting duty from E-430 to E-431

E-431 Shifting part of duty from E-430 to E-431

E-430 QVHD Condenser to T-510 ♦ Enthalpy[MMkcal/hr]

Figure 2.2-35 Deethanizer (T-430) CGCC (right) and Schematic Flow Diagram of Improvement Plan (left)

-2-62- Change of feed stage upward

T550 Propylene Stripper Propylene Rectifier Reboiler

E-555

■> Propylene

T-530 Potential of optimizin' feed stage

E-540 -> Propane OVHD Co ndenser

Enthalpy[MMkcal/hr]

Figure 2.2-36 Propylene Stripper/Rectifier (T-540/550) CGCC (right) and Schematic Flow Diagram of Improvement Plan (left)

- 2 - 63 - 1.010

1.000

0.990 ! Existing Feed Stage

2. 0.980 Existing

0.970

0.960 Modification 0.950

0.940 Rectifying Section Stripping Section

0.930 BTM — Tray Number [ - Vapor Load Ratio

1.050

1.000

Existing Feed Stage! 0.950 Existing

0.900

a. 0.850 Modification

0.800

Rectifying Section Stripping Section

0.750 Tray Number [ - Liquid Load Ratio

Figure 2.2-37 Propylene Stripper/Rectifier (T-540/550) Internal Vapor and Liquid Flow Ratios(*l) (top: vapor, bottom: liquid)

(*1) Flow rate in each stage compared to maximum flow rate (given a value of 1 ) in current operations

- 2 - 64 - (2) Energy conservation through the introduction of an advanced recovery system (ARS)

The ARS is the latest system developed by S&W. When applied to the existing plant, this process permits efficient equipment modifications.

The project site — the naphtha cracker I in the Merbau Plant of the Petrochemical Corporation of Singapore — was constructed in the early 1980s based on a design licensed by S&W. By incorporating the ARS developed by the same company, we can reduce both energy consumption and carbon dioxide emissions.

1) Dephlegmator The ARS features dephlegmators installed in the low-temperature separation system of the ethylene plant to reduce the power required by the refrigerant compressors. A device combining a vertical-plate core heat exchanger and a drum, a dephlegmator is a heat exchanger with a distilling function. The distilling principle of this equipment is explained below and illustrated in Figure 2.2-38. Process vapors rising from the bottom section are partially condensed within the vertical-plate core heat exchanger by an external refrigerant. The condensed liquid contacts the process gas to provide a distilling effect. As shown in Figure 2.2-39, when the same process gas is cooled to the same temperature by a conventional plate-core heat exchanger, the vapor in the downstream drum of the conventional system contains propylene fractions, but with the dephlegmator, propylene fractions are completely eliminated from the vapor.

The absence of propylene fractions in vapor discharged from the dephlegmator can create a stream composed of only ethane and ethylene in the bottom section of the demethanizer. This stream can bypass the deethanizer.

Figure 2.2-40 shows a typical example of the way in which dephlegmators can be installed in low-temperature distillation systems of the existing plant. Thick lines in the diagram represent new equipment.

This example incorporates two dephlegmator units. The existing demethanizer is used as a hot demethanizer, and a new cold demethanizer is added. This configuration allows the distillate from the bottom of the demethanizer to bypass the deethanizer.

-2-65- PROCESS -82 C VAPOR -85 c REFRIG

-68 C REFRIG

ALUMINUM PLATE

LIQUID FILM

-48 C ^ LIQUID (PROCESS) PROCESS -45 C VAPOR

Figure 2.2-38 Distilling Principle of the Dephlegmator

CONVENTIONAL ARS

(Af- plate -fin H/E) (DEPHLEGMATOR)

OVHD

-85°C C2 = R TAILGAS

C2 = R

C2= R TAIL GAS

8TMS

Figure 2.2-39 Comparison of Dephlegmator and Conventional System

-2-66- Hydrogen

Dephlegmator Dephlegmator Methane No.l No.2 7 > Cold Cracked Gas Demethanizer > >

> Hot

Demethanizer — * Ethylene Recovery

Condensate Stripper Bottom >

Deethanizer

C3+ CUT ◄------______y Figure 2.2-40 Typical Dephlegmator Installation Scheme

2) Existing low-temperature distillation system Figure 2.2-41 is a schematic flow diagram for the low-temperature distillation system currently in use.

The plant is equipped with a single-tower demethanizer without a dephlegmator and relies on the conventional flow scheme.

3) ARS’s energy-saving results Table 2.2-8 shows the results of a study of the potential energy-saving results of dephlegmator installation. This modification would achieve a power consumption reduction of 509 kW for the ethylene refrigerant compressor and 797 kW for the propylene refrigerant compressor, providing an overall 1,306 kW reduction in compressor power consumption. Since the refrigerant compressors are driven by turbines operating on SU (Ultra High Pressure Steam), the amount of SU consumption is reduced. The estimated decrease in steam consumption is 5 tons/hr, resulting in lower boiler load and C02 emissions.

Table 2.2-8 Energy Conservation Effects of ARS After ARS Installation C2 Refrigerant Power, kW 509 C3 Refrigerant Power, kW 797 Total Refrigerant Power, kW 1,306

-2-67- 4) Low-temperature distillation system equipped with ARS Figure 2.2-42 shows a system configuration in which the present plate core heat exchangers are replaced by dephlegmators, the existing demethanizer is used as a hot demethanizer, and a new cold demethanizer is added. Thick lines represent newly added devices.

Although detailed modification specifications must be determined based on the design specifications of Stone & Webster Engineering Company, the licenser, the following modifications must be made.

1. Installation of two dephlegmators and cold boxes to house the dephlegmators 2. Installation of a cold demethanizer and conversion of the existing demethanizer to a hot demethanizer 3. Replacement of the existing ethylene refrigerant compressor with a new unit to increase the number of stages from the current three to four to handle an additional -83 °C refrigerant. The existing turbine can then be used for the new compressor. 4. Modification of the expander/compressor to change the current single-stage system into a two-stage system 5. Installation of new heat exchangers 6. Removal of unnecessary equipment 7. Modification and addition of pipes required by the installation and removal of equipment 8. Instrumentation work required by the newly installed equipment.

The dephlegmators must be placed in cold boxes - containers equipped with cold insulators to minimize cryogenic energy loss. This requires a relatively large installation area. Additional space is also required for the new cold demethanizer. An inspection of the plant site turned up an empty, available lot adjacent to the existing demethanizer, which would be suitable for both the installation of the new equipment and for process flow. Figure 2.2-43 shows the proposed location of the new cold boxes and the cold demethanizer.

-2-68- + WW ww ww ww ww ww ww ww ww ww ww ww — ww ww

Figure 2.2-41 Flow Scheme of Existing Low-temperature Distillation System

ww <~ ww vwv ww ww ww ww ww ww

T-420

Figure 2.2-42 Flow Scheme of Dephlegmator-equipped Low-temperature Distillation

- 2 - 69 - System

Figure 2.2-43 Proposed Installation Site of the New Equipment

(3) Cogeneration using gas turbine generators

Cogeneration systems (heat and electricity supply systems) that incorporate gas turbine generators are used widely throughout the oil refining and petrochemical industries, as well as by companies in numerous other manufacturing fields. To cut the high cost of electricity purchased from power companies, companies in these fields have installed private power generating equipment, optimizing electrical and thermal energy supply balances and reducing manufacturing costs. Gas turbine technology advances, providing improved equipment efficiency and reliability, have further promoted the popularity of cogeneration systems.

1) Gas turbines In a reciprocating internal combustion engine such as an automobile gasoline engine or a diesel engine, each cylinder performs a series of processes: (1) intake; (2) compression; (3) ignition (combustion) and expansion; and (4) exhaust. Figure 2.2-44 illustrates these four processes. In a gas turbine, these processes are performed independently by the compressor, the combustor, and the turbine. Nevertheless, the basic operating principle is nearly identical. Figure 2.2-45 illustrates a typical gas turbine.

- 2 - 70 - A gas turbine is composed of a multi-stage axial compressor, a combustor, and a turbine. Rotating and stationary parts are joined with bolts by flanges to produce a single unit. Air, which the working fluid of the gas turbine, passes through the filter before being fed to the axial compressor. Compressed air is processed by the combustor and becomes a high-temperature combustion gas, entering the turbine, where it then expands. The thermal energy of the gas is converted to kinetic energy in the rotating turbine. Some of the power generated by the turbine is used to drive the air compressor, which is connected to the turbine by a shaft. The remaining power is output in the form of electricity. Figure 2.2-46 provides a schematic diagram of this process.

1 AIR intake 2 Compression

Figure 2.2-44 Reciprocating Internal Combustion Engine

Air

CompressionfCompressor] Ignition (Combustion) [Combustor]

Figure 2.2-45 Gas Thrbine

-2-71 - Gas Turbine main Unit

Air ToHRSG or Process

Figure 2.2-46 Schematic Diagram of Gas Tbrbine

2) GTI (Gas Turbine Integration) A gas turbine is combined with other types of equipment to enable high thermal efficiency in ethylene plant operations. The most effective combinations involve a turbine and a waste heat boiler for cogeneration of electric power and steam, and a gas turbine used with the existing cracker. The combination of a gas turbine and a waste heat boiler was selected for this project. However, the combination of a gas turbine used with the existing cracker is described below.

The exhaust gas of a gas turbine is composed of approximately 15% oxygen. A temperature of 550°C as well as the oxygen concentration make the exhaust gas appropriate for use as combustion air for crackers. Use of gas turbine exhaust gas can reduce the fuel consumption of crackers 8 to 12%, depending on the gas turbine and cracker capacities.

Figure 2.2-47 shows an example of the gas turbine/cracker combination.

-2-12- Furnace (TYP}

I.D. Fan (TYP)

Pipe Rack

Bypass Stack

Generator Auxiliary, " Generator Compartmmt Reduction Gear Turbin Compartment Waste Heat Boiler Starter Compartment Control Compartment

Figure 2.2-47 Combination of Gas Turbine and Cracker

The gas turbine, which is generally installed away from the cracker, compresses ambient air to the required pressure levels. Fuel gas is compressed and fed to the combustor. The combustion gas expands in the turbine, and the generated energy is used to drive the generator.

Exhaust gas is introduced to the cracker’s floor burners. Each cracker inlet is provided with a damper to ensure uniform distribution of exhaust gas.

Although a gas turbine can improve thermal efficiency when combined with a cracker, there are several problems to consider.

1. The gas turbine generator may prevent stable operation of the cracker, the core of the ethylene plant. 2. An FDF must be installed for use during gas turbine tripping. 3. A bypass stack must be installed for use during cracker tripping.

In this facility, combining a gas turbine with the existing cracker may lead to the following problems:

- 2 - 73 - 4. Because the existing cracker has many wall burners, piping of the gas turbine exhaust gas ducts may become complex. 5. Since the gas turbine must be installed away from the cracker, a large-diameter duct must be installed. 6. Back pressure in the duct may reduce gas turbine efficiency. _ 7. Since exhaust gas volume increases, the convection section needs to be reinforced.

The combination of a gas turbine with an existing cracker may generate operational difficulties and require extensive plant modifications. Due to these problems and the general low cost-effectiveness of the gas turbine/existing cracker option, the gas turbine/waste heat boiler combination was selected for the project.

3) Current conditions of steam and electric power consumption Gas turbine cogeneration systems may be roughly grouped into the following three groups:

(a) Waste heat recovery type Figure 2.2-48 shows schematic flow of this system. This system consists of a gas turbine and a waste heat recovery steam generator that produces process steam using exhaust heat from the gas turbine. Steam generation of this system stops during gas turbine trip. Figure 2.2-49 shows heat balance of this system.

(b) Waste heat recovery type with duct burners Figure 2.2-50 shows schematic flow of this system. This system’s waste heat recovery steam generator is equipped with duct burners to increase the temperature of the gas turbine exhaust gas and boost steam generating capacity. This system is effective when steam demand is high, relative to demand for electricity, or when it is necessary to prevent fluctuation of steam generation rate resulting from gas turbine load fluctuations. The exhaust gas of a gas turbine is composed of 13-15 % oxygen. Because of this, additional introduction of combustion air is not required. In the case that it is necessary to maintain steam generation during gas turbine trip, Forced Draft Fan, Damper System to isolate a waste heat boiler from a gas turbine and Bypass Stack should be installed. Figure 2.2-51 shows heat balance of this system. Since duct burners increase the temperature of the exhaust gas at the inlet of the steam generator, the waste gas outlet temperature can be lower than in systems lacking duct burners, even at the same pinch point. The increase in recovered heat resulting from duct burning exceeds the increase in the heat input. The result is higher overall thermal efficiency, compared to systems lacking duct burners.

- 2 - 74 - (c) Hybrid combined-cycle cogeneration type Figure 2.2-52 shows schematic flow of this system. This system is used in circumstances where steam demand is low compared to demand for electricity, and in which efficient heat recovery results in surplus process steam. This is a hybrid system integrating combined cycle and cogeneration systems, where surplus steam is introduced to the steam turbine to generate electricity. Process steam is generated in a waste heat boiler and/or extracted from a steam turbine in accordance with its pressure level.

To select the most suitable system among the three alternatives, we examined current demand for steam and electricity.

The current steam summary is shown in Figure 2.2-53, while power demand is shown in Table 2.2-9.

Table 2.2-9 Demand for Electricity at the Merbau Plant, Petrochemical ComplexI PLANT Electricity Demand (kW) No.l Naphtha Cracker Approx. 7,500 Downstream PLANT 1 Approx. 30,000 Downstream PLANT 2 Approx. 9,500-12,500 Total Approx. 45,000-47,000

- 2 - 75 - STEAM

EXHAUST GAS

■OILER FEED WATER

Figure 2.2-48 Turbine Exhaust Heat Recovery System ELECT. OUTPUT

STEAM

EXHAUST GAS

BLOW DOWN

MECHNtCAL LOSS

Figure 2.2-49 Heat Balance of Exhaust Heat Recovery System STEAM SUPPLEMENTARY FUEL FUEL

EXHAUST GAS

=© DOILER FEED WATER

Figure 2.2-50 Turbine Exhaust Heat Recovery System with Supplementary Firing

- 2 - 78 - OUTPUT

100H STEAM OUTPUT

SUPPUMENTAMY EXHAUST OAS

MECHWCAL LOSS

Figure 2.2-51 Heat Balance of Supplementary Firing System

- 2 - 79 - Figure 2.2-52 Combination of Combined Cycle and Co-generation System

- 2 - 80 - Other Plants Boiler Plant Ethvlene Plant Users

SU Header

CT-300 CT-600 CT-650

Boiler B Boiler C

Condensate ^ Condensate SH Header

Users

Pump Turbines

SM Header

Users

SL Header

Users

Figure 2.2-53 Current Steam Summary

-2-81 - Following discussions with the Singaporean side and an analysis of power demand, the selection of gas turbine capacity was narrowed to the following two values:

1. 17,000 - 20,000 kW (excludes power supply to Downstream PLANT 1) 2. 45,000 - 20,000 kW (power supply to entire Petrochemical Complex I)

For steam generated by the waste heat recovery steam generator, SU (108 Kg/cm2G, 500°C) was regarded as suitable, given the existing boilers. A steam generation capacity of 70 tons/hr was selected. This value is sufficient to allow one boiler to be shut down, even during periods of peak demand.

The heat balance analysis of the gas turbine and waste heat recovery steam generator indicates a higher heat consumption in the waste heat recovery steam generator. In addition, it is necessary to ensure constant levels of steam generation even when the gas turbine load fluctuations. Thus, the waste heat type with duct burners was selected as the most suitable gas turbine generator cogeneration method.

Of boilers B and C, boiler B was selected as to be shut down following installation of the gas turbine, due to its age. The operating conditions of boiler B are shown in Table 2.2-10, and Figure 2.2-54 shows a photograph.

The cogeneration gas turbine will use fuel gas, the same fuel used by the boiler (B) to be shut down. The duct burners will use fuel oil.

- 2 - 82 - Table 2.2-10 Boiler B Operating Conditions

Fuel Gas Flow Rate, Nm3/h 2888 Fuel Gas LHV, kcal/Nm3 8217

Fuel Oil Flow Rate, m3/h 2.75 Fuel Oil LHV, kcal/kg 10092 Fuel Oil Density 1.0112

Fired Duty, MMkcal/h 51.793

BFW Inlet Temperature, °C 188 SU Temperature, °C 490 SU Pressure, Kg/cm2G 110.4 SU Flow Rate, ton/h 78.6

Absorbed Duty, MMkcal/h 47.658

Efficiency, % 92.0

Excess Air, % 19.3

Flue Gas, Nm3/h C02 6,615 H20 10,957 n 2 49,598 02 2,147 Wet Total 69,317

Stack Temperature, °C 185 After SAH Temperature, °C 59

Humidity, % 85

Stack Loss, MMkcal/h 2.923 Wall Loss, MMkcal/h 1.212

- 2 - 83 - Figure 2.2-54 Boiler B

-2-84- 4) Results of an examination of cogeneration using a gas turbine generator Each gas turbine model has a designated capacity set by the manufacturer. This study was based on the selection of two gas turbine models: a product from company A generating 20,000 kW, and a product from company B generating 45,000-47,000 kW.

Table 2.2-11 provides the results of an examination of cogeneration applications. The amount of steam generated for 45,000 to 47,000 kW power generation exceeds 70 tons/hr. Without duct burning, overall efficiency is expected to be a mere 70%. This is listed as Case 1-45-MW power generation in Table 2.2-11. Given the acid dew point, it was decided to provide duct burning to keep waste gas temperatures above 170°C for the subsequent heat recovery process. Listed as Case 2, this increases overall efficiency to 81%.

The above-referenced cases and their schematic flow diagrams are provided in Figures 2.2-55 and 2.2-56.

5) Construction required to install a gas turbine generator for cogeneration The following construction is required to install a gas turbine generator for cogeneration.

1. Installation of the gas turbine and waste heat recovery steam generator 2. Piping and instrumentation 3. Cable-laying to the MCC 4. Modification of the existing MCC or construction of a new MCC

- 2 - 85 - Table 2.2-11 Results of an Examination of Cogeneration

20 MW Power Generation 45 MW Power Generation Case Case 1 | Case 2

Calculation Result Net Power Output kW 20,273 44,533 44,234 Heat to Steam kW 53,780 55,202 92,272 Fuel LHV energy input kW 88,756 142,894 169,148 Thermal Efficiency °/o 83 70 81

Gas Turbine Summary Gross Power Output kW 21,650 47,124 47,124 Estimated transfer losses and plant auxiliaries kW 1,377 2,591 2,890 Net Power Output kW 20,273 44,533 44,234 Fuel Gas LHV energy input kW 66,480 142,894 142,894 Fuel Gas to Gas Turbine t/h 4.711 10.130 10.130

HRSG Summary Heat to Steam kW 53,780 55,202 92,272 SU Generation Rate t/h 69.90 71.74 119.90 HRSG Inlet Temperature °C 559 531 531 Stack Temperature °C 170 236 173 HFO LHV to duct burners kW 22,276 0 26,254 HFO to duct burners t/h 1.96 0 2.31 Note 20 MW power generation Without duct burning With duct burning

-2-86- SU to Header 4.71ton/h 69.9ton/h BFW from

Existing Deaerator

Flue Gas

Fuel Oil 1.96 ton/h

Figure 2.2-55 Cogeneration with Gas Ttirbine Generator (20 MW Power Generation)

- 2 - 87 - 44,234kW A

Fuel Gas SU to Header lO.lton/h 119.9ton/h BFW from

Existing Deaerator

◄------

Flue Gas

Fuel Oil 2.31 ton/h

Figure 2.2-56 Cogeneration with Gas Tbrbine Generator (45 MW Power Generation) 2.2.5 Split of scope of work and supply between both parties for funds, facilities, and services for project implementation

The funds, facilities/equipment, services, and technologies to be provided by the Japanese and Singaporean sides for the project are as follows. Funds required for implementation of the project are calculated in accordance with this basis.

International technical standards shall be applied, as specified in PCS standards.

(1) Japanese side The Japanese side shall provide the following equipment, materials, services, and technologies for this project, including on-site construction work.

1) Implementation of more detailed feasibility studies based on the findings of this study 2) Compilation of the basic plan for the project 3) Handling all required government procedures/applications as the constructor and assisting the Singaporean counterpart in those matters 4) Providing basic designs for new facilities and equipment (including licensor designs) and detailed designs 5) Procurement of all equipment and materials required for this project 6) Procurement of spare parts for new equipment and materials for four years’ operation 7) Inspection of the new equipment and materials at fabricators ’ shop prior to shipment 8) Marine transportation of the new equipment and materials 9) Customs clearance and unloading at the port of unloading in Singapore 10) Inland transportation of the new equipment and materials to the construction site 11) Development of an on-site construction plan 12) Installation of the equipment 13) Piping modification and connection work 14) Civil engineering work (including equipment foundation, drainage, and paving work) 15) Building and steel structural work 16) Instrumentation work 17) Electric work 18) Thermal insulation work and fireproofing 19) Painting work 20) Disposal of construction waste 21) Preparation of procedures for measuring carbon dioxide emissions 22) Assistance in and witnessing of commissioning and performance tests

- 2 - 89 - (2) Singaporean side

The Singaporean side shall provide the following funds, services, and technologies required for this project, excluding on-site construction work.

1. Investigation for soil bearing capacity and site grading in and near the installation site for the new facilities 2. Performing officially required procedures and making applications for the project 3. Provision of design-related documents for the existing facilities and equipment 4. Witnessing of inspection of major equipment provided by the Japanese side 5. Education and training of any new operational/maintenance personnel 6. Implementation of commissioning and performance test runs 7. Continuous measurements of carbon dioxide before the project implementation and for a specified period of time afterwards in accordance with the documented measurement procedures for carbon dioxide emissions to be prepared by the Japanese side 8. Provision of temporary supply facilities for water, electricity, steam, and compressed air required for construction work 9. Exemption measures for customs duties and GST required for imported goods to be contractually agreed upon in the future

2.2.6 Preconditions and problems in project implementation

No problems have been observed in PCS’s technical prowess, control system, management foundation, financial support capability, and human resources support capability

2.2.7 Project implementation schedule

The following section explains the work schedule leading up to the commercial agreement to be signed between the governments of Japan and Singapore and the relevant companies once the implementation for the project has been officially agreed upon subsequent to this study, as well as the implementation process after the agreements are put into effect.

Please refer to Figure 2.2-57 the project schedule.

This project implementation process shall be divided into the following two stages.

- 2 - 90 - (1) First stage - Prior to signing official agreements

The first stage is comprised of the work plan leading up to the signing of commercial agreements. In this stage, more detailed feasibility studies will be conducted in collaboration with the partner company to investigate the detailed reduction estimates of carbon dioxide emissions and the likely profitability of the project.

Specifically, the following items shall be included. 1. Preparations for implementation of field surveys for more detailed feasibility studies. 2. Field surveys for more detailed feasibility studies (including detailed discussion concerning designs with the partner company) 3. Improvement and establishment of design bases in accordance with the findings acquired from the field surveys 4. Basic design 5. Detailed design and estimation of the budget required for facility construction 6. Final confirmation on service scopes, and negotiations on the contractual price with the partner company 7. Signing of design, procurement, and construction contracts with the partner company

Judging from our past experience, this stage is expected to take between 6-10 months.

(2) Second stage - EPC operations

The second stage covers the implementation of agreements on Engineering, Procurements, and Construction (hereafter referred to as “EPC”), completion of EPC, operations and test runs, which are expected to take about 29 months to complete. Furthermore, it shall be noted that the tie-in work between the new facilities inclusive of new piping and instrumentation, etc. and the existing facilities shall be conducted during the next shutdown maintenance (SDM) of the plant. Since the SDM schedule (timing and length) needs to be determined in meetings with the partner company and related companies, it is impossible to finalize the schedule until about a year prior to the actual shutdown (currently scheduled to be 2005).

1. Putting the agreements into effect 2. Acquiring official approval for the designs (primarily of the buildings) from the government of Singapore 3. Basic designs 4. Detailed designs

-2-91 - 5. Procurement of equipment and materials 6. Shipping and transportation 7. On-site construction works 8. Test runs and delivery of the equipment

-2-92- SHEET C( )NT'D SHEET CLIENT PETROCHEMICAL CORPORATION OF SINGAPORE PRIVATE LIMITED PROJECT NAME C()2 EMISSION REDUCTION .AND ENERGY EFFICIENCY IMPROVEMENT LOCATION SINGAPORE

LINE LINE DESCRIPTION PROJECT FIRST YEAR PROJECT SECOND YEAR PROJECT THIRD YEAR PROJECT FORTH YEAR No. No. 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 iu 11 12 1 2 3 4 5 6 7 8 9 10 11 12 12 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7

1 J 2 PHASE 1 (PRIOR TO CONTRACT AWARD) 2 3 J — 1 4 1. PREPARATION FOR SITE SURVEY — 4 5 2. SITE SURVEY - 6 3. PREP.ARATION OF SUMMARY OF SITE SURVEY RSULTS — 6 7 .AND ESTABLISHMENT OF DESIGN BASIS 8 4. BASIC DESIGN 8 9 5. DETAILED DESIGN .AND PROPOSAL PREPARATION 9 10 6. CLARIFICATION ON THE PROPOSAL & COST NEGOTIATION JO 11 7. SIGNING OF EPC AGREEMENT — —spT ii r 12 J2 13 ii 14 PHASE 2 (AFTER CONTRACT AWARD) U J4 15 ii r 16 1. CONCLUTION OF EPC AGREEMENT T, ii 17 2. GOVERNMENT APPROVAL ( MAINLY FOR BUILDING DESIGN) J7 18 3. BASIC DESIGN - - --- — ii 19 4. DETAILED DESIGN J9 20 5. PROCUREMENT — - — - — " — - - ■ — — - — - ■ — - - — — - 20 r 21 6. SHIPPING AND TRANSPORTATION — - — — — " ■ - 11 22 7. FILED CONSTRUCTION WORK 22 23 8. TEST OPERATION _ li 24 24 25 li 26 li 27 _ 27 28 li 29 29 30 j ii 31 _ 31 32 32 33 ii 34 34 35 ii 36 L __ 36 37 1 _ 37 38 ii 39 ii 40 1 1 40 1 n 41 L 41 NOTES: REV. DATE DESCRIPTION PREP'D CHK'D APP'D @JGCD0RPDRflTICW |«iiCKI~]__ ---- PLANNING ▼ BASIC DESIGN El VENDOR'S DWG 31-MARCH-01 FOR REPORT TO NEDO R.S - R.S — DESIGN V SKELETON 0 BILL MAT'L PROJECT SCHEDULE ■ CONST. # LOADING DATA 0 purchase order Figure 2.2-52 Project Schedule - - MANUF'I ® DESIGN DWG A MAT'L JOB CODE 0-1429 □ CLIENT'S WORK © SPFCTETCATTO A F.OIJTP. DELIVERY DWG No. REV.

FORM 2360-3 Figure 2.2-57 Project Schedule 2.3 Implementation of Financing Schedule

2.3.1 Financial Schedule for project implementation (Required Funds and financing methods)

As stated in the paragraph 4.1.2 “Financial requirements ”, expected amount of the funds required for the project will be around 9 billion Japanese Yen, except for any taxes and duties levied in Singapore. The ways to obtain the funds, as mentioned in the next paragraphs, can be expected as follows. 1. Through environmental loans from Japan Bank for Clean Gas Mechanism 2. Through investment loans from Japan Bank for International Cooperation or from Buyer’s Credit.

2.3.2 Financing prospectus (plans of parties commissioned to study financing plans and implementation site (companies))

Obtaining yen-denominated government credits (including yen credits for environmental protection purposes) is currently regarded as difficult for the following reasons: (1) the project is located in Singapore; (2) PCS is a private-sector company; and (3) the project involves a petrochemical complex. Since part of PCS’s capital was paid by a Japanese company, funds for the project may be obtained through investment loans from Japan Bank for International Cooperation or from Buyer’s Credit. JGC Corporation has successfully assisted in many past financing operations, and will gather the required information and provide support for fund procurement.

2.4 Conditions and Issues Related to the Clean Development Mechanism

2.4.1 Coordination with the Recipient Country for Setting Conditions for Project Execution and Assignment of Responsibility for Implementing Clean Development Mechanisms Based on the Project Site Conditions

In connection with the Clean Development Mechanism, which involves the setting of project implementation conditions and work division based on project site conditions, we attended a hearing with the Singapore ’s Ministry of the Environment to learn its basic policies. Based on the information thus obtained, we considered various energy conservation measures and adjustments with the project implementing company concerning execution of the project. The following is an overview of the hearing.

-2-95- Date of visit: December 9, 2000

Organization: Strategic Planning & Research Department, the Ministry of the Environment of Singapore

Visiting staff: Koji Sakurai (Manager, Singapore Office, JGC Corporation) Ryosaku Saito (Project Manager, JGC Corporation) Hisato Aoyama (Planning Engineer, JGC Corporation) S.K. Joshi (Principal Planner and Engineer, PCS)

(1) Singapore’s policies regarding carbon dioxide emission reduction

In comparison to advanced industrialized nations, Singapore ’s economy is still in the process of development, and continued economic development is expected to increase energy consumption. Singapore understands that the numerical targets established in COP3 for reducing carbon dioxide emissions apply to advanced industrialized nations, and differ from those applicable to Singapore. Singapore has yet to establish numerical targets, and the government feels that the nation has not reached the stage at which it is appropriate to do so.

With limited energy resources within its own borders, Singapore has no choice but to rely on energy policies that are based on imports of fossil fuels. The country believes it essential to secure a supply of primary energy sources to promote the development of core domestic industries (including oil refining and the petrochemical industry) and to meet the needs of the private sector and demand from transportation systems.

Nevertheless, Singapore ’s strategic policies target steps to halt or reverse global warming. Singapore is examining various measures to minimize global warming, and the government is promoting such measures.

One such measure is a shift in primary energy sources from petroleum to natural gas. In contrast to an earlier reliance on heavy oil to power thermal power plants, a conversion to natural gas is now being promoted. The amount of carbon dioxide discharged per unit of heat is lower for natural gas than for heavy oil. Generating systems are also moving from conventional boiler/turbine generators to systems that use gas turbines (combined cycle) for improved power generating efficiency and reduced carbon dioxide emissions per unit of generated power.

-2-96- Natural gas is supplied through pipelines by neighboring Malaysia under long-term contracts.

(2) Regarding the implementation of international joint projects for environmental measures

Singapore has never undertaken joint international research efforts or participated in international projects involving environmental measures. The environmental preservation measures taken by the government of Singapore have been based primarily on measures examined and implemented by Japan, modified to suit conditions specific to Singapore.

Since the merits of energy conservation technologies transferred from Japan have already been demonstrated, the government of Singapore is enthusiastic about their introduction. Singapore is likely to place great weight on potential energy savings and reductions in C02 emissions identified in this study.

If the introduction of Japanese technologies results in energy conservation for Singapore ’s domestic companies and benefits Singapore at the same time, the government of Singapore will cooperate in the project implementation.

The policies of the government of Singapore emphasize a balance between industrial development and environmental preservation, policies to which the government rigorously adheres, providing assistance only when a proposed project has been demonstrated to reduce carbon dioxide emissions and to provide the company with economic benefits, such as lower operating costs due to reduced fuel consumption.

(3) Negotiations between the two governments concerning carbon dioxide reductions The UNFCCC Kyoto Conference established reduction targets for greenhouse gases such as carbon dioxide, to be observed by advanced industrialized nations. To facilitate attainment of the target figures by individual nations, a framework for emissions trading between countries is likely to be proposed and adopted sometime in the future.

Under such proposed terms, its status as a developing nation will permit Singapore to trade unused emissions rights with advanced industrialized nations such as Japan. Singapore is aware that such trading with Japan is considered an implementation of the Clean Development Mechanism (CDM).

If an examination of energy conservation measures for Singapore ’s domestic industry indicates

-2-97- that carbon dioxide emissions will be reduced and it will result in economic benefits for the company, negotiations for carbon dioxide emissions trading between Japan and Singapore may become possible under the framework of the Clean Development Mechanism.

Although the details of the Clean Development Mechanism remain to be finalized, if joint implementation of the project by Japan and Singapore appears likely to provide benefits for both nations, the Clean Development Mechanism may be implemented.

2.4.2 Coordination with the Recipient Country for Setting Conditions for Project Execution and Assignment of Responsibility for Implementation of Clean Development Mechanisms Based on the Project Site Conditions

(1) Singapore ’s stance on global warming

As Singapore ’s economy and energy needs continue to grow, Singapore must address the issue of greenhouse gases such as carbon dioxide, since growing energy consumption will lead to increased carbon dioxide emissions.

The government of Singapore has been active in working to reduce carbon dioxide emissions. While remaining aware of the threat of global warming, the country is also focusing on nurturing its economy. Singapore is seeking both to meet the energy demands required for economic development and to implement measures to halt or reverse global wanning.

In the past, Singapore has taken various measures, including introducing energy conservation technologies, to achieve both economic development and environmental preservation.

Given its high regard for environmental measures implemented in Japan and Japanese technological trends, Singapore wishes to apply Japanese technologies, with appropriate modifications to suit the specific conditions that apply to Singapore.

To that end, we must present quantitative data on energy-saving effects and cost performance associated with the new technologies thereby adjusting the targets to be set.

(2) Policies and stance concerning the Clean Development Mechanism

The Clean Development Mechanism was adopted in the Kyoto Protocol, together with a concept of joint implementation that promotes the collaboration of advanced industrialized nations, with

-2-98- the goal of permitting flexible implementation of environmental measures.

The Clean Development Mechanism encompasses systems involving carbon dioxide absorption, emissions trading, and the Clean Development Mechanism to promote reductions in greenhouse gas emissions globally, by enabling participating nations to invest in projects proposed in other nations to reduce greenhouse gases. The rules governing emissions trading were slated for discussion at COP6, held at The Hague.

However, COP6 was devoted to the adjustment of the range of absorption sources such as forests and adjourned without a discussion of a system or concrete procedures for the Clean Development Mechanism.

The only method available to Singapore to reduce greenhouse gas emissions is to attain the highest possible efficiency in energy use. Consequently, Singapore has decided to introduce energy conservation technologies within the constraints imposed by its limited land area. Implementation of the Clean Development Mechanism with advanced industrialized nations is also an option.

(3) Possibility of Singapore ’s agreement to the Implementation of the Clean Development Mechanism

Singapore has expressed strong interest in the project under consideration, since the project ’s potential benefits match the country ’s goals - to reduce greenhouse gas emissions while strengthening the economy.

Preconditions for project implementation include economic achievements commensurate with the investment and a sound technical basis for the reduction of greenhouse gases.

PCS, the partner company in the project, is expecting to cut energy costs, as a responsible member of the energy-consuming petrochemical industry.

-2-99- Chapter 3 Project Effects

This chapter describes project benefits with respect to energy savings, reduced emission of greenhouse gases, and improved productivity.

3.1 Energy savings

3.1.1 Technological basis for energy savings

(1) Heat recovery using Pinch technology

While the ethylene refrigerant system is already optimized for heat recovery (meaning that no further energy savings are possible here), potential energy savings have been identified in the propylene refrigerant system. Energy savings at this stage can be achieved through heat recovery between processes.

As noted in Chapter 2, reducing the load on the propylene refrigerant system will reduce the power necessary for driving the compressor-that is to say, it will reduce steam consumption at the turbine. Since less steam is required from the boiler, this in turn conserves boiler fuel.

While there was no potential for energy savings via reduced consumption of the range between high-pressure to medium-pressure steam at the hot end, it should be possible to reduce low-pressure steam consumption through heat recovery between processes.

The energy-saving identification method using the pinch analysis employed in this study is not restricted to PCS I at the Merbau Plant. It is also applicable to other process units and ethylene plants.

(2) Energy savings using the Advanced Recovery System (ARS)

The main feature of the ARS is the dephlegmator. Unlike conventional heat exchangers, the dephlegmator is capable of moving both heat and physical matter simultaneously. It has around 10 theoretical stages for fractionating; the resulting improvements in liquid and gas composition effectively reduce the volume of refrigerant required in the low-temperature distillation system. Reducing the load on the refrigerant system will reduce power necessary for driving the compressor -that is to say, it will reduce steam consumption at the turbine. Reduced requirements for steam from the boiler lead to boiler fuel savings.

-3-1- The Advanced Recovery System can achieve energy savings at the primary stage naphtha cracker at the Merbau Plant or any other ethylene plant with a conventional low-temperature distillation system.

(3) Co-generation using gas turbine power generator

The introduction of a 20 MW gas turbine would convert 22.8% of combustion heat input into the gas turbine into electrical energy, enabling the recovery of 60.6% as steam in the waste heat recovery steam generator and producing an overall 83.4% improvement in thermal efficiency.

In current operation, the same volume of steam can be generated with 92% efficiency, while electricity can be purchased from a conventional power plant at an average efficiency of 35%, for an overall efficiency for electricity and steam generation of 63.6%. Co-generation would produce energy savings by boosting thermal efficiency from 63.6% to 83.4%.

Co-generation systems featuring gas turbine power generators are suitable not only for manufacturing applications such as petrochemical production (e.g., ethylene) and petroleum refining, but also for commercial and public facilities such as office buildings, hospitals, universities, and hotels.

The fuel savings achieved by this project would persist through the life of the equipment.

3.1.2 Baseline used to estimate energy savings and assumptions made in calculations of normal energy consumption (i.e., without modifications)

(1) Calculation of energy consumption (or input) at target site prior to modification

1) Baseline figure The baseline figure was based on the following statistical information on the energy consumption (or input) of ethylene processing equipment. Current actual operating data, such as steam consumption and generating rate, fuel consumption rate, and electric power consumption rate, were used for for this calculation.

(a) Processing capacity and operating rates • Processing capacity 55.83 tons of ethylene per hour • Operating time 8,400 hours per year

-3-2- (Annual processing capacity = 470,000 tons)

(b) Total energy consumption based on current operation, (calculated in fuel oil equivalent) Total Fuel Consumption rate (Baseline): 360 Gcal/h of fuel oil consumption Annual Energy Consumption rate: 302 ktoe/year (= 360 Gcal/h X 8,400 h/year X 0.1 toe/Gcal)

3.1.3 Estimate of actual energy savings, expected timeframe, and accumulation

(1) Estimate of actual energy saving

Table 3.1-1 shows the energy savings expected from each of the proposed modifications.

Table 3.11 Actual energy savings from each modification

Pinch N0TE 1) ARS N0TE 1) GTG 20MW N0TE 1) GTG 45MW N0TE 1)

SU (ton/hr) 8.1 5.0 -0.1 49.9

FueKGcal/hr) 0.0 0.0 n °te 2) _30 2 note 2) _99 4

Electric Power (MW) 0.0 0.0 20.3 44.2

NOTE 1) The title names stand for following project names. Pinch: Energy recovery Optimization Project using Pinch Technology ARS: Energy Saving Project applying Advanced Recovery System GTG 20MW: Installing new 20 MW Co-generation plant GTG 45MW: Installing new 45 MW Co-generation plant

NOTE 2) Calculation of Fuel consumption is based on following data. GTG 20MW Co-Generation fuel consumption: 76.3 Gcal/h GTG 45MW Co-Generation fuel consumption: 145.5 Gcal/h After Co-Generation project implemented, fuel consumption for existing boiler B would be eliminated. Fuel consumption for existing boiler B is assumed to be 46.1 Gcal/h. As the result, additional fuel for switching from boiler B to Co-Generation would be as below. Additional Fuel Consumption for introduction GTG 20MW Co-Generation: 30.2 Gcal/h (= 76.3 - 46.1) Additional Fuel Consumption for introduction GTG 45MW Co-Generation: 99.4 Gcal/h (= 145.5 - 46.1)

-3-3- (2) Reduced fuel consumption through energy savings

The table 3.1-1 indicates that the most significant energy savings would be achieved by a co-generation system with a 45 MW gas turbine and 49 Gcal/h of energy saving. For the purposes of calculation, electric power (kWh) was assumed to be converted into fuel (kcal) at a power generation efficiency of 2,450 kcal/kWh. This figure assumes a power generation efficiency of around 35% at the sending end of an ordinary boiler/turbine power plant. And, conversion coefficient to SU is 0.799 - 0.05 = 0.794 Gcal/t, assuming part of energy in SU to be recovered as Cold Condensate heat value of 0.05 Gcal/t.

The energy savings shown above represent the savings in each project that would be achieved by each modification, independent of other modifications. However, since the pinch-technology heat recovery system and the energy-saving ARS would offset each other to some degree, the combined energy savings may not be as high as the sum of the two figures.

The energy savings figures have been converted into fuel savings, as shown in Table 3.1-2:

Table 3.1-2 Expected energy savings from each modification

Pinch ARS GTG 20MW GTG 45MW

SU N0TE1) 6.1 3.7 -0.1 36.7

Fuel 0.0 0.0 -30.2 -99.4

Electric Power 0.0 0.0 49.7 108.4

(Total Energy Saving) 6.1 3.7 19.3 46.4 (Unit: Gcal/h) NOTE 1) SU steam conversion rate: 0.794 Gcal/h = 0.799 (SU steam calorie, Gcal/h) - 0.05 (Condensate calorie, Gcal/h) Following conversion coefficients are applied to convert energy in Gcal/h into that in TOE/year. 1) Pinch Technology Annual Energy consumption: 5.1 ktoe/year (= 6.1 Gcal/h X 8400hr/year X 0.1 toe/Gcal) 2) ARS Annual Energy consumption: 3.1 ktoe/year (= 3.7 Gcal/h X 8400hr/year X 0.1 toe/Gcal) 3) GTG 20MW cogeneration Annual Energy consumption: 16.2 ktoe/year (= 19.3 Gcal/h X 8400hr/year X 0.1 toe/Gcal) 4) GTG 45 MW cogeneration Annual Energy consumption: 39.0 ktoe/year (= 46.4 Gcal/h X 8400hr/year X 0.1 toe/Gcal)

-3-4- (3) Timeframe of energy savings and cumulative benefits (by project)

The energy savings achieved under this project would persist for the life of the equipment. For the purposes of calculation, energy savings in the equipment are assumed to accumulate for a period of 20 years, producing cumulative benefits from 2005 to 2024. Table 3.13 and Figure 3.1-1 show the cumulative energy savings for each project in isolation.

Table 3.1-3 Cumulative energy savings (Unit: k toe)

Pinch ARS GTG 20MW GTG 45MW

2005 5 3 16 39

2006 10 6 33 78

2007 15 9 49 117

2008 20 13 65 156

2009 26 16 81 195

2010 31 19 98 234

2011 36 22 114 273

2012 41 25 130 312

2013 46 28 146 351

2014 51 31 163 390

2015 56 35 179 429

2016 61 38 195 468

2017 66 41 211 507

2018 71 44 228 546

2019 77 47 244 585

2020 82 50 260 624

2021 87 54 276 663

2022 92 57 293 702

2023 97 60 309 741

2024 102 63 325 780

-3-5- Energy Savings (X 1000 TOE) 2005

2006

2007 ARS GTG GTG Pinch

2008

45MW 20MW

2009 Figure

2010

3.1

2011

1

Cumulative 2012 -3-6-

2013

2014 energy Year

2015

savings

2016

2017

2018

2019

2020

2021

2022

2023

2024 (4) Timeframe of energy savings and cumulative benefits (in total)

Table 3.14 and Figure 3.1-2 show the cumulative energy savings for the maximum case and the minimum case as total projects, respectively. The maximum total case includes “Heat recovery using Pinch technology ”, “Energy savings using the Advanced Recovery System (ARS)”, and “Co-generation using gas turbine power generator of 45MW”. The minimum total case includes “Heat recovery using Pinch technology” , “Energy savings using the Advanced Recovery System (ARS)”, and “Co-generation using gas turbine power generator of 20MW”.

Table 3.1-4 Cumulative energy savings (in total) (Unit: k toe)

Total Total Total Total

(Maximum) (Minimum) (Maximum) (Minimum)

2005 47 24 2015 519 269

2006 94 49 2016 567 294

2007 142 73 2017 614 318

2008 189 98 2018 661 343

2009 236 122 2019 708 367

2010 283 147 2020 756 392

2011 331 171 2021 803 416

2012 378 196 2022 850 441

2013 425 220 2023 897 465

2014 472 245 2024 944 490

-3-7- Total (Maximum) Total (Minimum)

2006 2007 2008 2009 2010 2011 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Figure 3.1-2 Cumulative energy savings (in total)

-3-8- 3.1.4 Verification of energy savings (monitoring methods)

Energy savings are achieved through more efficient heat recovery in the heat exchanger, as well as reduced utility consumption through boiler load reduction and refrigerant compressor load reduction. The main areas to be monitored are the fuel supply rate for boiler, and steam consumption in the refrigerant compressor driver, fuel consumption. The energy savings in the boiler can be verified through continuous monitoring of the rate of steam generation in each device. Similarly, operating rates of the plant can be confirmed via continuous monitoring of intake lines. Some of the measuring devices have already been installed with the tag numbers shown below. Measuring devices need to be fitted to the new gas turbine power generator includes monitoring the power generation rate at the supply end and the SU (steam) generation rate.

Table 3.1-4 Monitoring devices used to measure actual energy savings (already installed) Category Device tag number Location Intake charge KF1102KV Naphtha Ch ’g to FI 10 (cracker) KF1202KV Naphtha Ch ’g to FI20 KF1302KV Naphtha Ch ’g to F130 KF1402KV Naphtha Ch ’g to FI40 KF1403KV C4 Ch ’g to F140 KF1502KV Naphtha Ch ’g to F150 KF1602KV Naphtha Ch ’g to FI60 KF1702KV Naphtha Ch ’g to F170 KF1802KV Naphtha Ch ’g to FI80 KF1902KV Gas Ch ’g to F190 SU consumption FI6010 CT-600 (freezer compressor) FI6011 CT-600 FI6020 CT-650 Fuel consumption (Fuel Gas) FC70B Boiler-B (Off Gas) FI80B Boiler-B (PFO) FC60B Boiler-B (HFO) FC50B Boiler-B (Fuel Gas) FC70C Boiler-C

-3-9- 3.2 Reduced greenhouse gas emissions

3.2.1 Technological basis for reductions in greenhouse gas emissions

As is described in Chapter 3.1.1, we identified that energy saving project by pinch technology, introduction of Advanced Recovery System, and installation of GTG Co-generation system are very effectively save fuel. As the result, it is clear that C02 emission rate can be reduced as long as reduced fuel consumption.

3.2.2 Baseline used to estimate reductions in greenhouse gas emissions (i.e., without modifications)

As with energy savings calculations, the baseline was based on current operating data, as follows:

(1) Calculation of energy consumption or energy input at the project site prior to modification

As with energy savings calculations, the baseline was based on current operating data, as follows-

Processing capacity and operating rates

• Processing capacity 55.83 tons of ethylene per hour • Operating time 8,400 hours per year (Annual processing capacity = 470,000 tons)

Total fuel consumption (converted): 360.0 Gcal (= baseline)

The baseline figure in 2-1(1) (b) above was converted using the thermal conversion coefficient for fuel oil.

1. Annual fuel consumption 302 ktoe/year = 360.0 x 8,400 hr/yr x 0.1 toe/Gcal 2. Converted to energy units (unit: TJ) 12,900 TJ/year = 302 x 42.62 TJ/kt

3. Converted to carbon emission rate 258 ktons/year = 12,900 x 20

4. Corrected to account for unbumed 255 ktons/year = 258 x 0.99 components 5. Converted to C02 emission rate 936 tons/year = 255 x 44/12

3-10- 3.2.3 Estimate of actual reduction in greenhouse gas emissions, anticipated timeframe, and cumulative benefits

For the purposes of calculation, greenhouse gases will be restricted to carbon dioxide alone.

(1) Actual reduction in C02 emissions

Table 3.2-1 shows the reduction in C02 emissions expected from each of the proposed modifications:

Table 3.2-1 Reduction in C02 emissions expected from each modification (Unit: 1,000 tons/yr) Case Pinch analysis ARS GTG-20MW GTG-45MW Reduction in 15.8 9.7 50.3 120.6 C02 emissions

According to this table, the most significant reduction in C02 emissions (127 ktons per year) would be achieved through the co-generation system with a 45 MW gas turbine. For the purposes of calculation, electric power (kWh) was converted into fuel (kcal) at a power generation efficiency of 2,450 kcal/kWh. This figure assumes an average power generation efficiency of around 35% at the sending end of an ordinary boiler/turbine type power plant.

The baseline volume of C02 generated is calculated from the energy density using the following expression:

1) Expected reductions in annual C02 emissions from pinch technology heat recovery system 1. Annual fuel reduction 5.1 ktoe/yr 2. Converted to energy units (unit: TJ) 217 TJ/yr

3. Converted to carbon emission per 4.3 ktons/yr product unit 4. Corrected to account for unbumed 4.3 k tons/yr components 5. Converted to C02 units 15.8 ktons/yr

2) Expected reductions in annual C02 emissions from Advanced Recovery System 1. Annual fuel reduction 3.1 ktoe 2. Converted to energy units (unit: TJ) 134 TJ 3. Converted to carbon emission per 2.7 kton product unit 4. Corrected to account for unburned 2.7 kton components 5. Converted to C02 units 9.7 kton

3) Expected reductions in annual C02 emissions from co-generation system with a 20MW gas turbine power generator 1. Annual fuel consumption 16.2 ktoe 2. Converted to energy units (unit: TJ) 692 TJ 3. Converted to carbon emission per 13.8 kton product unit 4. Corrected to account for unbumed 13.7 kton components 5. Converted to C02 units 50.3 kton

4) Expected reductions in annual C02 emissions from co-generation system with a 45MW gas turbine power generator 1. Annual fuel consumption 39.0 ktoe 2. Converted to energy units (unit: TJ) 1,661 TJ 3. Converted to carbon emission per 33.2 kton product unit 4. Corrected to account for unbumed 32.9 kton components 5. Converted to C02 units 120.6 kton

(2) Timeframe of reduction in C02 emissions and cumulative benefits (by project)

The reduction in C02 emissions achieved under this project would persist for the life of the equipment.

For the purposes of calculation, energy savings in the equipment are assumed to persist for a period of 20 years, producing cumulative benefits lasting from 2005 to 2024.

Table 3.2-2 and Figure 3.2-1 show the cumulative benefits in terms of C02 emission reductions for each project in isolation.

-3-12- Table 3.2-2 Cumulative reduction of CO? emissions (Unit: tons CO? x 1,000)

Pinch ARS GTG 20MW GTG 45MW

2005 16 10 50 121

2006 32 19 101 241

2007 47 29 151 362

2008 63 39 201 482

2009 79 49 251 603

2010 95 58 302 724

2011 110 68 352 844

2012 126 78 402 965

2013 142 88 452 1,085

2014 158 97 503 1,206

2015 174 107 553 1,327

2016 189 117 603 1,447

2017 205 127 654 1,568

2018 221 136 704 1,688

2019 237 146 754 1,809

2020 253 156 804 1,930

2021 268 166 855 2,050

2022 284 175 905 2,171

2023 300 185 955 2,291

2024 316 195 1,005 2,412

-3-13- Figure

3.2-1 C 0 2Reduction(X 1000 ton)

Cumulative 2005

2006

reduction

2007

of 2008

C0

2 2009

emissions ■Pinch

-GTG •ARS 2010 GTG

2011 45MW 20MW

2012

(Unit:

2013

tons

2014

C0 Year 2

x 2015

1,000) -3-14-

2016

2017

2018

2019

2020

2021

2022

2023

2024 (3) Timeframe of reduction in C02 emissions and cumulative benefits (in total)

Table 3.2-3 and Figure 3.2*2 show the cumulative benefits in terms of C02 emission reductions for the maximum case and the minimum case as total projects, respectively. The maximum total case includes “Heat recovery using Pinch technology ”, “Energy savings using the Advanced Recovery System (ARS)”, and “Co-generation using gas turbine power generator of 45MW”. The minimum total case includes “Heat recovery using Pinch technology ”, “Energy savings using the Advanced Recovery System (ARS)”, and “Co-generation using gas turbine power generator of 20MW”.

Table 3.2-3 Cumulative reduction of C02 emissions (Unit: tons C02 x 1,000)

Total Total Total Total

(Maximum) (Minmum) (Maximum) (Minmum)

2005 146 76 2015 1,607 834

2006 292 152 2016 1,753 910

2007 438 227 2017 1,900 985

2008 584 303 2018 2,046 1,061

2009 731 379 2019 2,192 1,137

2010 877 455 2020 2,338 1,213

2011 1,023 531 2021 2,484 1,289

2012 1,169 606 2022 2,630 1,364

2013 1,315 682 2023 2,776 1,440

2014 1,461 758 2024 2,922 1,516

-3-15- C 0 2 Reduction (X 1000 ton) 3,500 2005

2006

2007

Figure 2008

3.2-2 2009

Total Total

Cumulative 2010

(Minimum) (Maximum)

2011

reduction

2012

of 2013

C0 -3-16-

2 2014

emissions Year

2015

2016

(Unit: 2017

tons 2018

C0

2019 2

x

1,000)

2020

2021

2022

2023

2024 3.2.4 Verification of reductions in greenhouse gas emissions (monitoring methods)

Reductions in greenhouse gas emissions are achieved through more efficient heat recovery in the heat exchanger, as well as reduced utility consumption through boiler load reduction and refrigerant compressor load reduction. The main areas to be monitored are the fuel supply rate for boiler, and steam consumption in the refrigerant compressor driver. The energy savings in the boiler can be verified through continuous monitoring of the rate of steam generation in each device. The reductions in greenhouse gas emissions at the plant can be confirmed via continuous monitoring of intake lines. Likewise, the boiler can be verified via continuous monitoring of the rate of steam generation in each device.

Some of the measuring devices have already been installed with the tag numbers shown below. Measuring devices need to be fitted to the new gas turbine power generator includes monitoring the power generation rate at the supply end and the SU (steam) generation rate.

Once fuel consumption data is obtained via the monitoring process described above, the expected reduction in greenhouse gases can be calculated using the expression given in section 3.2.3.

Monitoring devices used to measure actual energy savings (already installed) Category Device tag number Location Intake charge KF1102KV Naphtha Ch ’g to FI 10 (cracker) KF1202KV Naphtha Ch ’g to F120 KF1302KV Naphtha Ch ’g to F130 KF1402KV Naphtha Ch ’g to FT40 KF1403KV C4 Ch ’g to F140 KF1502KV Naphtha Ch ’g to F150 KF1602KV Naphtha Ch ’g to FT60 KF1702KV Naphtha Ch ’g to FI70 KF1802KV Naphtha Ch ’g to FT80 KF1902KV Gas Ch ’g to F190 SU consumption FI6010 CT-600 (freezer compressor) FI6011 CT-600 FI6020 CT-650 Fuel consumption (Fuel Gas) FC70B Boiler-B (Off Gas) FI80B Boiler-B (PFO) FC60B Boiler-B (HFO) FC50B Boiler-B (Fuel Gas) FC70C Boiler-C

-3-17- 3.3 Productivity improvements

Ethylene processing equipment has much higher fuel requirements than other equipment used at petrochemical plants. The bulk of its massive energy requirements is accounted for by the power load of the cracker and the compressor used in the refining/separation process. Promoting energy conservation in this equipment with high fuel consumption will obviously reduce fuel costs, which account for a considerable proportion of overall production costs, while improving productivity.

The PCS’s Complex I (the focus of this project) has been operating for 16 years. The equipment has been modified numerous times in an effort to alleviate production bottlenecks. It is anticipated that total energy input could be reduced by approximately 3% by applying pinch technology to improve energy recovery in the low temperature distillation line, and by using the Advanced Recovery System to reduce the power load in the refrigeration system. This would reduce boiler fuel consumption, and in turn further reduce the amount of energy required for ethylene production.

Additional revenue from the sale of surplus power produced via co-generation would also help to make the plant more competitive.

Modifications to the energy recovery system also raise the possibility of adding capacity in the future. The energy savings identified in this study may generate spare capacity in the existing boiler system, while spare capacity in the freezer system compressor may alleviate restrictions imposed by existing equipment and raise the possibility of boosting ethylene production capacity in the future.

-3-18- Chapter 4 Earnings potential

Chapter 4 looks at the amount of investment required to implement the projects described in Chapters 2 and 3 and discusses anticipated earnings, energy savings, and reductions in C02 emissions.

4.1 Recovery of investment

This Chapter looks at the total investment required to achieve the energy savings and reductions in C02 emissions outlined in Chapter 2.2, “Overview of Implementation Site/Company. ” Calculations are based on the following assumptions and prerequisites:

4.1.1 Investment calculation method

(1) Currency exchange rate

For the purposes of calculation, the exchange rate as of January 2001 is applied at all times when investment is required.

US$1 =¥110 = 1.6 S$ i.e.,

S$1 = ¥68.75

(2) Price standards

All expenses are calculated at January 2001 prices, without accounting for inflation.

4.1.2 Required level of investment

The total investment required carrying out equipment modifications in order to reduce energy consumption at the naphtha cracker I at PCS is given below:

(1) Pinch technology heat recovery alleviation project: ¥460 million (2) ARS power reduction project: ¥3,700 million (3) GTG 20 MW Co-generation project: ¥3,445 million (4) GTG 45 MW Co-generation project: ¥5,460 million

-4-1- Since details of the CDM mechanism have yet to be finalized at this stage, all of the foreign currency required is considered to be provided through long-term environmental credits in yen.

Investment breakdown (¥M) Pinch GTG-20M GTG-45M Case ARS analysis W W Design and engineering 70 428 640 736 Procurement and transportation of 147 2,112 1,970 3,632 machinery and equipment

Work on site 243 1,160 835 1,092 Total 460 3,700 3,445 5,460

4.1.3 Breakdown of total investment

The investment breakdown is outlined below.

(1) Design and engineering

Expenses associated with design and engineering at the relevant plant including: more detailed FS based on the present study; formulation of overall project plan; and preliminary and detailed designs for new machinery and equipment.

(2) Procurement and transportation of machinery and equipment

Expenses associated with materials and machinery required for plant modifications including: purchase of all materials and machinery required in the project; purchase of spare parts for newly installed machines; pre-shipment factory inspections of materials and machines; marine transportation of same; unloading and customs procedures at the port of discharge in Singapore; land transport to the construction site; and insurance expenses associated with land transportation.

(3) Work on site

All expenses —personnel expenses, temporary construction costs, purchase of secondary materials required for installation, and rental of construction machinery —associated with installation and assembly at the plant, covering: formulation of site work schedules; installation

-4-2- of machinery and piping; earth-moving work; steel frame and building construction; instrumentation and electrical work; thermal insulation/flame-proof sheathing work; painting; training on new machinery for operators and maintenance personnel; assistance with test runs and performance evaluations; and associated supervision and guidance.

4.1.4 Recovery of investment

(1) Initial investment

The initial investment described in Section 4.1.2 above would be required in the first year of the project.

(2) Operating costs

Ongoing use of the modified equipment would necessitate payment of an amount equivalent to 1.5% of the initial investment annually (starting from the first year of the project) for maintenance expenses and insurance. No additional utility costs and no additional operator wages are expected to arise.

(3) Revenue from energy savings

The energy savings achieved as a result of the project would generate economic benefits in the form of additional revenue, as described in Section 4.2.1.

(4) Recovery of investment

Return on Investment (ROI) after Tax for each project is given below:

Pinch Heat Recovery Project 19% 20 MW GTG Co-Generation 19% 45 MW GTG Co-Generation 27%

ROIs in this stage are based on assumptions Those are subject to be reviewed depend on further in-detail study.

-4-3- For the case of Advanced Recovery System, the modification target is not only energy saving but more on capacity expansion. Considering the feature of this specific project, ROI of Advanced Recovery System Project from energy cost saving should not be comparable with the others. Therefore, the ROI of Advanced Recovery System is not listed above.

-4-4- EPC Cost: 460 MM YEN 1. Project Life No. of Year 1.1 Construction (EPC) 3 1.2 Operation 35 Total 38

2. Capital Cost & Payment Schedule C1 C2 C3 Total MM¥ Basis 2.1 EPC Cost 30% 40% 30% 100% 460.0 2.2 Owner's Cost 30% 40% 30% 100% 46.0 10.0% on EPC Cost 2.3 Initial Working Capital 0% 0% 100% 100% 12.9 1 Month(s) Revenue

3. Total Revenue Quantity per Day Operating Hours per Year Quantity per Year Unit Price MM ¥ /Year 3.1 Energy Conservation Merit 155.3

4. Operation Cost: Fixed Cost Quantity or Basis Unit Cost MM ¥ /Year 4.1 Personnel Expenses 0 persons 0.0 4.2 Administration 0.0 % of Personnel Expenses 0.0 4.3 Maintenance & Insurance 1.5 % of EPC Cost 6.9

5. Depreciation Method Period Salvage MM ¥ /Year 5.1 EPC Cost Straight Line 10 years 0% 46.0 5.2 Owner's Cost Straight Line 10 years 0% 4.6 5.3 Initial Working Capital None

6. Tax Tax Rate Tax Holiday 6.1 Income Tax 26% None

Table4.1-2 Conditions of Cash Flow Calculation for the Project of Improvements in Heat Recovery Systems CASE: Pinch Heat Recovery

Unit: MMJP ¥ Construction (EPC) i Operation Year C1 C2 C3 ! 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

1. Capital Cost 1.1 EPC Cost 138.0 184.0 138.0 1.2 Owner's Cost 13.8 18.4 13.8 1.3 Initial Working Capital 0.0 0.0 12.9 1.4 Total 151.8 202.4 164.7

2. Operation Factor 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

3. Products Sales Revenue 3.1 Energy Conservation Merit 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 3.2 Total 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3

4. Operation Cost: Fixed Cost 4 1 Personnel Expenses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.2 Administration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.3 Maintenance & Insurance 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 4.4 Total 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9

5. Depreciation 5.1 Depreciation 50.6 50.6 50.6 50.6 50.6 50.6 50.6 50.6 50.6 50.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0

6. Profit & Tax 6.1 Profit before Tax 97.8 97.8 97.8 97.8 97.8 97.8 97.8 97.8 97.8 97.8 148.4 148.4 148.4 148.4 148.4 148.4 148.4 6.2 Cumulative Profit before Tax 97.8 195.6 293.4 391.2 489.0 586.8 684.6 782.4 880.2 978.0 1126.4 1274.8 1423.2 1571.6 1720.0 1868.4 2016.8 6.3 Tax Rate 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 6.4 Tax 25.4 25.4 25.4 25.4 25.4 25.4 25.4 25.4 25.4 25.4 38.6 38.6 38.6 38.6 38.6 38.6 38.6 6.5 Profit after Tax 72.4 72.4 72.4 72.4 72.4 72.4 72.4 72.4 72.4 72.4 109.8 109.8 109.8 109.8 109.8 109.8 109.8 6.6 Cumulative Profit after Tax 72.4 144.7 217.1 289.5 361.9 434.2 506.6 579.0 651.3 723.7 833.5 943.4 1053.2 1163.0 1272.8 1382.6 1492.4

7. Net Cash Flow 7.1 NCF before Tax -151.8 -202.4 -164.7 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 7.2 NCF after Tax -151.8 -202.4 -164.7 123.0 123.0 123.0 123.0 123.0 123.0 123.0 123.0 123.0 123.0 109.8 109.8 109.8 109.8 109.8 109.8 109.8

8. IRR on Investment (ROI) 8.1 ROI before Tax 23.04% 8.2 ROI after Tax ______19.36%

Table 4.1-3 Cash Flow Calculation Sheet for the Project of Improvements in Heat Recovery Systems CASE: Pinch Heat Recovery

Unit: MMJP ¥

Year j8 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 Total

1. Capital Cost 1.1 EPC Cost 460.0 1.2 Owner's Cost 46.0 1.3 Initial Working Capital 12.9 1.4 Total 518.9

Operation Factor 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Products Sales Revenue 3.1 Energy Conservation Merit 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 5435.5 3.2 Total 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 155.3 5435.5

Operation Cost: Fixed Cost 4.1 Personnel Expenses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.2 Administration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.3 Maintenance & Insurance 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 241.5 4.4 Total 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 241.5

Depreciation 5.1 Depreciation 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 506.0

Profit & Tax 6.1 Profit before Tax 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 4688.0 6.2 Cumulative Profit before Tax 2165.2 2313.6 2462.0 2610.4 2758.8 2907.2 3055.6 3204.0 3352.4 3500.8 3649.2 3797.6 3946.0 4094.4 4242.8 4391.2 4539.6 4688.0 4688.0 6.3 Tax Rate 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 6.4 Tax 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 38.6 1218.9 6.5 Profit after Tax 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 3469.1 6.6 Cumulative Profit after Tax 1602.2 1712.1 1821.9 1931.7 2041.5 2151.3 2261.1 2371.0 2480.8 2590.6 2700.4 2810.2 2920.0 3029.9 3139.7 3249.5 3359.3 3469.1 3469.1

Net Cash Flow 7.1 NCF before Tax 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 148.4 4675.1 7.2 NCF after Tax 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 109.8 3456.2

8. IRR on Investment (ROI) 8.1 ROI before Tax ______23.04% 8.2 ROI after Tax ______19.36%

Table 4.1-4 Cash Flow Calculation Sheet for the Project of Improvements in Heat Recovery Systems CASE: 20MWGTG EPC Cost: 3445 MMYEN 1. Project Life No. of Year 1.1 Construction (EPC) 3 1.2 Operation 35 Total 38

2. Capital Cost & Payment Schedule C1 C2 C3 Total MM¥ Basis 2.1 EPC Cost 30% 40% 30% 100% 3445.0 2.2 Owner's Cost 30% 40% 30% 100% 344.5 10.0% on EPC Cost 2.3 Initial Working Capital 0% 0% 100% 100% 93.8 1 Month(s) Revenue

3. Total Revenue Quantity per Day Operating Hours per Year Quantity per Year Unit Price MM ¥/Year 3.1 Energy Conservation Merit 1125.5

4. Operation Cost: Fixed Cost Quantity or Basis Unit Cost MM ¥/Year 4.1 Personnel Expenses 0 persons 0.0 4.2 Administration 0.0 % of Personnel Expenses 0.0 4.3 Maintenance & Insurance 1.5 % of EPC Cost 51.7

5. Depreciation Method Period Salvage MM ¥ /Year 5.1 EPC Cost Straight Line 10 years 0% 344.5 5.2 Owner's Cost Straight Line 10 years 0% 34.5 5.3 Initial Working Capital None

6. Tax Tax Rate Tax Holiday 6.1 Income Tax 26% None

Table 4.1-5 Conditions of Cash Flow Calculation for the Project of Cogeneration with a 20 MW Gas Turbine generator CASE: 20MW GTG

Unit: MMJP ¥ Construction (EPC) I Operation Year C1 C2 C3 i 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

1. Capital Cost 1.1 EPC Cost 1033.5 1378.0 1033.5 1.2 Owner's Cost 103.4 137.8 103.4 1 3 Initial Working Capital 0.0______00^____ 93.8 1.4 Total 1136.9 1515.8 1230.6

Operation Factor 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Products Sales Revenue 3.1 Energy Conservation Merit 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 3.2 Total 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5

Operation Cost: Fixed Cost 4.1 Personnel Expenses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.2 Administration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.3 Maintenance & Insurance 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 4.4 Total 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7

Depreciation 5.1 Depreciation 379.0 379.0 379.0 379.0 379.0 379.0 379.0 379.0 379.0 379.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Profit & Tax 6.1 Profit before Tax 694.9 694.9 694.9 694.9 694.9 694.9 694.9 694.9 694.9 694.9 1073.8 1073 8 1073.8 1073.8 1073.8 1073.8 1073.8 6.2 Cumulative Profit before Tax 694.9 1389.8 2084.6 2779.5 3474.4 4169.3 4864.1 5559.0 6253.9 6948.8 8022.6 9096.4 10170.2 11244.1 12317.9 13391.7 14465.5 6.3 Tax Rate 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 6.4 Tax 180.7 180.7 180.7 180.7 180.7 180.7 180.7 180.7 180.7 180.7 279.2 279.2 279.2 279.2 279.2 279.2 279.2 6.5 Profit after Tax 514.2 514.2 514.2 514.2 514.2 514.2 514.2 514.2 514.2 514.2 794.6 794.6 794.6 794.6 794.6 794.6 794.6 6.6 Cumulative Profit after Tax 514.2 1028.4 1542.6 2056.8 2571.0 3085.2 3599.5 4113.7 4627.9 5142.1 5936.7 6731.3 7526.0 8320.6 9115.2 9909.9 10704.5

Net Cash Flow 7.1 NCF before Tax -1136.9 -1515.8 -1230.6 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 7.2 NCF after Tax -1136.9 -1515.8 -1230.6 893.2 893.2 893.2 893.2 893.2 893.2 893.2 893.2 893.2 893.2 794.6 794.6 794.6 794.6 794.6 794.6 794.6

8. IRR on Investment (ROI) 8.1 ROI before Tax ______22.40% 8.2 ROI after Tax ______18,84%

Table 4.1-6 Cash Flow Calculation Sheet for the Project of Cogeneration with a 20 MW Gas Turbine CASE: 20MWGTG

Unit: MMJP ¥

Year 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 Total

1. Capital Cost 1.1 EPC Cost 3445.0 1.2 Owner's Cost 344.5 1.3 Initial Working Capital 93.8 1.4 Total 3883.3

Operation Factor 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Products Sales Revenue 3.1 Energy Conservation Merit 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 39392.5 3.2 Total 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 1125.5 39392.5

Operation Cost: Fixed Cost 4.1 Personnel Expenses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.2 Administration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.3 Maintenance & Insurance 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 . 51,7 51.7 51.7 51.7 51.7 51.7 51.7 1808.6 4.4 Total 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 51.7 1808.6

Depreciation 5.1 Depreciation 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3789.5

Profit & Tax 6.1 Profit before Tax 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 33794.4 6.2 Cumulative Profit before Tax 15539.4 16613.2 17687.0 18760.8 19834.7 20908.5 21982.3 23056.1 24130.0 25203.8 26277.6 27351.4 28425.3 29499.1 30572.9 31646.7 32720.6 33794.4 33794.4 6.3 Tax Rate 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 6.4 Tax 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 279.2 8786.5 6.5 Profit after Tax 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 25007.8 6.6 Cumulative Profit after Tax 11499.1 12293.7 13088.4 13883.0 14677.6 15472.3 16266.9 17061.5 17856.2 18650.8 19445.4 20240.1 21034.7 21829.3 22623.9 23418.6 24213.2 25007.8 25007.8

Net Cash Flow 7.1 NCF before Tax 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 1073.8 33700.6 7.2 NCF after Tax 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 794.6 24914.0

8. IRR on Investment (ROI) 8.1 ROI before Tax ___^_2Z40% 8.2 ROI after Tax ______18.84%

Table 4.1-7 Cash Flow Calculation Sheet for the Project of Cogeneration with a 20 MW Gas Turbine CASE: 45MWGTG EPC Cost: 5460 MMYEN 1. Project Life No. of Year 1.1 Construction (EPC) 3 1.2 Operation 35 Total 38

2. Capital Cost & Payment Schedule C1 C2 C3 Total MM¥ Basis 2.1 EPC Cost 30% 40% 30% 100% 5460.0 2.2 Owner's Cost 30% 40% 30% 100% 546.0 10.0% on EPC Cost 2.3 Initial Working Capital 0% 0% 100% 100% 227.2 1 Month(s) Revenue

3. Total Revenue Quantity per Day Operating Hours per Year Quantity per Year Unit Price MM ¥/Year 3.1 Energy Conservation Merit 2726.4

4. Operation Cost: Fixed Cost Quantity or Basis Unit Cost MM ¥/Year 4.1 Personnel Expenses 0 persons 0.0 4.2 Administration 0.0 % of Personnel Expenses 0.0 4.3 Maintenance & Insurance 1.5 % of EPC Cost 81.9

5. Depreciation Method Period Salvage MM ¥/Year 5.1 EPC Cost Straight Line 10 years 0% 546.0 5.2 Owner's Cost Straight Line 10 years 0% 54.6 5.3 Initial Working Capital None

6. Tax Tax Rate Tax Holiday 6.1 Income Tax 26% None

Table 4.1-8 Conditions of Cash Flow Calculation for the Project of Cogeneration with a 45 MW Gas Turbine CASE: 45MWGTG

Unit: MMJP ¥ Construction (EPC) S Operation Year C1 C2 C3 i 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

1. Capital Cost 1.1 EPC Cost 1638.0 2184.0 1638.0 1.2 Owner's Cost 163.8 218.4 163.8 1.3 Initial Working Capi tal 0.0______0.0 227.2 1.4 Total 1801.8 2402.4 2029.0

2. Operation Factor 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

3. Products Sales Revenue 3.1 Energy Conservation Merit 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 3.2 Total 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4

4. Operation Cost: Fixed Cost 4.1 Personnel Expenses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.2 Administration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.3 Maintenance & Insurance 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 4.4 Total 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9

5. Depreciation 5.1 Depreciation 600.6 600.6 600.6 600.6 600.6 600.6 600.6 600.6 600.6 600.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0

6. Profit & Tax 6 1 Profit before Tax 2043.9 2043.9 2043.9 2043.9 2043.9 2043.9 2043.9 2043.9 2043.9 2043.9 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 6.2 Cumulative Profit before Tax 2043.9 4087.8 6131.7 8175.6 10219.5 12263.4 14307.3 16351.2 18395.1 20439.0 23083.5 25728.0 28372.5 31017.0 33661.5 36306.0 38950.5 6.3 Tax Rate 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 6.4 Tax 531.4 531.4 531.4 531.4 531.4 531.4 531.4 531.4 531.4 531.4 687.6 687.6 687.6 687.6 687.6 687.6 687.6 6.5 Profit after Tax 1512.5 1512.5 1512.5 1512.5 1512.5 1512.5 1512.5 1512.5 1512.5 1512.5 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 6.6 Cumulative Profit after Tax 1512.5 3025.0 4537.5 6049.9 7562.4 9074.9 10587.4 12099.9 13612.4 15124.9 17081.8 19038.7 20995.7 22952.6 24909.5 26866.4 28823.4

7. Net Cash Flow 7.1 NCF before Tax -1801.8 -2402.4 -2029.0 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 7.2 NCF after Tax -1801.8 -2402.4 -2029.0 2113.1 2113.1 2113.1 2113.1 2113.1 2113.1 2113.1 2113.1 2113.1 2113.1 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9

8. IRR on Investment (ROI) 8.1 ROI before Tax 31.77% 8.2 ROI after Tax ______26.40%

Table 4.1-9 Cash Flow Calculation Sheet for the Project of Cogeneration with a 45 MW Gas Turbine CASE: 45MWGTG

Unit: MMJP ¥

Year 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 Total

1. Capital Cost 1.1 EPC Cost 5460.0 1.2 Owner's Cost 546.0 1.3 Initial Working Capital 227.2 1.4 total 6233.2

Operation Factor 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Products Sales Revenue 3.1 Energy Conservation Merit 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 95424.0 3.2 Total 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 2726.4 95424.0

Operation Cost: Fixed Cost 4.1 Personnel Expenses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.2 Administration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.3 Maintenance & Insurance 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 2866.5 4.4 Total 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 81.9 2866.5

Depreciation 5.1 Depreciation 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6006.0

Profit & Tax 6.1 Profit before Tax 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 86551.5 6.2 Cumulative Profit before Tax 41595.0 44239.5 46884.0 49528.5 52173.0 54817.5 57462.0 60106.5 62751.0 65395.5 68040.0 70684.5 73329.0 75973.5 78618.0 81262.5 83907.0 86551.5 86551.5 6.3 Tax Rate 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 26% 6.4 Tax 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 687.6 22503.4 6.5 Profit after Tax 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 64048.1 6.6 Cumulative Profit after Tax 30780.3 32737.2 34694.2 36651.1 38608.0 40565.0 42521.9 44478.8 46435.7 48392.7 50349.6 52306.5 54263.5 56220.4 58177.3 60134.3 62091.2 64048.1 64048.1

Net Cash Flow 7 1 NCF before Tax 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 2644.5 86324.3 7.2 NCF after Tax 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 1956.9 63820.9

8. IRR on Investment (ROI) 8.1 ROI before Tax 31.77% 8.2 ROI after Tax ______26.40%

Table 4.1-10 Cash Flow Calculation Sheet for the Project of Cogeneration with a 45 MW Gas Turbine 4.2 Cost-benefit analysis

The anticipated project benefits are: lower utility charges through energy savings; reduced emissions of the greenhouse gas C02; and greater production output as a result of increased productivity.

In the United States, C02 emissions trading has been introduced as a means of reducing emissions. However, as of last year’s COP6 meeting, details of emissions trading (via clean development mechanisms, for example) had yet to be finalized. Even assuming that the scheme is successful in reducing C02 emissions, it is difficult to place a dollar value per reduction of ton of greenhouse gases. Potential productivity improvements are also expected, but not considered here.

The cost-benefit evaluation involves comparing the initial cost of plant and equipment investments against subsequent reductions in operating costs. Here, operating costs consist of the reductions in utility charges resulting from energy savings, plus operating costs associated with project implementation.

The following section discusses the financial benefits associated with energy savings and reduced greenhouse gas emissions.

4.2.1 Energy savings

The financial benefits to be derived from the project are determined by calculating changes in utility charges for steam, fuel, and electricity.

Changes in utility consumption are calculated by comparing consumption rates before and after the modifications. These are then multiplied by the unit charges for each utility to generate a figure for cost savings.

(1) Utility charges

Utility charges are as follows. The fuel oil price is based on HSFO (Sulfur 3.5%, ISOcst) Singapore Spot price (average price from January 2000 to December 2000, data source: Platt’s Oligram Price Report). Other utility prices are estimated on the equivalent heat value.

-4-14- Steam (SU) S$33.2/MT (=¥2,283/MT) Fuel gas S$318.3/MT (= ¥21,883/MT) Fuel oil S$257.1/MT (= ¥17,676MT) Electricity S$0.15/kWh (=¥10.3 kWh)

(2) Energy savings Table 4.2-1 Energy savings Pinch ARS 20 MW GTG 45 MW GTG SU steam (ton/hr) 8.1 5.0 -0.1 49.9 Fuel (Gcal/hr) 0 0 -30.2 -99.4 Electricity (MW) 0 0 20.3 44.2 Energy savings 6.1 3.7 19.3 46.4 (Gcal/hr)

(3) Economic benefits of energy savings (¥M/yr)

The economic benefit of each project is calculated below in Table 4.2-2, based on the energy savings given above: Regarding GTG Co-Generation, boiler B would be shut down after Co-Generation project implemented. Effect of economic benefit is calculated comparing boiler B operation cost.

Table 4.2-2 Energy savings Economic Benefits Pinch ARS 20 MW GTG 45 MW GTG SU steam - Condensate 155 96 -2 957 Fuel 0 0 -556 -1,827 Electricity 0 0 1,756 3,832 additional variable cost -73 -236 Economic Benefits 155 96 1,125 2,726 (Unit: ¥M/yr) The most significant economic benefit from energy savings (defined as the initial investment values given in Section 4.1.2, divided by the savings generated via lower fuel consumption shown above) would be achieved from the co-generation system with a gas turbine power generator. Table 4.2-3 Economical Return on Initial Investment Initial investment Economic benefit through ROI (¥M) energy savings (¥M/yr) (after Tax) % Pinch 460 151 19.36 GTG 20MW 3,445 1,125 18.84 GTG 45 MW 5,460 2,726 26.40

4.2.2 Cost versus project benefit

(1) The cost versus energy savings for one year are shown below, relative to the initial

-4-15- investment: Table 4.2-4 Cost versus energy savings

Initial investment Energy savings Cost versus energy savings (*M) (toe/yr) (toe/yr/¥M) Pinch 460 5,101 11.1 ARS 3,700 3,149 0.9 GTG 20 MW 3,445 16,251 4.7 GTG 45 MW 5,460 38,975 7.1 Total (Maximum) 9,620 47,224 4.9 Total (Minimum) 7,605 24,500 3.2

(2) Cost versus energy savings over a period of 20 years

The cost-benefit value, defined as the cost per unit of energy saving, is determined by calculating the cost of plant and equipment investment directly related to energy-saving modifications in terms of cumulative energy savings over a period of 20 years.

Table 4.2-5 Cost versus 20 years energy savings Initial investment Energy savings Cost versus energy savings (¥M) (toe/20yr) (toe/¥M) Pinch 460 102,014 222 ARS 3,700 62,971 17 GTG 20 MW 3,445 325,013 94 GTG 45 MW 5,460 779,501 143 Total (Maximum) 9,620 944,486 98 Total (Minimum) 7,605 489,999 64

4.2.3 Cost versus greenhouse gas reductions

(1) Cost versus greenhouse gas emissions in the first year, relative to initial investment

Initial investment Greenhouse gas Cost versus greenhouse (¥M) emissions gas reduction (ton-COVyr) (ton-COz/yr/YM) Pinch 460 15,783 34 ARS 3,700 9,742 3 GTG 20 MW 3,445 50,270 15 GTG 45 MW 5,460 120,597 22 Total (Maximum) 9,620 146,122 15 Total (Minimum) 7,605 75,795 10

(2) Cost-benefit as investment cost per unit reduction in greenhouse gas emissions

-4-16- The following table shows the initial investment required in energy-saving modifications in terms of cumulative reductions in greenhouse gas emissions over a period of 20 years.

Initial investment Greenhouse gas Cost versus greenhouse (¥M) emissions gas reduction (ton-CO 2/20yr) (ton-COa/YM) Pinch 460 315,652 686 ARS 3,700 194,847 53 GTG 20 MW 3,445 1,005,403 292 GTG 45 MW 5,460 2,411,942 442 Total (Maximum) 9,620 2,922,441 304 Total (Minimum) 7,605 1,515,902 199

-4-17- Chapter 5 LOCAL DIFFUSION OF THE TECHNOLOGIES

The project described in this report is designed to reduce energy consumption and C02 emissions from the naphtha cracker I and utility equipment at PCS’s plant. Technologies studied in this report include Energy recovery Optimization using Pinch Technology, Energy Saving applying Advanced Recovery System, and Installing new Co-generation Plant.

Among those technologies, Pinch Technology can be used to achieve energy savings at any ethylene processing plant, regardless of plant design. Analysis tools such as pinch technology are considered effective ways of reducing fuel consumption and achieving energy savings in plant systems as a whole.

Although Advanced Recovery System (ARS) is the basic design to be licensed by S&W, it could be applicable not only for Ethylene Plants design of S&W but also those of other Ethylene licensors. In other words, this technology could be applicable for most of Ethylene plants without ARS technology.

On the other hand, Installing new Co-generation Plant is effective for any plant who used both of electric power and steam utility. Especially, an Industries of high Energy Intensity, such as Oil Refineries or Petrochemical Companies are the candidate who could reduce energy consumption by installing new Co-generation plants. As the diffusion effect identified here is based on certain assumptions, the result is subjected to further detailed feasibility study.

5.1 Possibility of local diffusion of technologies to be introduced in this project

The products produced within the complex are continually in high demand in the complex. The ethylene production lines at the plant are maintained at high operating rates, as are downstream lines such as polyethylene and polypropylene plants, which are owned by affiliated companies. This provides a stable earnings structure. Implementation of the project could help expand business by boosting ethylene production capacity.

PCS views improvements of its plant profitability and consideration for environment as top priorities. With respect to modifications that would achieve genuine energy savings, the company has expressed its eagerness to proceed with energy-saving equipment modifications, supposed that the project is economically justified. So there is a good possibility of achieving energy savings and reductions in greenhouse gases.

-5 - 1 - 5.2 Benefits including diffusion effects

Complex I and II ethylene plants owned by PCS have a combined annual production capacity of 965,000 tons. Although we have not studied in detail, the following diffusion effects are expected to the No.2 ethylene plant.

5.2.1 Energy saving

The energy savings anticipated from implementing the Pinch analysis project at Complex II ethylene plant, where ARS is already installed, are estimated at 7 ktoe per year (assuming an energy-saving of around 2% of total energy consumption from the project).

Note: Energy savings from PCS I project = 47 ktoe/yr (converted to annual crude oil equivalent)

5.2.2 Greenhouse gas reductions

The reductions in greenhouse gas emissions anticipated from implementing the pinch analysis project on PCS’s Complex II ethylene complex plant (as in (2) above) is estimated to be 18 kton-C0 2 per year.

Note: Reduction in greenhouse gases from PCS I project = 146 kton-CCVyr

-5-2- Chapter 6 Other benefits

In addition to reducing emissions of greenhouse gases (i.e., carbon dioxide) through energy savings, the project is expected to deliver the following benefits:

1. The energy savings will reduce the energy consumption per unit volume of ethylene production, making the final products (ethylene and propylene) more cost competitive.

2. Lower fuel consumption will proportionally reduce the amount of atmospheric pollutants such as SOx and NOx in exhaust gases.

3. The energy savings will generate spare capacity in the heat recovery and power systems, which will alleviate bottlenecks in expansion of equipment capacity.

4. Modifications to existing equipment will encourage investment in new equipment.

-6 - 1 - Chapter 7 Conclusions

Singapore is poised to become a major petroleum refining and petrochemical production center and a leading presence in Asian economic growth. The petrochemical industry will become increasingly crucial to Singapore in light of growth expectations for the industry and rising demand for ethylene products. Like Japan, Singapore relies almost exclusively on supplies of primary energy materials such as petroleum from external sources, and its economy is primarily driven by processing and exports, requiring significant amounts of foreign capital. Buoyed by free economy, the petroleum industry in Singapore is expected to enjoy continued growth for some time. Although eager to implement measures to reduce greenhouse gas emissions, Singapore does not have clearly defined targets as do many industrialized nations, because it is still classified as a developing nation. The government of Singapore is keen to obtain greenhouse gas reduction credits for energy-saving projects such as this.

The government of Singapore has a strong interest in emissions trading via Clean Development Mechanisms (CDM) with industrialized nations such as Japan and awaits further CDM details. A project that can be shown to be profitable and reduce greenhouse gases has a good chance of being accepted.

Project partner PCS hopes that an improved energy consumption rate will boost productivity and make its products more cost competitive. The company has shown notable willingness to work toward implementation alongside the Japanese study team. Provided that the project is deemed economically viable, a full-scale study of the project is likely to begin as part of the process of working toward future implementation.

The specific nature of the CDM system has yet to be finalized at this time, and there are no guidelines for quantitative measurement of reductions. But progress is expected in these areas at the next COP meeting; once the details of CDM are finalized, there will be much room for discussions between Japan and Singapore.

The above represents the background leading up to the study of potential energy savings in PCS’s Complex I cracker. The study found that the project has the potential to reduce emissions of the greenhouse gas carbon dioxide by as much as 150,000 tons per year. The greenhouse gas reductions would be achieved in three areas: more efficient heat recovery in the propylene system using pinch technology; applying of an Advanced Recovery System (from S&W) to reduce the power load on the refrigeration system; and installation of a new co-generation system using gas turbine generator to improve energy recovery.

-7-1- The government of Singapore has expressed great enthusiasm on issues such as environmental conservation and restoration. Rationalization of energy-saving strategies to reduce fuel consumption, and in turn reduce carbon dioxide emissions —is an important goal of the Government, and should lead to sustained economic growth and help tackle the threat of global warming. For this reason, the Singapore government is most interested in Japanese energy conservation technologies and their application to reduce carbon dioxide emissions. The project is likely to be accepted if it can be demonstrated that it will contribute to both technological advancement and economic growth.

We would like to extend our heartfelt gratitude to the staff of PCS in Singapore and to officials from Ministry of the Environment, Singapore, for providing us with documents and materials, as well as advice on operating conditions and detailed explanations of facilities. We are also grateful for their faithful attendance at meetings related to the study. It is our sincere wish that at some time in the very near future, the energy conservation project will be implemented at PCS’s Complex I via a Clean Development Mechanism.

-7-2- References

The following list is main publications and literatures, which we referred to compete this report. We would like to express our gratitude to authors.

1. Business Guide Singapore, JETRO 2. Petrochemical Industries in Asia 1999, Jukagaku Kogyo Tsushinnsha 3. Petroleum and Petrochemical Industries in East Asia 1997, Tozai Boeki Tsushinsha 4. Business Times/Singapore, Nov. 13, 1999 5. European Chemical News, July 31, 2000 6. Yearbook of Statistics Singapore 1997 7. Monthly Digest of Statistics Singapore, March 1998 8. Singapore Trade Statistics (import and Exports) , 1994, Trade Development Board 9. Monthly Digest of Statistics (March 1995), Department of Statistics 10. Annual Report of the Public Utilities Board (1994) 11. Annual Report of Public Utilities Board (1994) 12. (Technology and Characteristic of Ethylene PlantJ (Piping Technology, Jan. ’98) 13. rCurrent and Future Ethylene Plant] (Piping Technology, Jan. ’98) 14. fRetrofit your ethylene unit] (Hydrocarbon Processing, March ’98) 15. rS&W Process] (Chemical Equipment, Oct.’90) 16. rGas Turbine Cogeneration in a Refinery] (Petro-tech, Oct. ’00) 17. rCogeneration Technology of Waste Heat Recovery] (Chemical Engineering, Dec.’98) Attachment

(1) First-stage study

1) Material to explain the study objectives and schedule for the Singaporean side 2) Materia] to explain cogeneration with a gas turbine generator

(2) Second-stage study

1) Material to explain cogeneration with a gas turbine generator 2) Materia] to explain heat recovery improvement plans based on pinch technology

(3) Third-stage study

1) Material to explain cogeneration with a gas turbine generator 2) Material to explain heat recovery improvement plans based on pinch technology PMJ Contents i ....—

1. Objectives of the Study

2. Work Procedure Material

to

3. Overall Schedule explain

the

4. Study Content study

objectives

5. Question and Answer and

schedule

for

the

Singaporean

side JGC 1. Objectives of the Study

• Identification of the potential of C02 emission reduction • Targeting the scope of modification

on some Facilities in PCS Plant PMil 2. Work Procedure (1/2)

Process Pinch Utility Analysis Analysis ARS study

Optimized Heat Recovery Process Flow Scheme JGC 2. Work Procedure (2/2)

Optimized Heat Recovery Process Flow Scheme

Project Manager Modification and •Scope of modification Equipment •Investment cost estimation Outline Design

Operating Performance •C02 Emission •Profitability JGC 3. Overall Schedule

year • month 2000 2000 2000 2000 2000 2001 2001 2001

work Sep. Oct. Nov. Dec. Jan. Feb. Mar.

a) Meeting at Site b) Data Gathering c) Process Simulation d) Pinch Analysis e) Process Study f) Utility Analysis g) Project Identification h) Report Preparation JGC 4. Study Content c

(T) Process Pinch Analysis (2) Effect of ARS for existing plant (3) Effect of Ceramic Coating for Furnace (4) Utility Analysis JGC 4. Study Content

CD Process Pinch Analysis Identification of Energy Saving Potential • Thermal Pinch Analysis

• Optimization of Distillation Column Operating Conditions • Optimization of Refrigerant Level • Optimization of QW Network dec 4. Study Content

(2) Effect of ARS for existing plant (1/2) ARS contributes to reduce refrigeration load by 25% (typical) over a conventional design. JGC simulates ARS effect for existing plant without SWEC’s Basic Design. ARS operation data of PCS-2 is a reference for above simulation. ilGC 4. Study Content

(2) Effect of ARS for existing plant (2/2) Typical cold fractionation revamp scheme

>► Hydrogen

Dephlegmator Dephlegmator ^ Methane

No. 1 No.2

i k 4

Cold Cracked Gas Demethanizer

*■ Hot

Demethanizer __ > >> Acetylene Recovery

^ Unit

Condensate Stripper Bottom >

> Deethanizer New equipment are shown

C3+ CUT by red line ◄------4. Study Content (D Effect of Ceramic Coating for furnace To be evaluated based on Sumitomo/Chiba operation data. Following operation data before and after application will be required (Process condition of before and after application shall be same as much as possible) • 02 % in Flue Gas • Fuel Consumption • Radiant Flue Gas Temperature •COT • Flue Gas Stack Temperature • Fuel Composition JGC 4. Study Content

® Utility Analysis Process Pinch Analysis will contribute energy conservation. Consequently, steam consumption will be reduced. I There may be a potential to optimize steam system in the Plant. JGC Gas Turbine Integration (1/3)

1. Estimated Configuratia

Cracking Furnaces F110 F180

Combustion Air Duct Material

Back-up FDF to

Back-up Stack explain

cogeneration

with

a

gas

turbine New GTG JGC Gas Turbine Integration (2/3) 2. Energy Conservation

Floor Burner : 40% of Total Burners Flue Gas from GTG : 540 °C

1

7% Reduction of Fuel Gas Consumption EH3 Gas Turbine Integration (3/3) i ...... — . ... - . . —~ czz , ...... —...... - ... — .... . - ..- ...... — 3. Expected Modification for Gas Turbine Integration 3-1 Burner Floor Burner O —» Replace Wall Burner x —> Not Practical 3-2 IDF Replace (cable replace included) 3-3 Duct Size Approx. 3,000D (20MW GT) 3-4 Back-up FDF & Stack

3-5 Radiant/Convection Section Revamp —* No ? 3-6 De-NOX —» No Need (Max. 300mg/Nm3)

3-7 De-SOX —* No Need (Low Sulfur Fuel) 3-8 Plot Area for New GTG (Approx. 20 mL x 5mw x 5mH) —► Need to site survey 4. Study Procedure GTG with HRSG Configuration

60°C. LHV 9.788kcal/kg Fuel Gas 54°C, 2.5K/G, LHV 12,151kcal/kg 1. Scope of work

♦ Investigation of potential of 002 emission reduction by reducing steam consumption - Steam Savings in Reboilers I - Convert Power in Compressor Savings J £T S’ r ♦ Study on heat recovery network to achieve the target ery

C02 emission reduction improvement

plans

based

on

pinch

R o o rra UGC 2. Summary

♦ Ethylene refrigeration power 7.0kW-Savings - optimization of C2 refrigerant placement

♦ Propylene refrigeration power 870~1,100kW-Savings - heat integration between demethanizer chilling and column reboilers ♦ SL consumption in Hot End 8.1ton/hr-Savings (maximum) - proper use of pan oil circuit and cracked gas heat

* study on heat recovery network has not been completed JGC 3. Pinch analysis - C2 Refrigerant

♦ Existing analysis • Existing DTmin is 1.5°C • Ethylene refrigeration systems has already been optimized • There is small potential of changing refrigerant levels between C2R-1 and C2R-2

♦ Targeting • Choose target DTmin is 1.5°C • The expected power saving is 7.0kW, too small JGC Pinch analysis - C3 Refrigerant

♦ Existing analysis • Existing DTmin is 3.5°C • Propylene refrigeration systems seems to be optimized from DTmin point of view • There is room to reduce refrigerant duties by optimization of heat recovery ♦ Targeting • Choose Target DTmin is 3.5°C • The matching between Cracked Gas and Column OVHD and Column Reboiler are good • The expected propylene power saving is range from 870 to 1,100kW 3. Pinch analysis - Cold End Summary

• In ethylene refrigerant, there is small potential to reduce compressor power

• In propylene refrigerant, the compressor power can be reduced by using Column OVHD and Cracked Gas to heat Column Reboiler [ ] 3. Pinch analysis - Hot End

♦ Existinganalysis • Existing DTmin is 12.6°C • Hot End also seems to be optimized from DTmin point of view • There is room to reduce LP steam consumption by utilizing Cracked Gas

♦ Targeting • Choose Target DTmin is 12.6°C • The maximum reduction of LP steam consumption is expected at 8.1 MMkcal/hr

♦ To achieve the target... • Optimization of heat recovery from Pan Oil Circuit • Optimization of BFW pre-heating network • Utilization of T-280 OVHD heat • Utilization of Cracked Gas heat «IGC Cogeneration with a Gas Turbine Generator

...... yy.^y, , r - -1 r i r ~ririrri nfiff~r~r*,~ri~*r~rnfrff J,'/' r r iTW'-'if• ^ *ftm ih" * * Ahwxxxfrtfn hum 20MW 20 MW 45MW 45MW Boiler B Boiler B Model A Model B Model A Model A 22-Sep-OO

Duct Firing I YES I YES I NO I YES I

Calculation Result Net Power Output kW 20,273 22,881 44,533 44,234 0 0 Heat to Steam kW ’ 53,780 53,876 55,202 92,272 49,309 55,388 Fuel LHV energy input kW 88,756 93,160 142,894 169,148 53,587 60,194 Thermal Efficiency % 83 82 70 81 92 92

Gas Turbine Summary Gross Power Output kW 21.650 24,420 47,123 47,124 0 0 Estimated transfer losses and plant auxiliaries kW 1,377 1.539 2,590 2,890 0 0 Net Power Output kW 20,273 22,881 44,533 44,234 0 0 RG LHV energy input kW 66,480 76,453 142,894 142,894 0 0 RG to Gas Turbine t/h 4.711 5.418 10.130 10.130 0 0

HRSG Summary Heat to Steam kW 53,780 53,876 55,202 92,272 49,309 55,388 SU Generation Rate t/h 69.90 70.02 71.74 119.90 70.00 78.63 Material HRSG Inlet Temperature °c 559 566 531 531 - Stack Temperature °c 170 170 236 170 185 185 RG LHV to duct burners kW 0 0 0 0 24,551 27,578

RG to duct burners t/h 0 0 0 0 1.824 2.049 to

HFO LHV to duct burners kW 22,276 16,707 0 26,254 29,036 32,616 explain HFO to duct burners t/h 1.96 1.47 0 2.31 2.47 2.78

Variable Cost for New GTG S$

RG 305.4 S$/t 1,439 1,655 3,094 3,094 557 626 cogeneration Fuel Oil 249.4 S$/t 489 367 0 576 617 693 BFW + Chemical 6.14 S$/t 433 434 445 744 434 494 Capacity Charge 0.014 S$/kW 303 342 660 660 0 0 Total 2.664 2.797 4.198 5.073 1,608 1.813

ith w Electric!tv S$/kWh 3,041 3,432 6.680 6,635

32,2 S$/t 1 -3.2 I 0 6 1 56.0 1 1,607 I a

SU Generation gas

I Boiler B Operation Cost 1,608 1,608 1,608 1,608 turbine

Gross Margin S$/h 1,982 2,244 4,146 4,777

8400 h 16.6MMSS 18.8MMSS 34.8MMS$ 40.1MMS$ generator Pinch analysis - Cold End Summary

• The ethylene refrigerant systems has already been optimized. Therefore, it is difficult to reduce

C2R compressor power further Material

to

explain • In propylene refrigerant, the compressor power

heat

can be reduced utilizing Column OVHD and recovery

Cracked Gas for distillation column reboiling improvement • The reduction of compressor power consumption

is expected to range from 6.4 to 8.1 ton/hr in SU plans

consumption. based JGC y <* s' Pinch analysis - 03 Refrigerant Modification Idea • INT-1: Use of Cracked Gas for Demethanizer Reboiling • INT-2: Use of Depropanizer OVHD for Ethylene Stripper Reboiling • INT-3: Use of Demethanizer Feed Chilling for Ethylene Rectifier Reboiling • INT-4: Heat integration are as follows; - Use of Demethanizer Feed Chilling for Ethylene Stripper/ Rectifier Reboiling - Use of Deethanizer OVHD for Ethylene Rectifier Reboiling • INT-5: Re-sequence of ethane product vaporizer on C3R systems Pinch analysis - Hot End

♦ Existing analysis • Revised BFW pre-heating data • Excluded Cracked Gas Stream • The existing DTmin is 12.6°C • Hot end has a potential to reduce SL consumption by utilizing Quench Water Heat

♦ Targeting • Choose Target DTmin is 12.6°C • The maximum potential of reducing SL consumption is expected at 8.9 MMkcal/hr Pinch analysis - Hot End

Modification Idea INT-1: Use of Quench Water-1 for Depropanizer Reboiling INT-2: Use of Quench Water-1 for Naphtha Pre-heating INT-3: Use of Pan Oil for Distillate Stripper Reboiling

Expected Energy Savings Reduction of SL consumption is expected at 5.3 MMkcal/hr This is equivalent to a reduction of 10.3 ton/hr in SL consumption mmm JGC PWWWWK Pinch analysis - Column analysis

• Deethan izer(T-430) Potential of increasing side-reboiling by approximately 1.0 MMkcal/hr ™> reduction of SL consumption • Ethylene Stripper/Rectifier(T-441/442) Potential of install of side-reboiling by approximately 1.2 MMkcal/hr —> produce cold heat source • Propylene Stripper/Rectifier(T-540/550) Potential of optimizing feed stage —> reduce vapor/liquid load in tower Any part or a whole of the report shall not be disclosed without prior consent of International Cooperation Center, NEDO.

Rhone 03 (3987) 9466

Fax 03 (3 987) 5103