PreFS Coal to DME FKIE Rev 3A

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PRE-FEASIBILITY STUDY REPORT FOR

COAL TO DME PLANT 775 000 Ton per Year

Cerenti District, Kuantan Singingi Regency of Riau Province, Sumatera Island, Indonesia

PT Fabrik Komponen Industri Energi October 2021

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Executive Summary

The Indonesian government has established a long-term vision to reduce its dependencies to imported energy source, particularly for LPG. LPG consumption in Indonesia is rapidly increasing due to its easiness to use by household. However, approximately 70% of LPG is imported. This import, along with heavily LPG subsidy, create burden to government expenditure and to overall economic.

By 2050, Indonesian government plans to blend DME to LPG to reduce the expenditure. The DME is planned to be produced from low-rank coal. Coal is abundant resource in Indonesia, but low rank coal is not attractive to be sold as direct energy source, nor other usage. This low rank coal can be converted to DME which has added value.

Indonesian government, through its national owned company, PT Bukit Asam already started Coal to DME plant as stimulant. However, based on the capacity, more plant needed to fulfill 2050’s target of DME blending. The government had prepared regulations to allow private sector to participate to produce DME from Coal.

PT FKIE (PT Fabrik Komponen Industri Energi) has coal concession area of low-rank coal in Cerenti district, Riau and planned to use it as DME plan raw material. The advantages of FKIE coal is low sulphur, low stripping ratio. These advantages contribute to low coal production price which is important factor.

Technology proposed in this study is two-step DME production with Methanol intermediate.

Methanol production is considered as value added as it can be sold instead of converted to DME when the DME price is low. Main production process of coal to DME are as following:

- Coal Gasification - Syngas Cleaning - Methanol Synthesis - DME Synthesis

The project will have positive impact for government and society, as the import expenses from government is reduced and more job opening are available.

This study has following conclusions:

- This project is considered to be feasible and attractive.

- This project is also attractive as it will have contribution to the society.

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Indonesia experienced fast economic growth since the economic depression in 2008. The GDP was increased from 95.4 billion USD at 1998 to 1.1 trillion USD at 2019. Despite the COVID-19 pandemic, Indonesia can manage the growth to rebound in Quarter 3 of 2020 (Fig. 1.2) and also projected to be recovered in 2022 (Table 1.1.). Indonesian Government and several independent institutions project the economic growth to be 5.486 billion USD (GDP at PPP) at 2030 and positioned as 5 biggest economic players in the world (The World in 2050, Price Waterhouse Cooper, February 2015).

Figure 1.1. Indonesia GDP 1998-2019

(https://data.worldbank.org/indicator/NY.GDP.MKTP.CD?end=2019&locations=ID-BN-MY-SG-TH- VN&start=1998&view=chart)

Table 1.1. Indonesia GDP Projection 2021-2022

(Indonesia Economic Prospects, The World Bank, December 2020)

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Figure 1.2. Indonesia GDP Rebound after Pandemic

(IMF Country Report No. 21/46, March 2021)

Along with economic growth, Indonesia population has increased from 237 billion at 2010 to 268 billion at 2019 (Statisik Indonesia 2020, BPS, 2020). Indonesian big population is a potential economic growth factor. Either as market or as player, the population growth will increase energy consumption in Indonesia.

1.2. Fuel Demand and Supply

Due to increasing economic activity and high population growth, energy consumption in Indonesia has increased significantly in recent year. Overall energy consumption in Indonesia can be observed in Figure 1.3 and 1.4.

Figure 1.3. Final Energy Consumption by Sector (included Biomass)

(Handbook of Energy and Economic Statistics of Indonesia 2019, Ministry of Energy and Mineral Resources, July 2020)

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Figure 1.4. Final Energy Consumption by Type

From the data, the highest direct energy consumption is for engine fuel, particularly for transportation. If we look further in final energy shares as shown in Table 1.2, we can see consistent increase for LPG consumption. the increase is average 0.27 % per year or 3.8 million BoE per year.

Table 1.2. Share of Final Energy Consumption by Type

(%) Year Coal Natural

Gas Fuel Biofuel Biogas LPG Electricity 2009 13.70 14.91 51.11 2.60 n.a 4.03 13.65 2010 20.55 13.00 43.94 4.17 n.a 4.79 13.55 2011 19.17 12.49 44.37 6.07 n.a 4.91 12.99 2012 15.05 11.91 47.53 7.24 n.a 5.24 13.03 2013 5.72 13.15 50.46 8.95 n.a 6.38 15.34 2014 7.23 12.77 47.68 9.55 n.a 6.81 15.96 2015 9.25 12.55 42.56 12.09 0.02 7.16 16.37 2016 8.62 10.49 44.59 10.67 0.02 7.67 17.94 2017 7.64 11.54 42.96 12.17 0.02 7.95 17.73 2018 11.57 11.01 36.92 14.99 0.02 7.42 18.07 2019 17.70 10.00 28.17 20.29 0.02 7.00 16.82 Note : Exclude biomass

This is following the conversion from kerosene to LPG for household consumption started 2006 (as per Surat Menteri ESDM No. 3249/26/MEM/2006). Due to increasing population and the practical use of LPG, the consumption soon increases beyond supply capability of Indonesia refineries (See Table 1.3). Thus, this demand is mostly supplied by LPG import as

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shown in Table 1.3. The import shares of LPG were increasing from 31.4% at 2009 to 73.6% at 2019.

Table 1.3. LPG Supply and Demand

(Ton) Year

Production

Export Import Sales Gas

Refinery Oil

Refinery Total

2009 1,430,671 694,547 2,125,218 88,463 917,171 2,922,080 2010 1,828,743 649,628 2,478,371 279 1,621,959 3,761,086 2011 1,580,598 704,842 2,285,439 76,566 1,991,774 4,347,465 2012 1,824,297 377,242 2,201,539 205 2,573,670 5,030,547 2013 1,447,055 563,935 2,010,990 286 3,299,808 5,607,430 2014 1,831,683 547,445 2,379,128 483 3,604,009 6,093,138 2015 1,631,599 675,808 2,307,407 408 4,237,499 6,376,990 2016 1,410,169 831,398 2,241,567 494 4,475,929 6,642,633 2017 1,162,575 865,366 2,027,941 372 5,461,934 7,190,871 2018 1,143,958 883,305 2,027,263 434 5,566,572 7,562,893 2019 1,140,297 821,697 1,961,994 457 5,714,693 7,765,541 (Handbook of Energy and Economic Statistics of Indonesia 2019, Ministry of Energy and Mineral Resources, July

2020)

Table 1.4. Domestic LPG Price

Year

LPG (3 Kg) LPG (12 Kg) LPG (50 Kg)

Thousand

Rp/BOE US$/ BOE Thousand

Rp/BOE US$/ BOE

2009 499 53 686 73 860 91

2010 499 55 686 76 863 96

2011 499 55 686 76 863 95

2012 499 52 686 71 1,316 136

2013 499 41 747 61 1,569 129

2014 499 40 1,211 97 1,548 124

2015 499 36 1,440 104 1,428 104

2016 499 37 1,361 101 1,247 93

2017 499 37 1,410 104 1,461 108

2018 499 36 1,457 104 1,612 115

2019 499 36 1,457 105 1,612 116

Domestic 3 kg LPG price is heavily subsidized as shown in Table 1.4. In 2019, Pertamina imported 5,844,919 Metric Ton of LPG with 2,720,135,191 USD valuation which is 465.38 USD/ton or 54.59 USD/BoE (https://pertamina.com/id/laporan-pengadaan-impor-periode- 2019, accessed April 2021). LPG 3 kg sales realization in 2018 is approximately 6.53 Metric Ton which is 86.34% of total LPG sales (Info Singkat , Vol XI, No. 12, Juni 2019, Puslit Badan Keahlian DPR-RI, http://berkas.dpr.go.id/puslit/files/info_singkat/Info%20Singkat-XI-12-II-P3DI-Juni-

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2019-213.pdf). Huge LPG 3 kg consumption which has lower price than the Imported LPG contract price makes burden to Indonesia Government budget to subsidize 3 kg LPG price.

1.3. Other Fuel Resources

Indonesia as a big country has vast natural resources that has big potential as an energy source. The distribution of other fuel resources in Indonesia can be referred to Table 1.5 to 1.7. However, the oil and gas proven reserves is quickly depleted in these 10 years. In contrast, the coal reserves still abundant can potentially being notable energy future for Indonesia.

Table 1.5. Indonesia Oil Reserves as December 2019

(Billion Barrel)

Year

Commercial Sub Commercial

Reserves Contingent Resources

Unrecoverable Proven Potential Low

Estimate Best+High Estimate

2009 4.30 3.70 - - -

2010 4.23 3.53 - - -

2011 4.04 3.69 - - -

2012 3.74 3.67 - - -

2013 3.69 3.86 - - -

2014 3.62 3.75 - - -

2015 3.60 3.70 - - -

2016 3.31 3.94 - - -

2017 3.17 4.36 - - -

2018 3.15 4.36 - - -

2019 2.48 1.29 0.33 0.38 3.03

Table 1.6. Indonesia Gas Reserves as December 2019

(Billion Barrel)

Year

Commercial Sub Commercial

Reserves Contingent Resources

Unrecoverable Proven Potential Low

Estimate

Best+High Estimate

2009 107.34 52.29 - - -

2010 108.40 48.74 - - -

2011 104.71 48.18 - - -

2012 103.35 47.35 - - -

2013 101.54 48.85 - - -

2014 100.26 49.04 - - -

2015 97.99 53.34 - - -

2016 101.22 42.84 - - -

2017 100.37 42.35 - - -

2018 96.06 39.49 - - -

2019 49.74 27.55 48.75 4.44 5.07

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1.4. Coal Reserve

Coal reserve in Indonesia is abundant which is suitable for replacing import dependency of fuel. Coal reserve in Indonesia is 37,604 million ton from several coal types as per December 2019 (Table 1.7). Currently, the production rate is at 616.16 Million Ton/year (Table 1.8).

Based on the data, the proven reserve of coal can last for approximately 61 years.

Table 1.7. Indonesia Coal Reserves as December 2019

(Million Ton)

Province Hypothetic Inferred Resources

Total Verified

Resources Reserves Verified Reserves Indicated Measured

Banten 5.47 32.92 17.18 5.99 61.55 12.69 0.23 0.23

Central Java 0.00 0.82 0.00 0.00 0.82 0.82 0.00 0.00

East Java 0.00 0.08 0.00 0.00 0.08 0.08 0.00 0.00

Aceh 0.00 326.68 465.57 346.90 1,139.16 1,071.00 553.00 546.15

North Sumatera 0.00 7.00 1.84 5.78 14.62 7.00 0.00 0.00

Riau 3.86 533.83 845.54 535.27 1,918.50 753.20 558.92 295.00

West Sumatera 1.19 152.40 85.46 270.31 509.36 271.54 110.27 44.64

Jambi 140.31 2,444.15 2,044.42 2,994.83 7,623.71 2,613.72 2,017.05 912.96

Bengkulu 0.00 205.51 227.83 195.55 628.90 68.79 155.11 25.46

South Sumatera 3,099.45 14,499.31 13,961.08 12,634.23 44,194.07 33,748.93 9,454.16 8,460.80

Lampung 0.00 122.95 19.95 9.00 151.90 106.95 0.00 0.00

West Kalimantan 2.26 375.69 6.85 3.70 388.50 371.01 0.00 0.00

Central Kalimantan 22.54 4,899.41 3,008.73 2,899.14 10,829.83 3,808.39 2,418.15 913.23 South Kalimantan 0.00 5,424.83 4,432.12 7,551.53 17,408.48 12,248.16 4,874.71 3,386.82 East Kalimantan 872.99 14,888.60 21,080.48 23,299.45 60,141.52 30,829.95 15,803.82 9,543.93 North Kalimantan 25.79 1,215.49 1,041.54 1,497.47 3,780.30 2,272.16 1,656.26 939.48

West Sulawesi 11.46 16.00 0.78 0.16 28.41 13.11 1.80 1.80

South Sulawesi 10.66 17.86 10.32 3.86 42.70 24.56 1.16 0.00

Southeast Sulawesi 0.52 1.98 0.00 0.00 2.50 2.50 0.00 0.00

Central Sulawesi 0.64 0.00 0.00 0.00 0.64 0.64 0.00 0.00

North Maluku 8.22 0.00 0.00 0.00 8.22 8.22 0.00 0.00

West Papua 93.66 32.82 0.00 0.00 126.48 95.57 0.00 0.00

Papua 7.20 2.16 0.00 0.00 9.36 9.36 0.00 0.00

TOTAL 4,306.21 45,200.51 47,249.69 52,253.17 149,009.59 88,338,34 37,604.66 25,070.50 (Handbook of Energy and Economic Statistics of Indonesia 2019, Ministry of Energy and Mineral Resources, July 2020)

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Figure 1.5. Coal Reserve by Calorific Value Type

(http://psdg.bgl.esdm.go.id/index.php?option=com_content&view=article&id=1335:neracadancdanganbatubarai ndonesia&catid=36:kegiatan-pmg-&Itemid=610)

Table 1.8. Indonesia Coal Production

(Ton)

Year Production Export Import

2009 256,181,000 198,366,000 68,804 2010 275,164,196 208,000,000 55,230 2011 353,270,937 272,671,351 42,449 2012 386,077,357 304,051,216 77,786 2013 474,371,369 356,357,973 609,875 2014 458,096,707 381,972,830 2,442,319 2015 461,566,080 365,849,610 3,031,677 2016 456,197,775 331,128,438 4,113,764 2017 461,248,184 286,936,795 4,723,755 2018 557,772,940 356,394,687 5,468,706 2019 616,159,594 454,500,164 7,391,172

Despite its abundant reserve, currently coal usage in Indonesia is limited to electric power generating power plant (See Table 1.9). Throughout the history, coal can be converted to

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several products. Most notably, coal is converted through gasification process into synthetic gas. This synthetic gas can be used as intermediate product for another product, such as Fertilizer, Petrochemical, and others. Indonesia Government already plans to enhance Coal to be processed to several value-added product such as: Fuel, Synthetic Gas, Olefin, Urea, DME (Dimethyl Ether) and others. This plan can be seen in Figure 1.6 to 1.8.

Table 1.9. Indonesia Coal Domestic Consumption by Sector

(Ton) Year Total

Iron, Steel

&

Metallurgy

Power Plant

Cement, Textile, Fertilizer

Pulp &

Paper Briquette Others

2009 56,295,000 256,605 36,570,000 6,900,000 1,170,000 61,463 11,336,932 2010 67,180,051 335,000 34,410,000 6,308,000 1,742,000 34,543 24,350,508 2011 79,557,800 166,034 45,118,519 5,873,144 1,249,328 33,939 28,366,165 2012 82,142,862 289,371 52,815,519 6,640,000 2,670,701 36,383 19,690,889 2013 72,070,000 300,000 61,860,000 7,190,000 1,460,000 36,383 1,223,617 2014 76,180,001 298,000 63,054,000 7,187,400 1,458,170 15,623 4,166,808 2015 86,814,099 399,000 70,080,000 7,180,000 4,310,000 13,174 4,831,925 2016 90,550,000 390,000 75,400,000 10,540,000 4,190,000 30,000 0 2017 97,030,000 300,000 83,000,000 9,802,000 3,898,000 30,000 0 2018 115,080,000 1,750,000 91,140,000 19,030,000 3,150,000 10,000 0 2019 138,418,192 10,064,750 98,550,260 22,515,239 3,304,980 7,969 3,974,994 (Handbook of Energy and Economic Statistics of Indonesia 2019, Ministry of Energy and Mineral Resources, July 2020)

Figure 1.6. Coal Processing Scheme in Indonesia

(Booklet Peluang Investasi Batubara di Indonesia, Ministry of Energy and Mineral Resources, 2020, https://www.esdm.go.id/id/booklet/booklet-tambang-batubara-2020)

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Figure 1.7. Coal Processing Road Map in Indonesia

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Figure 1.8. Coal Gasification Industry Scheme in Indonesia

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2. Dimethyl Ether

2.1. Description

Dimethyl Ether (DME) is an organic compound with chemical formula CH3OCH3. DME is simplest ether which is non-toxic, colorless gas, and non-corrosive. Having vapor pressure of 0.6 MPa at 25 oC and normal boiling point at -25 oC, DME appears as gaseous phase at ambient condition. DME can be liquified under moderate pressure with physical and chemical properties similar to LPG (Semelsberger et al., 2006). It has no direct C-C bond, but rather direct C-H and C-O bonds and contains about 35 %w/w oxygen (Azizi et al., 2014). Based on these properties, the combustion of DME releases no SOx, soots with less NOx emissions compared to Diesel (Taupy, 2007). Combining these features with its high cetane number (higher cetane number corresponds to shorter ignition delays), DME can be used as an alternative for fuel transportation (Azizi et al., 2014).

Furthermore, though DME is a volatile organic compound (VOC), it is non-mutagenic, non- carcinogenic, non-teratogenic and non-toxic. This makes it a good aerosol propellant and refrigerant with zero potential to deplete the ozone layer (Semelsberger et al., 2006). DME can also be used as polishing agent, pesticide, anti-rust agent, a source of hydrogen used in fuel cells, as well as important intermediate for producing key chemicals (e.g. light olefins, dimethyl sulphate etc.). Moreover, it has a great cooking and heating potential just like LPG since they exhibit similar properties. These similarities mean that DME can be transported and stored in existing LPG infrastructures (Semelsberger et al., 2006).

Good et al. (1998) found that DME has a global warming potential of 0.3 (w.r.t. CO2) averaged over 100 years compared to 21 in 100 years of methane (see Table 3). Evidently, DME has a lower global warming potential compared to carbon dioxide, methane and dinitrogen oxide.

Based on this result, they concluded that DME is environmentally acceptable

The various properties listed above show that DME is a relatively clean energy source with great potential in the future. With a growing concern in climate change, oil supply and energy security, more adoption of DME in the future would play a central role in helping to solve these issues (Semelsberger et al., 2006).

2.2. Properties

The properties of Dimethyl Ether (DME) is summarized in Table 2.1. Several countries, such as South Korea, Japan and China has been establish DME quality standard as shown in Table 2.2.

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Table 2.1. Comparison of DME Properties to Commonly Used Fuels

(Current Status and Technical Development for Di-Methyl Ether as a New and Renewable Energy, Wonjun Cho†

and Seung-Soo Kim, J. Korean Ind. Eng. Chem., Vol. 20, No.4, August 2009)

Table 2.2. Comparison of DME Standard of Korea, Japan and China

(Current Status and Technical Development for Di-Methyl Ether as a New and Renewable Energy, Wonjun Cho†

and Seung-Soo Kim, J. Korean Ind. Eng. Chem., Vol. 20, No.4, August 2009)

2.3. Usage

DME as in description above have several properties advantages which made DME used widely. DME has a variety of applications:

- Use as a liquefied petroleum gas (LPG) substitute for cooking and heating. DME combustion produces very low NOx and CO emissions and no sulfur or soot emissions.

- Use as a chlorofluorocarbon (CFC) substitute for propellants in cosmetic- or paintaerosol cans (Ohno 2001).

- Use as a diesel substitute. DME has a high cetane number (55) and can be combusted in diesel-powered vehicles that have been retrofitted to run on DME or in purpose built engines.

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- Use as a precursor to dimethyl sulfate and acetic acid production - Use as a refrigerant.

- Use as a rocket propellant.

- Use as carrier for livestock insect sprays and foggers.

- Use as a solvent for extraction of organic compounds.

Before 1990, DME was only used as an aerosol propellant commercially and known as

“nonozone-layer depleting replacement for chlorofluorohydrocarbons” (Fleisch et al, 2012).

In recent times, DME is more considered as an alternative and/or additive fuel and covers a wide area of applications. It is now known for its different applications as a fuel for transportation, cooking and heating, and power generation (Erdener et al., 2011). DME has been used in limited amount to freeze meat and fish by direct immersion (Patty, 1963).

A schematic classification of DME usage is displayed in Figure 2.1 and it shows that currently DME is mainly used either as a fuel or chemical feedstocks. DME as a fuel is used for “a combustion fuel itself” and also “a feedstock for reforming”. The power generations, diesel engines, and some home devices are using DME as their combustion fuel.

Volvo and Nissan have developed heavy duty diesel engines modified to run on DME. Further, DME can be used to make Synthesis natural gas (SNG) as well as produce hydrogen for fuel cell electric vehicles (Japan DME forum, 2007; Marchionna, 2008).

The mixture of different pre-defined proportions of DME and LPG, which is called “synthetic LPG”, is applicable as a domestic cooking and heating fuel. Also, some power generation manufacturers like General Electric, Mitsubishi and Hitachi have approved DME as a fuel for their gas turbines (Basu et al, 2014).

Figure 2.1. Different Applications of DME

(Japan DME Forum, 2007)

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DME use as LPG substitution has been studied intensively in several countries such as in Korea (KOGAS DME Activities for Commercialization, November 2011), Indonesia (Boedoyo, M.S., Pemanfaatan DME Sebagai Substitusi BBM dan LPG, Jurnal Teknik Lingkungan, Vol 11, No. 2, Hal 301-311, Mei 2010 and Anggarani, R. et al, Review Perkembangan Teknologi Pemanfaatan DME sebagai Bahan Bakar, Scientific Contributions Oil and Gas, Vol 40, No. 1, April 2017).

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3. Market Demand and Supply

3.1. Dimethyl Ether

Dimethyl Ether (DME) market is mainly intended for domestic consumption in Indonesia. As mentioned in chapter 1, the LPG consumption in Indonesia is increasing rapidly. Meanwhile, most of LPG supply is imported from overseas. Only approximately 27% is supplied by domestic producer in Indonesia.

By 2019, the imported LPG is 5,714,693 ton annually. DME can be mixed up to 50% (Anggarani, R. et al, Review Perkembangan Teknologi Pemanfaatan DME sebagai Bahan Bakar, Scientific Contributions Oil and Gas, Vol 40, No. 1, April 2017). However as per indicated in Indonesia

Energy Outlook 2019 provided by Dewan Energy National

(https://www.esdm.go.id/assets/media/content/content-indonesia-energy-outlook-2019- english-version.pdf) the mixing ratio of DME to LPG will be limited to 20%. This regulation is mainly based on the study result that mention 20% mixing ratio does not require any change in the stove (Boedoyo, M.S., Pemanfaatan DME Sebagai Substitusi BBM dan LPG, Jurnal Teknik Lingkungan, Vol 11, No. 2, Hal 301-311, Mei 2010).

Figure 3.1. Indonesian Energy Outlook Scenario

(https://www.esdm.go.id/assets/media/content/content-indonesia-energy-outlook-2019-english-version.pdf)

Thus, the annual DME demand in 2019 is only 1,142,938 ton annually. However, based on Indonesia Energy Outlook 2019, the LPG consumption is increasing every year. In 2030, it is expected that the LPG consumption is reaching 9.7 million tons/year with government expectation that 4.5 million tons/year is supplied by DME substitution

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(https://www.spglobal.com/platts/en/market-insights/latest-news/oil/012221-indonesia- may-cut-reliance-on-lpg-imports-by-2030-on-dimethyl-ether-output-plans).

DME supply in Indonesia is currently imported. However, PT. Bukit Asam, a government company, is currently build Coal to DME plant near their mine, inside Kawasan Industri Tanjung Enim in South Sumatera. As per PT Bukit Asam official release, the plant will have capacity of 1.4 million tons DME per year from 6 million tons coal per year (https://www.ptba.co.id/uploads/ptba_siaran_pers/gasifikasi-batu-bara-ptba-jadi-proyek- strategis-nasional.pdf). The investment cost for this plant is USD 2.1 million.

Considering regional supply of DME, South Korea, Iran, China and Japan are main producer of DME in the world (https://www.mordorintelligence.com/industry-reports/dimethyl-ether- market, retrieved 30 Sep 2021). In 2026, the market of DME is expected to be 5.9 million ton annually with almost of 75% of DME usage is for LPG blending in respective producing country.

China’s DME price is mostly used for benchmarking world DME price. In 10 years, the DME price is varied from about 2500 to 5000 CNY/ton (386 – 772 USD/ton) with average of 568 USD/ton (between 2018 – 2019). Bottom price of about 2500 CNY/ton as reached in 2016 is not expected in future as global demand is increasing. Thus, low price of 3000 CNY/ton (450 USD/ton) is assumed for lowest DME price in this study.

Figure 3.2. DME 10 years price

(https://www.ceicdata.com/en/china/china-petroleum--chemical-industry-association-petrochemical-price- organic-chemical-material/cn-market-price-monthly-avg-organic-chemical-material-dimethyl-ether-990-or-

above, retrieved 30 Sep 2021)

Since the DME will be used for LPG blending, DME base price shall consider LPG price in Indonesia. LPG contract realization from Saudi Aramco is 570 USD/ton and government assumption in APBN is 379 USD/ton. (https://www.cnbcindonesia.com/news/

20210531191406-4-249687/subsidi-lpg-tembus-rp-20-t-melesat-66-dari-kuota-kok-bisa).

Thus, base price for this study is assumed 10% lower than LPG contract realization price, 513 USD/ton. For bottom price, APBN assumption is used in this study.

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3.2. Methanol

The proposed DME plant produce methanol as its intermediate in converting coal to DME.

Thus, methanol can be optionally considered as product that can improve revenue by partially sell methanol instead of DME. Methanol is raw material required by several petrochemical industry to produce several products such as ethylene and propylene.

Methanol market size in 2020 is about 83.3 million tons annually (https://www.mordorintelligence.com/industry-reports/methanol-market, retrieved 30 Sep 2021). Its market value is still expected to increase by about 30% from 20.4 billion USD in 2020 to 26.6 billion USD in 2026 (https://www.marketsandmarkets.com/Market- Reports/methanol-market-425.html, retrieved 30 Sep 2021). Some of main methanol producers are Methanex Corporation, SABIC, and others 6 producer that supply about of 40%

global demand.

In Indonesia, Methanol demands is about 1.5 million tons/year in 2021 with only domestic capacity of 0.66 million tons/year (https://cci-indonesia.com/product/industry-marketing- prospect-methanol-indonesia/, retrieved 30 Sep 2021). Domestic supply is mostly supplied by PT. Kaltim Methanol Industry. Thus, most of methanol need is still fulfilled by imported methanol.

Methanol contract price from Methanex Corporation for Asia Pacific region in September 2021 is 460 USD/ton (https://www.methanex.com/sites/default/files/Mx-Price-Sheet%20-

%20Aug%2031%202021.pdf, retrieved 30 Sep 2021). Meanwhile, Methanol Institute provides methanol price data from several source. Bottom price for methanol is 200 – 400 USD/ton for CFR China main ports.

Figure 3.3. Methanol 3 Years Price

(https://www.methanol.org/methanol-price-supply-demand/, retrieved, 30 Sep 2021)

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4. Process Technology

DME can be produced in two different ways using any methane containing feedstock e.g.

natural gas, coal, oil, biomass etc. The first method which is the most popular at the moment is the indirect DME synthesis method. This method first converts the raw material (e.g. natural gas) to syngas (a mixture of hydrogen and carbon monoxide). In the presence of a catalyst, the syngas is converted to methanol – this is a very mature technology of methanol production. The obtained methanol is then dehydrated to get DME in the presence of another catalyst. The method is indirect because it is a two-step process involving first the production of methanol and then, DME. The second method is the direct DME synthesis method. Using this method, DME is produced from syngas directly without the intermediary step of methanol production. The method increases the conversion rate of syngas to DME better than what is obtained using the indirect method (The University of California, 2015). The DME cost is also lower using this method because of a simpler reactor design. This method, however, is more complex than the conventional indirect method making it, as yet, not suitable for commercial purposes (Azizi et al., 2014). In recent years, however, there have been great progress towards making the method fit for commercial purposes. An example is the successful 100 ton/day commercial DME demonstration plant in Japan (Ogawa et al., 2003). Figure 3 shows a schematic of both methods.

4.1. Dimethyl Ether Indirect Method

The reactions for the commercial production of DME are shown below. Eq. (1) shows the production of methanol from syngas and Eq. (2) the dehydration of methanol to DME.

2𝐶𝑂 + 4𝐻2 → 2𝐶𝐻3𝑂𝐻 (1) 2𝐶𝐻3𝑂𝐻 → 𝐶𝐻3𝑂𝐶𝐻3 + 𝐻2𝑂 (2)

Figure 4.1. DME Production Schematic

Syngas is mainly produced from natural gas and coal. Using biomass as a feedstock is also becoming popular (Figure 3). Syngas production has a great impact on the price of methanol and thus, the price of DME. This is because generating the syngas accounts for more than 50%

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of the total investment in a methanol plant using natural gas as the raw material. This is higher for coal, where the investment for syngas generation accounts for 70-80% of total investment (Olah et al., 2009).

4.2. Dimethyl Ether Production from Coal

DME can also be produced from coal. This method of production is very popular in China, where there are large coal deposits and producing a clean fuel such as DME from coal can play a big role in meeting the country’s energy needs with minimal negative impact on the environment (Japan DME Forum, 2011). Similar to natural gas, coal has to be first converted to syngas and then to methanol. Coal gasification is used to produce syngas from coal. There are different coal gasification designs, which are mainly dependent on the type of coal being used (Olah et al., 2009). The gasification process combines partial oxidation and steam treatment. The equations below illustrates the process (Olah et al., 2009) i.e.:

𝐶 + 0.5𝑂2 ↔ 𝐶𝑂, (3)

𝐶 + 𝐻2𝑂 ↔ 𝐶𝑂 + 𝐻2, (4) 𝐶𝑂 + 𝐻2𝑂 ↔ 𝐶𝑂2 + 𝐻2, (5)

𝐶𝑂2 + 𝐶 ↔ 2𝐶𝑂. (6)

Equations. (3), (4), (5) and (6) show the different reactions in the coal gasification process. The process involves first coal gasification, followed by coal purification. After this step, the composition of the gas is adjusted to the desired composition for methanol synthesis. The H2/CO ratio of coal is lower than one (typically between 0.5 and 0.7), which is not desired for methanol synthesis. This is because the syngas is usually rich in CO and CO2 with a little amount of hydrogen. Therefore, to increase the amount of hydrogen, the syngas is subjected to a WGS (water gas shift) reaction. The produced CO2 is removed to the required level suitable for DME synthesis (Japan DME Forum, 2011). H2S is also removed to prevent poisoning of catalysts (Olah et al., 2009). Figure 4.2 shows the whole process for both direct and indirect DME synthesis.

Figure 4.2. DME from Coal Production Schematic

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5. Process Configuration

DME plant used in this project is as following configuration:

Figure 5.1. DME from Coal Process Flowchart

This project planned to produce 100% DME. However, if required, some methanol production can be sold directly without necessity to produce DME. It can be summarized as following:

A. Product Plan A:

o 100% DME B. Product Plan B:

o DME

o Up to 50% Methanol

Sulfur Recovery

Water Gas Shift Syngas Cleaning Air Separation Unit

Methanol Plant

DME Plant Coal Gasification

CO2 Recovery Coal Preparation

H2S, CO2 Raw Syngas

Clean Syngas

H2 Rich Syngas

Methanol

DME

Sulfur

CO2 Oxygen

Coal Slurry Coal, Water

Air

Steam

Product Plan A

Product Plan B

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6. FKIE Coal Reserve and Configuration

PT. Fabrik Komponen Industri Energi (PT. FKIE) holds the Mining Business License (IUP Operation Production over a concession in Cerenti District, Kuantan Singingi Regency of Riau Province, Sumatera Island, Indonesia. PT. FKIE plans to develop the Coal Concession with an aim to supply coal to its proposed pit head Dimethyl Ether plant.

Total Concession owned by PT FKIE Indonesia Jakarta with Total area 9.822 Ha in Cerenti Riau Sumatra Licency issued by GOI/ October 2014, JORC by German Consultant DMT done in 2003 -2014 in 1.000 Ha, with 60 M MT proven reserve on 869 Ha with S/R 3-7 Meters on 2 seems A and B, close to River Batang Kuantan/ River Inhu Riau Province.

FKIE owned IUP Operasi Produksi of 9822 Ha for 20 years approved by Bupati of Kuantan Singingi in October 2014, No. Kpts. 434.a/X/2014. Located in Cerenti District of Kuantan Singingi Regency, Riau Province. Focus area of JORC Exploration in 869 Ha.

Figure 6.1. FKIE Coal Concession Area

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The FKIE coal concession location is ideal for building Coal to DME plant. Particularly, the following main factor is present:

a. The location is near Indragiri River which can be used for water source and as transportation mean.

b. The location is inside coal mine, thus there is no necessity to transport the coal. The mine is also shallow mine type with only maximum of 10 meter of excavation.

c. The location is still far from villages.

Figure 6.1. FKIE Coal Detailed Mining Area

FKIE’s coal quality is low calorie – low sulphur coal. This coal type is suitable to be converted to DME. The coal gross calorific value is approximately 2778 – 3115 kcal/kg (ARB) with total

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sulphur content of 0.29 – 0.38 % (ADB). The detail of coal data on FKIE reserve can be seen in Table 6.1 and 6.2.

Table 6.1. FKIE Coal Reserve

Table 6.1. FKIE Coal Quality

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7. Material Balance

This project material and heat balance can be summarized as following:

Table 7.1. Material Balance of DME Plant

INPUT OUTPUT

RAW MATERIAL QUANTITY (TPA) PRODUCTS QUANTITY (TPA)

Coal (Total) 3,218,088 DME 775,228

- Coal for Production 2,580,657

- Coal for Power 637,430 Intermediate:

- Methanol 1,069,377

Air 8,372,439

- Oxygen 1,722,107

Water

- For WGS 1,421,316

- For Other Make-up 2,892,853

Table 7.2. Energy Consumption of DME Plant

Plant Unit Consumption

ASU MW 88.9

Sizing MW 8.5

Gasifier MW 28.0

Cleaning and WGS MW 37.2

Methanol MW 25.9

DME MW 1.2

Other Utility MW 16.5

Total MW 206.2

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8. Process Plant

The DME production plant consists of following 4 process plants and common utility/ offsite system. The design capacity of the DME production is set at 97.9 tons/day.

A. Coal Gasification Plant

Coal gasification plant includes coal reduction equipment and slurry preparation process.

After coal is mixed with water as slurry, the slurry is fed to coal gasification reactor together with oxygen from Air Separation Unit to produce syn-gas. The syn-gas is then cleaned in Rectisol Unit to be freed from CO2 and sulphur. Heat generated in this gasification plant is utilized to produced steam which is used as feedstock of water-gas shift process.

B. Air Separation Unit

Coal gasification requires oxygen to produce syn-gas. Oxygen with approximately 94%

purity is generated by Air Separation Unit with cryogenic process. The oxygen is compressed to approximately 41 barg to match with gasification process pressure. This air separation unit is the most energy consumer in the plant (~ 43%) and contribute to

~45% of purchased main equipment cost. Thus, techno-economical optimum equipment selection is important.

C. Syn-gas Cleaning Unit (Rectisol) and Water-Gas Shift Unit

Syn-gas need to be cleaned to maintain optimum CO/CO2 ratio and remove Sulphur to maximize methanol production. Rectisol process is selected because of its advantages that can remove sulphur thoroughly. Since methanol is used as absorbent in this process, any make-up requirement can be easily taken from the product. However, since it is need refrigeration, good insulation and energy optimization shall be considered.

Cleaned syn-gas is then processed to water-gas shift unit to convert water to hydrogen gas which is used to maintain CO/H2 ratio which is also important to produce methanol.

Sulphur separated as H2S in Rectisol process is further processed in Sulphur Recovery Plant.

D. Methanol Plant

H2 and CO rich syngas from water-gas shift reactor is compressed to 24 barg and heated to about 240 C to allow conversion to methanol. Methanol produced is stored in intermediate tank before fed to DME plant. Recycle is important in the methanol

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production process to achieve optimum energy efficiency and conversion. If required, methanol can also be considered as main product to optimize economical revenue.

E. DME Plant

Methanol from DME plant is compressed to approximately 13 barg and heated to approximately 150 C to allow conversion to DME. Recycled quantity is also important in DME production process. DME product is then stored in product tank at about 12 barg.

F. Sulphur Recovery Plant

H2S recovered by Rectisol process is further recovered by Clauss process to obtain sulphur as by product.

G. Power Plant

This plant requires power plant of about 250 MW electricity with 2 x 125 MW configuration to supply 206 MW plant electricity requirement. The boiler shall also be able to produce addition 250 MW of steam to be used in process. This will allow the power plant to operate at about 82% capacity at plant maximum load. The powerplant proposed is CFB boiler which has high efficiency and reasonable investment cost compared to other type (such as IGCC powerplant).

This project also has utility system which is consisting of the following:

A. Cooling System and Chilled Water System

The cooling system for the plant will be a closed circuit of clean water, where clean water, passed through heat exchanger, taking heat, and being cooled by series of cooling tower.

Chilled water system is also required to provide cooling for condenser at several distillation column. Hot water and waste heat type chiller can be used to optimize the energy consumption.

B. Raw Water Treatment

The raw water will be taken from Indragiri River and some Deep Well to provide water supply of approximately 365 m3/hr clean make-up water to the system.

C. Wastewater Treatment

The effluent water will be discharged to the Indragiri River after being treated in the wastewater treatment unit to meet regulations.

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D. Steam Generation

Steam required for process will be generated by utilizing the waste heat of gasification process and partially from CFB Boiler.

E. Demin Water Treatment

Boiler feed water will be treated in a de-mineralized water treatment unit and sent to power plant unit for steam generation.

F. Instrument Air Generation

Instrument Air will be generated by air compression and dryer system for plant demand.

G. Nitrogen Supply

Nitrogen supply will be from air separation unit. Small storage tank is provided to cater any purging requirement for the plant.

H. Flare System

Flare system will flare off effluent gases.

I. Incinerator

Incinerator unit will be provided to incinerate effluent flammable liquids.

J. Tank Farm and Coal Yard

Product storage tank will be provided for both methanol and DME. 15 days of storage is expected for the DME, considering that the location is far from the off-taker facility. Coal Yard is still required to cater 10 days of storage. Short storage time is considered since the plant is at mine mouth.

K. Jetty and Loading Dock

Alternative for product shipment is through utilization Indragiri River. Thus, a jetty or loading dock is required. Barge capacity of 3000 kg might be used to transport out the DME.

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9. Economic Evaluation

The economic evaluation of the processes was based on the total annual cost, commonly used in the conceptual design of chemical processes. Foremost, the investment cost and economic profitability of completing the production of DME from coal were computed established on several price scenarios. The economic analysis calculates the internal rate of return (IRR), investment payback, the total cost of consumed feed, and total net sales.

The economic analysis output such as:

A. Estimation of fixed capital cost and working capital cost, B. Annual manufacturing cost,

C. Estimation of annual depreciation,

D. Determination of profits and losses of project, E. Internal rate of return (IRR),

F. Determination of rate and period of investment payback, and G. Sensitivity analysis.

Input data for calculations such as current unit costs and unit fixed investment costs were gathered from several sources. The cost data is corrected to present time by using CEP Index.

After that, sensitivity analysis based on economic indicators such as internal rate of return (IRR) and investment payback, the total cost of feed consumed, and total net sales for the plant was calculated.

9.1. Assumptions

9.1.1 Annual Production Volume

The DME production capacity is assumed 2349 tons per day. Periodical turnaround is 35 days annual basis and operation days is 330 days, resulting in annual production volume of 775 228 tons. The plant intermediate is methanol which the annual production is 1 069 377 tons per year. This methanol production is wholly used to produce DME. Product variation of DME and Methanol is exercised during sensitivity analysis.

9.1.2 Marketing and Sales Price

The entire sales destination of DME is assumed to be for LPG blending performed by PT Pertamina in Indonesia. Meanwhile, if Methanol production is observed, the sales destination will be in East Asia including Domestic market in Indonesia and to China, Japan, South Korea and Taiwan.

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As discussed in chapter 3, the China’s DME price is used for benchmarking world DME price.

In 10 years, the DME price is varied from about 2500 to 5000 CNY/ton (386 – 772 USD/ton) with average of 568 USD/ton (between 2018 – 2019). Bottom price of about 2500 CNY/ton as reached in 2016 is not expected in future as global demand is increasing. Thus, bottom price of 3000 CNY/ton (450 USD/ton) is assumed for lowest DME price in this study. Normal price for DME is considered as 513 USD/ton and 550 USD/ton is considered as high case. Additional bottom low price of 379 USD/ton is also observed. This is to understand the impact when the lowest price in last 10 years is incidentally occurred.

Figure 9.1. DME 10 years price

(https://www.ceicdata.com/en/china/china-petroleum--chemical-industry-association-petrochemical-price- organic-chemical-material/cn-market-price-monthly-avg-organic-chemical-material-dimethyl-ether-990-or-

above, retrieved 30 Sep 2021)

For methanol, as discussed in chapter 3, methanol price also refers to China’s CFR price.

Bottom price for methanol is 200-400 USD/ton for CFR China main ports. For project evaluation, methanol price is assumed at 400 USD/ton.

9.1.3 Sales Cost

The Project Company sells the product to offtakers and they take the market risk of sales volume. As a compensation for that risk, the Project Company pays offtakers sales commission. Sales commission is assumed 2% of sales value predicted.

9.1.4 Raw Material (Coal) Cost

The coal price assumed in this project is 25 USD/ton. This low coal price is considered as the coal source is in the vicinity of the plant. As per discussed in chapter 6, the mine is shallow with stripping ration of 1:6.9. This will be major advantages for the plant economic analysis.

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Similar project performed by PT Bukit Asam indicates that the assumption of coal price is about 21 USD/ton. Thus, it is assumed that the coal price low case is at 20 USD/ton.

Meanwhile, high case of coal price is at 30 USD/ton.

9.1.5 Labor Cost

This project is assumed that labor cost is about 244 persons which is combined between direct and indirect labor, excluding managerial and top-level management. Additional supervision cost is added to cover the expense of managerial and top-level management which is assumed to be 25% of labor cost.

9.1.6 Maintenance Cost

Due to complexity of the plant, annual maintenance cost is estimated at 4.0% of the plant cost. Additional plant supplies is assumed as 10% of maintenance cost.

9.1.7 Electricity Cost

Required volume of electricity is 206 MW it will be supplied by dedicated power generation unit. The electricity cost will be reflected by coal consumption cost.

9.1.8 Catalyst and Chemical Cost

Catalyst includes the ones for methanol synthesis, sulfur removal, reforming etc. Chemicals are the ones used for water treatment such as demineralized water unit and boiled feed water unit, and for wastewater treatment and waste disposal. From process estimation, annual cost all together is estimated at US$ 5.07 million.

9.1.9 Administrative Cost

This includes office rent, travelling, social welfare, consultant, audit etc. The annual cost of US$ 11.9 million is estimated.

9.1.10 Insurance Cost

The annual insurance cost is estimated at US$ 9.4 million.

9.1.11 Finance Cost

Finance cost is estimated at US$ 68.7 million, considering that 70% of fixed capital cost and working capital is from debt. 10% interest is applied for fixed capital cost debt and 10%

interest is applied for working capital debt.

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9.1.12 Working Capital

Working capital includes inventory, account receivable and payable, which is necessary for operation of the Project, and it is assumed as shown below.

Table 9.1. Assumption for Working Capital

Item Assumption

Inventory 15 days Against total production cost

Account receivable 10 days Against sales

Account payable 10 days Against coal cost

Under project finance, the Project is required to keep a certain amount of cash in the reserve account as restricted cash for the purpose of emergency case of cash shortfall. The reserve is assumed for 20 days of operation.

9.1.13 Tax

Corporate income tax is assumed 22% as per tax rate of Indonesia as per Undang-Undang Harmonisasi Peraturan Perpajakan which is signed in October 2021.

9.2. Total Project Cost

Total project cost is calculated from several sources and corrected to present value by utilizing CEP Cost Index. Several assumptions were made on transportation, installation, piping, instrumentation, electrical, insulation and development cost.

The total project cost includes plant cost and other expenditure during the construction period. Interest during construction (IDC), financial cost, development cost, other expenditure and contingency are considered for calculation of total project cost. Some of these expenditures are assumed capitalized even though there will be actual cash out.

The cost excluded Import Tax, VAT, Tarif and other taxes imposed in Indonesia

This study estimates the physical plant cost of US$ 746.3 million and the construction period of 36 months including procurement, construction, and commissioning, which is typical period of time for construction of a methanol plant. Other cost is estimated US$ 189.9 million (including contingency of 8% of Direct Plan Cost) and total project cost is assumed US$ 936.2 million. The breakdown of total project cost is shown in Table 9.2.

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Table 9.2. Total Project Cost at 100% DME Product Base Case

Product DME 100%

DME Production TPA 775,012

Methanol Production TPA -

Sulfur Production TPA 13,827

Coal Consumption

- DME Production TPA 2,581,920

- Power TPA 637,528

- Total TPA 3,219,448

Power Consumption MW 206

DME Price USD/ton 513.00

Methanol Price USD/ton 400.00

Sulfur Price USD/ton 40.00

Coal Price USD/ton 25.00

Fixed Capital Cost USD/anno 936,176,757 Manufacturing Cost USD/anno 203,326,999 Working Capital USD/anno 44,929,587 General Expense USD/anno 91,371,083

Total Sales USD/anno 398,134,017

9.3. Evaluation of Economics

Based on the assumptions as discussed, the economics of the Project is analyzed based on cash flow of 25 years operational period. The economics is evaluated based on project internal rate of return (Project IRR). The basis of calculation is based on free cash flow after tax.

Outcome of calculation for base case is as follows; Project IRR of 18.8%. The details is as per Table 9.3.

9.4. Sensitivity Analysis

Sensitivity analysis is conducted to evaluate impact of fluctuation of each variable. Following are selected as main variables and sensitivity of Project IRR is calculated.

A. Coal Price B. DME Price C. Tax

D. Product Variation Scenario

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Table 9.3. Economic Analysis Result

Product DME 100%

Lifetime years 25

Tax % 22

Profit Before Tax USD/anno 103,435,935 Profit After Tax USD/anno 80,680,029

ROI Before Tax % 11.0

ROI After Tax % 8.6

POT Before Tax years 6.6

POT After Tax years 7.9

BEP % Capacity 47.0

Shutdown Point % Capacity 20.6

IRR (After Tax) % 18.8

9.4.1 Increase and decrease of Coal Price

In this scenario, other variables remain unchanged.

Table 9.4. Sensitivity on Coal Price

Low Base High

Coal Price USD/ton 20.0 25.0 30.0

ROI Before Tax % 12.8 11.0 9.3

ROI After Tax % 10.0 8.6 7.3

POT Before Tax years 6.0 6.6 7.5

POT After Tax years 7.2 7.9 8.9

IRR (After Tax) % 20.2 18.8 17.4

9.4.2 Increase and decrease of DME price

Table 9.5. Sensitivity on DME Price

Bottom Low Mid Base High

DME Price USD/ton 379.0 400.0 450.0 513.0 550.0

ROI Before Tax % 0.8 2.4 6.2 11.0 13.9

ROI After Tax % 0.6 1.9 4.9 8.6 10.8

POT Before Tax years 20.9 15.7 9.8 6.6 5.6

POT After Tax years 21.7 17.1 11.3 7.9 6.7

IRR (After Tax) % 10.6 12.0 15.1 18.8 21.0

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9.4.3 Increase and decrease of Tax

Table 9.6. Sensitivity on Tax

Low Base High

Tax % 15.0 22.0 30.0

ROI Before Tax % 11.0 11.0 11.0

ROI After Tax % 9.4 8.6 7.7

POT Before Tax years 6.6 6.6 6.6

POT After Tax years 7.5 7.9 8.5

IRR (After Tax) % 19.6 18.8 17.9

9.4.4 Product Variation Scenario

Table 9.7. Sensitivity on Product Variation

Base Prod #1 Prod #2 Prod #3 Prod #4

Product -

DME 100%

Methanol 25%

Methanol 50%

Propylene 50%

M 25% P 25%

ROI Before Tax % 11.0 12.1 13.1 11.9 11.2

ROI After Tax % 8.6 9.4 10.2 9.3 8.8

POT Before Tax years 6.6 6.2 5.8 6.3 6.6

POT After Tax years 7.9 7.4 7.0 7.5 7.8

IRR (After Tax) % 18.8 19.6 20.4 19.5 19.0

Figure 9.2. Sensitivity Analysis: Product Variation

18.8 19.6 20.4 19.5 19.0

0.0 5.0 10.0 15.0 20.0 25.0

DME 100% Methanol

25% Methanol

50% Propylene

50% M 25% P 25%

%

Product

Sensitivity Analysis: Product Variation

ROI Before Tax % ROI After Tax % IRR (After Tax) %

PreFS Coal to DME FKIE Rev 3A

PRE-FEASIBILITY STUDY REPORT FOR

COAL TO DME PLANT 775 000 Ton per Year

Table of Contents

Sensitivity Analysis: Product Variation