June 2015
Coal Mine Methane
Country Profiles
Prepared by U.S. Environmental Protection Agency
Coalbed Methane Outreach Program
In support of the Global Methane Initiative
Global
Methane Initiative
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Disclaimer
The U.S. Environmental Protection Agency does not:
a) Make any warranty or representation, expressed or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this report, or
that the use of any apparatus, method, or process disclosed in this report may not
infringe upon privately owned rights; or
b) Assume any liability with respect to the use of, or damages resulting from the use
of, any information, apparatus, method, or process disclosed in this report
'Global
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Contents
Units of Conversions i
Executive Summary ii
Global Overview at a Glance ii
Introduction 1
Purpose of the Report 2
Organization of the Report 2
1 Argentina 4
1.1 Summary of Coal Industry 4
1.1.1 Role of Coal in Argentina 4
1.1.2 Stakeholders 5
1.1.3 Status of Coal and the Coal Mining Industry 6
1.2 Overview of CMM Emissions and Development Potential 6
1.2.1 CMM Emissions from Operating Mines 6
1.2.2 CMM Emissions from Abandoned Coal Mines 7
1.2.3 CBM from Virgin Coal Seams 7
1.3 Opportunities and Challenges to Greater CMM Recovery and Use 7
1.3.1 Market and Infrastructure Factors 7
1.3.2 Regulatory Information 9
1.4 Profiles of Individual Mines 9
1.5 References 10
2 Australia 12
2.1 Summary of Coal Industry 12
2.1.1 Role of Coal in Australia 12
2.1.2 Stakeholders 13
2.1.3 Status of Coal and the Coal Mining Industry 15
2.2 Overview of CMM Emissions and Development Potential 15
2.2.1 CMM Emissions from Operating Mines 16
2.2.2 CMM Emissions from Abandoned Coal Mines 17
2.2.3 CBM from Virgin Coal Seams 18
2.3 Opportunities and Challenges to Greater CMM Recovery and Use 19
2.3.1 Marketand Infrastructure Factors 21
2.3.2 Regulatory Information 22
2.4 Profiles of Individual Mines 23
2.5 References 24
3 Botswana 27
3.1 Summary of Coal Industry 27
3.1.1 Role of Coal in Botswana 27
3.1.2 Stakeholders 28
3.1.3 Status of Coal and the Coal Mining Industry 28
3.2 Overview of CMM Emissions and Development Potential 29
3.2.1 CMM Emissions from Operating Mines 29
3.2.2 CMM Emissions from Abandoned Coal Mines 29
3.2.3 CBM from Virgin Coal Seams 29
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Contents (continued)
3.3 Opportunities and Challenges to Greater CMM Recovery and Use 30
3.3.1 Market and Infrastructure Factors 31
3.3.2 Regulatory Information 31
3.4 Profiles of Individual Mines 32
3.5 References 32
4 Brazil 34
4.1 Summary of Coal Industry 34
4.1.1 Role of Coal in Brazil 34
4.1.2 Stakeholders 35
4.1.3 Status of Coal and the Coal Mining Industry 36
4.2 Overview of CMM Emissions and Development Potential 37
4.2.1 CMM Emissions from Operating Mines 37
4.2.2 CMM Emissions from Abandoned Coal Mines 38
4.2.3 CBM from Virgin Coal Seams 38
4.3 Opportunities and Challenges to Greater CMM Recovery and Use 38
4.3.1 Marketand Infrastructure Factors 38
4.3.2 Regulatory Information 39
4.4 Profiles of Individual Mines 39
4.5 References 39
5 Bulgaria 41
5.1 Summary of Coal Industry 41
5.1.1 Role of Coal in Bulgaria 41
5.1.2 Stakeholders 42
5.1.3 Status of Coal and the Coal Mining Industry 43
5.2 Overview of CMM Emissions and Development Potential 43
5.2.1 CMM Emissions from Operating Mines 44
5.2.2 CMM Emissions from Abandoned Coal Mines 44
5.2.3 CBM from Virgin Coal Seams 44
5.3 Opportunities and Challenges to Greater CMM Recovery and Use 44
5.3.1 Market and Infrastructure Factors 45
5.3.2 Regulatory Information 45
5.4 Profiles of Individual Mines 46
5.5 References 46
6 Canada 48
6.1 Summary of Coal Industry 48
6.1.1 Role of Coal in Canada 48
6.1.2 Stakeholders 49
6.1.3 Status of Coal and the Coal Mining Industry 50
6.2 Overview of CMM Emissions and Development Potential 53
6.2.1 CMM Emissions from Operating Mines 54
6.2.2 CMM Emissions from Abandoned Coal Mines 54
6.2.3 CBM from Virgin Coal Seams 54
6.4 Opportunities and Challenges to Greater CMM Recovery and Use 57
6.4.1 Market and Infrastructure factors 58
6.4.2 Regulatory Information 59
6.5 Profiles of Individual Mines 60
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Contents (continued)
6.6 References 60
7 China 63
7.1 Summary of Coal Industry 63
7.1.1 Role of Coal in China 63
7.1.2 Stakeholders 64
7.1.3 Status of Coal and the Coal Mining Industry 65
7.2 Overview of CMM Emissions and Development Potential 66
7.2.1 CMM Emissions from Operating Mines 66
7.2.2 CMM Emissions from Abandoned Coal Mines 68
7.2.3 CBM from Virgin Coal Seams 68
7.3 Opportunities and Challenges to Greater CMM Recovery and Use 70
7.3.1 Marketand Infrastructure Factors 73
7.3.2 Regulatory Information 75
7.4 Profiles of Individual Mines 77
7.5 References 77
8 Colombia 81
8.1 Summary of Coal Industry 81
8.1.1 Role of Coal in Colombia 81
8.1.2 Stakeholders 83
8.1.3 Status of Coal and the Coal Mining Industry 84
8.2 Overview of CMM Emissions and Development Potential 85
8.2.1 CMM Emissions from Operating Mines 85
8.2.2 CMM Emissions from Abandoned Coal Mines 86
8.2.3 CBM from Virgin Coal Seams 86
8.3 Opportunities and Challenges to Greater CMM Recovery and Use 86
8.3.1 Marketand Infrastructure Factors 87
8.3.2 Regulatory Information 87
8.4 Profiles of Individual Mines 88
8.5 References 88
9 Czech Republic 90
9.1 Summary of Coal Industry 90
9.1.1 Role of Coal in the Czech Republic 90
9.1.2 Stakeholders 91
9.1.3 Status of Coal and the Coal Mining Industry 92
9.2 Overview of CMM Emissions and Development Potential 92
9.2.1 CMM Emissions from Operating Mines 93
9.2.2 CMM Emissions from Abandoned Coal Mines 93
9.2.3 CBM from Virgin Coal Seams 94
9.3 Opportunities and Challenges to Greater CMM Recovery and Use 94
9.3.1 Market and Infrastructure Factors 95
9.3.2 Regulatory Information 96
9.4 Profiles of Individual Mines 96
9.5 References 96
10 Ecuador 98
10.1 Summary of Coal Industry 98
10.1.1 Role of Coal in Ecuador 98
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10.1.2 Stakeholders 99
10.1.3 Status of Coal and the Coal Mining Industry 100
10.2 Overview of CMM Emissions and Development Potential 100
10.2.1 CMM Emissions from Operating Mines 100
10.2.2 CMM Emissions from Abandoned Coal Mines 100
10.2.3 CBM from Virgin Coal Seams 100
10.3 Opportunities and Challenges to Greater CMM Recovery and Use 100
10.3.1 Market and Infrastructure Factors 101
10.3.2 Regulatory Information 101
10.4 Profiles of Individual Mines 101
10.5 References 101
11 Finland 103
11.1 Summary of Coal Industry 103
11.1.1 Role of Coal in Finland 103
11.1.2 Stakeholders 104
11.1.3 Status of Coal and the Coal Mining Industry 104
11.2 Overview of CMM Emissions and Development Potential 104
11.2.1 CMM Emissions from Operating Mines 104
11.2.2 CMM Emissions from Abandoned Coal Mines 104
11.2.3 CBM from Virgin Coal Seams 105
11.3 Opportunities and Challenges to Greater CMM Recovery and Use 105
11.3.1 Market and Infrastructure Factors 105
11.3.2 Regulatory Information 105
11.4 Profiles of Individual Mines 105
11.5 References 106
12 France 107
12.1 Summary of Coal Industry 107
12.1.1 Role of Coal in France 107
12.1.2 Stakeholders 107
12.1.3 Status of Coal and the Coal Mining Industry 108
12.2 Overview of CMM Emissions and Development Potential 108
12.2.1 CMM Emissions from Operating Mines 108
12.2.2 CMM Emissions from Abandoned Coal Mines 108
12.2.3 CBM from Virgin Coal Seams 109
12.3 Opportunities and Challenges to Greater CMM Recovery and Use 109
12.3.1 Market and Infrastructure Factors 110
12.3.2 Regulatory Information 110
12.4 Profiles of Individual Mines 110
12.5 References Ill
13 Georgia 112
13.1 Summary of Coal Industry 112
13.1.1 Role of Coal in Georgia 112
13.1.2 Stakeholders 113
13.1.3 Status of Coal and the Coal Mining industry 113
13.2 Overview of CMM Emissions and Development Potential 114
13.2.1 CMM Emissions from Operating Mines 114
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13.2.2 CMM Emissions from Abandoned Coal Mines 115
13.2.3 CBM from Virgin Coal Seams 115
13.3 Opportunities and Challenges to Greater CMM Recovery and Use 115
13.3.1 Market and Infrastructure Factors 116
13.3.2 Regulatory Information 116
13.4 Profile of Individual Mines 116
13.5 References 117
14 Germany 119
14.1 Summary of Coal Industry 119
14.1.1 Role of Coal in Germany 119
14.1.2 Stakeholders 120
14.1.3 Status of Coal and the Coal Mining Industry 121
14.2 Overview of CMM Emissions and Development Potential 122
14.2.1 CMM Emissions from Operating Mines 122
14.2.2 CMM Emissions from Abandoned Coal Mines 122
14.2.3 CBM from Virgin Coal Seams 123
14.3 Opportunities and Challenges to Greater CMM Recovery and Use 123
14.3.1 Market and Infrastructure Factors 124
14.3.2 Regulatory Information 124
14.4 Profiles of Individual Mines 125
14.5 References 126
15 Hungary 128
15.1 Summary of Coal Industry 128
15.1.1 Role of Coal in Hungary 128
15.1.2 Stakeholders 129
15.1.3 Status of Coal and the Coal Mining Industry 130
15.2 Overview of CMM Emissions, Projects, and Potential 130
15.2.1 CMM Emissions from Operating Mines 130
15.2.2 CMM Emissions from Abandoned Coal Mines 130
15.2.3 CBM from Virgin Coal Seams 130
15.3 Opportunities and Challenges to Greater CMM Recovery and Use 131
15.3.1 Market and Infrastructure Factors 131
15.3.2 Regulatory Information 132
15.4 Profiles of Individual Mines 132
15.5 References 132
16 India 134
16.1 Summary of Coal Industry 134
16.1.1 Role of Coal in India 134
16.1.2 Stakeholders 136
16.1.3 Status of Coal and the Coal Mining Industry 137
16.2 Overview of CMM Emissions and Development Potential 138
16.2.1 CMM Emissions from Operating Mines 138
16.2.2 CMM Emissions from Abandoned Coal Mines 139
16.2.3 CBM from Virgin Coal Seams 139
16.3 Opportunities and Challenges to Greater CMM Recovery and Use 141
16.3.1 Market and Infrastructure Factors 141
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Contents (continued)
16.3.2 Regulatory Information 142
16.4 Profiles of Individual Mines 143
16.5 References 144
17 Indonesia 146
17.1 Summary of Coal Industry 146
17.1.1 Role of Coal in Indonesia 146
17.1.2 Stakeholders 148
17.1.3 Status of Coal and the Coal Mining Industry 149
17.2 Overview of CMM Emissions and Development Potential 150
17.2.1 CMM Emissions from Operating Mines 150
17.2.2 CMM Emissions from Abandoned Coal Mines 150
17.2.3 CBM from Virgin Coal Seams 150
17.3 Opportunities and Challenges to Greater CMM Recovery and Use 152
17.3.1 Market and Infrastructure Factors 152
17.3.2 Regulatory Information 152
17.4 Profiles of Individual Mines 153
17.5 References 153
18 Italy 155
18.1 Summary of Coal Industry 155
18.1.1 Role of Coal in Italy 155
18.1.2 Stakeholders 156
18.1.3 Status of Coal and the Coal Mining Industry 156
18.2 Overview of CMM Emissions and Development Potential 157
18.2.1 CMM Emissions from Operating Mines 157
18.2.2 CMM Emissions from Abandoned Coal Mines 157
18.2.3 CBM from Virgin Coal Seams 157
18.3 Opportunities and Challenges to Greater CMM Recovery and Use 158
18.3.1 Market and Infrastructure Factors 159
18.3.2 Regulatory Information 159
18.4 Profiles of Individual Mines 160
18.5 References 160
19 Japan 162
19.1 Summary of Coal Industry 162
19.1.1 Role of Coal in Japan 162
19.1.2 Stakeholders 162
19.1.3 Status of Coal and the Coal Mining Industry 163
19.2 Overview of CMM Emissions and Development Potential 164
19.2.1 CMM Emissions from Operating Mines 164
19.2.2 CMM Emissions from Abandoned Coal Mines 164
19.2.3 CBM from Virgin Coal Seams 164
19.3 Opportunities and Challenges to Greater CMM Recovery and Use 164
19.3.1 Market and Infrastructure Factors 165
19.3.2 Regulatory Information 165
19.4 Profiles of Individual Mines 165
19.5 References 165
20 Kazakhstan 167
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Contents (continued)
20.1 Summary of Coal Industry 167
20.1.1 Role of Coal in Kazakhstan 167
20.1.2 Stakeholders 168
20.1.3 Status of Coal and the Coal Mining industry 169
20.2 Overview of CMM Emissions and Development Potential 170
20.2.1 CMM Emissions from Operating Mines 170
20.2.2 CMM Emissions from Abandoned Coal Mines 171
20.2.3 CBM from Virgin Coal Seams 172
20.3 Opportunities and Challenges to Greater CMM Recovery and Use 173
20.3.1 Market and Infrastructure Factors 173
20.3.2 Regulatory Information 174
20.4 Profile of Individual Mines 175
20.5 References 176
21 Mexico 178
21.1 Summary of Coal Industry 178
21.1.1 Role of Coal in Mexico 178
21.1.2 Stakeholders 179
21.1.3 Status of Coal and the Coal Mining Industry 180
21.2 Overview of CMM Emissions and Development Potential 181
21.2.1 CMM Emissions from Operating Mines 181
21.2.2 CMM Emissions from Abandoned Coal Mines 184
21.2.3 CBM from Virgin Coal Seams 184
21.3 Opportunities and Challenges to Greater CMM Recovery and Use 185
21.3.1 Market and Infrastructure Factors 185
21.3.2 Regulatory Information 185
21.4 Profiles of Individual Mines 187
21.5 References 188
22 Mongolia 191
22.1 Summary of Coal Industry 191
22.1.1 Role of Coal in Mongolia 191
22.1.2 Stakeholders 193
22.1.3 Status of Coal and the Coal Mining Industry 194
22.2 Overview of CMM Emissions and Development Potential 196
22.2.1 CMM Emissions from Operating Mines 196
22.2.2 CMM Emissions from Abandoned Coal Mines 197
22.2.3 CBM from Virgin Coal Seams 198
22.3 Opportunities and Challenges to CMM Recovery and Use 198
22.3.1 Market and Infrastructure Factors 198
22.3.2 Regulatory Information 200
22.4 Profiles of Individual Mines 201
22.4.1 TavanTolgoi 201
22.4.2 Baganuur 202
22.4.3 NarynSukhait 202
22.4.4 Khotgor 202
22.4.5 SharynGol 203
22.4.6 Others 203
22.5 References 204
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23 New Zealand 208
23.1 Summary of Coal Industry 208
23.1.1 Role of Coal in New Zealand 208
23.1.2 Stakeholders 210
23.1.3 Status of Coal and the Coal Mining industry 210
23.2 Overview of CMM Emissions and Development Potential 212
23.2.1 CMM Emissions from Operating Mines 212
23.2.2 CMM Emissions from Abandoned Coal Mines 212
23.2.3 CBM from Virgin Coal Seams 212
23.3 Opportunities and Challenges to Greater CMM Recovery and Use 213
23.3.1 Market and Infrastructure factors 213
23.3.2 Regulatory Information 214
23.4 Profiles of Individual Mines 214
23.5 References 214
24 Nigeria 216
24.1 Summary of Coal Industry 216
24.1.1 Role of Coal in Nigeria 216
24.1.2 Status of Coal and the Coal Mining Industry 218
24.2 Overview of CMM Emissions and Development Potential 219
24.2.1 CMM Emissions from Operating Coal Mines 219
24.2.2 CMM Emissions from Abandoned Coal Mines 220
24.2.3 CBM from Virgin Coal Seams 220
24.3 Opportunities and Challenges to Greater CMM Recovery and Use 220
24.3.1 Market and Infrastructure Factors 221
24.3.2 Regulatory Information 221
24.4 Profiles of Individual Mines 222
24.5 References 222
25 Pakistan 224
25.1 Summary of Coal Industry 224
25.1.1 Role of Coal in PAKISTAN 224
25.1.2 Stakeholders 225
25.1.3 Status of Coal and the Coal Mining industry 226
25.2 Overview of CMM Emissions and Development Potential 227
25.2.1 CMM Emissions from Operating Mines 227
25.2.2 CMM Emissions from Abandoned Coal Mines 227
25.2.3 CBM from Virgin Coal Seams 227
25.3 Opportunities and Challenges to Greater CMM Recovery and Use 228
25.3.1 Market and Infrastructure factors 228
25.3.2 Regulatory Information 228
25.4 Profiles of Individual Mines 229
25.5 References 229
26 Philippines 231
26.1 Summary of Coal Industry 231
26.1.1 Role of Coal in the Republic of the Philippines 231
26.1.2 Stakeholders 233
26.1.3 Status of Coal and the Coal Mining Industry 234
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26.2 Overview of CMM Emissions and Development Potential 236
26.2.1 CMM Emissions from Operating Mines 237
26.2.2 CMM Emissions from Abandoned Mines 237
26.2.3 CBM from Virgin Coal Seams 237
26.3 Opportunities and Challenges to Greater CMM Recovery and Use 238
26.3.1 Market and Infrastructure Factors 238
26.3.2 Regulatory Information 239
26.4 Profiles of Individual Mines 239
26.4.1 Panian Mine, Semirara Mining Corporation 239
26.5 References 239
27 Poland 241
27.1 Summary of Coal Industry 241
27.1.1 Role of Coal in Poland 241
27.1.2 Stakeholders 242
27.1.3 Status of Coal and the Coal Mining Industry 243
27.2 Overview of CMM Emissions and Development Potential 244
27.2.1 CMM Emissions from Active Mines 244
27.2.2 CMM Emissions from Abandoned Coal Mines 246
27.2.3 CBM from Virgin Coal Seams 246
27.3 Opportunities and Challenges to Greater CMM Recovery and Use 247
27.3.1 Market and Infrastructure Factors 247
27.3.2 Regulatory Information 247
27.4 Profiles of Individual Mines 248
27.5 References 248
28 Republic of Korea 250
28.1 Summary of Coal Industry 250
28.1.1 The Role of Coal in Korea 250
28.1.2 Stakeholders 251
28.1.3 Status of Coal and the Coal Mining Industry 252
28.2 Overview of CMM Emissions and Development Potential 253
28.2.1 CMM Emissions from Operating Mines 253
28.2.2 CMM Emissions from Abandoned Coal Mines 253
28.2.3 CBM from Virgin Coal Seams 253
28.3 Opportunities and Challenges to Greater CMM Recovery and Use 253
28.3.1 Market and Infrastructure Factors 254
28.3.2 Regulatory Information 255
28.4 Profiles of Individual Mines 255
28.5 References 256
29 Romania 257
29.1 Summary of Coal Industry 257
29.1.1 Role of Coal in Romania 257
29.1.2 Stakeholders 258
29.1.3 Status of Coal and the Coal Mining Industry 259
29.2 Overview of CMM Emissions and Development Potential 260
29.2.1 CMM Emissions from Operating Mines 260
29.2.2 CMM Emissions from Abandoned Coal Mines 260
29.2.3 CBM from Virgin Coal Seams 261
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29.3 Opportunities and Challenges to Greater CMM Recovery and Use 261
29.3.1 Market and Infrastructure Factors 261
29.3.2 Regulatory Information 262
29.4 Profiles of Individual Mines 262
29.5 References 262
30 Russia 264
30.1 Summary of Coal Industry 264
30.1.1 Role of Coal in Russia 264
30.1.2 Stakeholders 266
30.1.3 Status of Coal and the Coal Mining Industry 267
30.2 Overview of CMM Emissions and Development Potential 268
30.2.1 CMM Emissions from Operating Mines 268
30.2.2 CMM Emissions from Abandoned Coal Mines 270
30.2.3 CBM from Virgin Coal Seams 270
30.3 Opportunities and Challenges to Greater CMM Recovery and Use 272
30.3.1 Market and Infrastructure Factors 273
30.3.2 Regulatory Information 273
30.4 Profiles of Individual Mines 275
30.5 References 275
31 South Africa 278
31.1 Summary of Coal Industry 278
31.1.1 Role of Coal in South Africa 278
31.1.2 Stakeholders 280
31.1.3 Status of Coal and the Coal Mining Industry 281
31.2 Overview of CMM Emissions and Development Potential 282
31.2.1 CMM Emissions from Operating Mines 282
31.2.2 CMM Emissions from Abandoned Mines 284
31.2.3 CBM from Virgin Coal Seams 284
31.3 Opportunities and Challenges to Greater CMM Recovery and Use 285
31.3.1 Market and Infrastructure Factors 285
31.3.2 Regulatory Information 286
31.4 Profiles of Individual Mines 286
31.5 References 286
32 Spain 289
32.1 Summary of Coal Industry 289
32.1.1 Role of Coal in Spain 289
32.1.2 Stakeholders 290
32.1.3 Status of Coal and the Coal Mining Industry 290
32.2 Overview of CMM Emissions and Development Potential 291
32.2.1 CMM Emissions from Operating Mines 291
32.2.2 CMM Emissions from Abandoned Coal Mines 292
32.2.3 CBM from Virgin Coal Seams 292
32.3 Opportunities and Challenges to Greater CMM Recovery and Use 292
32.3.1 Market and Infrastructure Factors 292
32.3.2 Regulatory Information 293
32.4 Profiles of Individual Mines 293
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32.5 References 293
33 Turkey 295
33.1 Summary of Coal Industry 295
33.1.1 Role of Coal in Turkey 295
33.1.2 Stakeholders 297
33.1.3 Status of Coal and the Coal Mining Industry 297
33.2 Overview of CMM Emissions and Development Potential 297
33.2.1 CMM Emissions from Operating Mines 298
33.2.2 CMM Emissions from Abandoned Mines 298
33.2.3 CBM from Virgin Coal Seams 298
33.3 Opportunities and Challenges to Greater CMM Recovery and Use 298
33.3.1 Market and Infrastructure Factors 299
33.3.2 Regulatory Information 299
33.4 Profiles of Individual Mines 299
33.5 References 299
34 Ukraine 301
34.1 Summary of Coal Industry 301
34.1.1 Role of Coal in Ukraine 301
34.1.2 Stakeholders 303
34.1.3 Status of Coal and the Coal Mining Industry 305
34.2 Overview of CMM Emissions and Development 306
34.2.1 CMM Emissions from Operating Mines 306
34.2.2 CMM Emissions from Abandoned Coal Mines 307
34.2.3 CBM from Virgin Coal Seams 308
34.3 Opportunities and Challenges to Greater CMM Recovery and Use 308
34.3.1 Market and Infrastructure Factors 309
34.3.2 Regulatory Information 309
34.4 Profiles of Individual Mines 310
34.5 References 312
35 United Kingdom 315
35.1 Summary of Coal Industry 315
35.1.1 Role of Coal in the United Kingdom 315
35.1.2 Stakeholders 317
35.1.3 Status of Coal and the Coal Mining Industry 319
35.2 Overview of CMM Emissions and Development Potential 321
35.2.1 CMM Emissions from Operating Mines 322
35.2.2 CMM Emissions from Abandoned Coal Mines 323
35.2.3 CBM from Virgin Coal Seams 324
35.3 Opportunities and Challenges to Greater CMM Recovery and Use 325
35.3.1 Market and Infrastructure Factors 325
35.3.2 Regulatory Information 326
35.4 Profiles of Individual Mines 326
35.5 References 326
36 United States 329
36.1 Summary of Coal Industry 329
36.1.1 Role of Coal in the United States 329
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Contents (continued)
36.1.2 Stakeholders 330
36.1.3 Status of Coal and the Coal Mining Industry 331
36.2 Overview of CMM Emissions and Development Potential 332
36.2.1 CMM Emissions from Operating and Abandoned Mines 332
36.2.2 Coalbed Methane from Virgin Coal Seams 334
36.2.3 Opportunities and Challenges to Greater CMM Recovery and Use 335
36.2.4 Market and Infrastructure Factors 336
36.2.5 Regulatory Information 340
36.3 Profiles of Individual Mines 341
36.4 References 341
37 Vietnam 344
37.1 Summary of Coal Industry 344
37.1.1 Role of Coal in Vietnam 344
37.1.2 Stakeholders 346
37.1.3 Status of Coal and the Coal Mining industry 346
37.2 Overview of CMM Emissions and Development Potential 347
37.2.1 CMM Emissions from Operating Mines 347
37.2.2 CMM Emissions from Abandoned Mines 347
37.2.3 CBM from Virgin Coal Seams 347
37.3 Opportunities and Challenges to Greater CMM Recovery and Use 348
37.3.1 Market and Infrastructure Factors 349
37.3.2 Regulatory Information 349
37.4 Profiles of Individual Mines 349
37.5 References 350
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List of tables
Countries Profiled in the Report ii
Table ES-1. Estimated Coal Reserves, 2011 iii
Table ES-2. Estimated Coal Production, 2012 iv
Table ES-3. Methane Emissions from Coal Mining (MmtCC^e) v
Table 1-1. Argentina's Coal Reserves and Production 4
Table 1-2. Key Stakeholders in Argentina's CMM Industry 5
Table 1-3. Argentina's CMM Emissions (million cubic meters) 7
Table 1-4. Argentina's Climate Change Mitigation Commitment 7
Table 2-1. Australia's Coal Reserves and Production 12
Table 2-2. Key Stakeholders in Australia's CMM Industry 14
Table 2-3. Australia's Coal Production by Mining Method and Region (Mmt) 15
Table 2-4. Australia's CMM Emissions 2000-2012 (million cubic meters) 17
Table 2-5. Australia's Climate Change Mitigation Commitment 20
Table 2-6. Major Australian Underground Coal Mines 23
Table 3-1. Botswana's Coal Reserves and Production 27
Table 3-2. Key Stakeholders in Botswana's CMM Industry 28
Table 3-3. Botswana's CMM Emissions (million cubic meters) 29
Table 3-4. Botswana's Climate Change Mitigation Commitment 31
Table 4-1. Brazil's Coal Reserves and Production 34
Table 4-2. Key Stakeholders in Brazil's CMM Industry 35
Table 4-3. Brazil's Coal-Fired Power Plants 37
Table 4-4. Brazil's CMM Emissions (million cubic meters) 38
Table 4-5. Brazil's Climate Change Mitigation Commitment 38
Table 5-1. Bulgaria's Coal Reserves and Production 41
Table 5-2. Key Stakeholders in Bulgaria's CMM Industry 42
Table 5-3. 2012 Statistics for Bulgaria's Coal Mining 43
Table 5-4. Bulgaria's CMM Emissions (million cubic meters) 44
Table 5-5. CBM and Coal Resources of Bulgaria's Dobroudja Basin 44
Table 5-6. Bulgaria's Climate Change Mitigation Commitment 45
Table 6-1. Canada's Coal Reserves and Production 48
Table 6-2. Key Stakeholders in Canada's CMM Industry 49
Table 6-3. Canada's Most Recent Statistics for Coal Mining 51
Table 6-4. Status of Canada's Coal Mines 52
Table 6-5. Canada's CMM Emissions (million cubic meters) 54
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List of Tables (continued)
Table 6-6. Canada's Major CBM Reserves 55
Table 6-7. Canada's Climate Change Mitigation Commitment 57
Table 7-1. China's Coal Reserves and Production 63
Table 7-2. Key Stakeholders in China's CMM Industry 64
Table 7-3. China's Mines by Category and Percent of Total Production (2004) 66
Table 7-4. China's CMM Emissions (million cubic meters) 67
Table 7-5. China's Climate Change Mitigation Commitment 71
Table 7-6. China's Regional Pilot Emissions Trading Schemes 72
Table 8-1. Colombia's Coal Reserves and Production - 2013 81
Table 8-2. Key Stakeholders in Colombia's CMM Industry 83
Table 8-3. Major Colombian Coal Producing Companies\Regions 84
Table 8-4. Major Colombian Coal Mines 85
Table 8-5. Colombia's CMM Emissions (million cubic meters) 86
Table 8-6. Colombia's Climate Change Mitigation Commitment 86
Table 9-1. The Czech Republic's Coal Reserves and Production 90
Table 9-2. Key Stakeholders in the Czech Republic's CMM Industry 91
Table 9-3. The Czech Republic's Coal Mines and Coal Production (2008) 92
Table 9-4. The Czech Republic's CMM Emissions (million cubic meters) 93
Table 9-5. The Czech Republic's Climate Change Mitigation Commitment 95
Table 10-1. Ecuador's Coal Reserves and Production 98
Table 10-2. Key Stakeholders in Ecuador's CMM Industry 99
Table 10-3. Ecuador's Climate Change Mitigation Commitment 100
Table 11-1. Finland's Coal Reserves and Production 103
Table 11-2. Finland's Climate Change Mitigation Commitment 105
Table 12-1. France's Coal Reserves and Production 107
Table 12-2. Key Stakeholders in France's CMM Industry 107
Table 12-3. France's Climate Change Mitigation Commitment 110
Table 13-1. Georgia's Coal Reserves and Production 113
Table 13-2. Key Stakeholders in Georgia's CMM Industry 113
Table 13-3. Georgia's CMM Emissions (million cubic meters) 115
Table 13-4. Georgia's Climate Change Mitigation Commitment 116
Table 13-5. Tkibuli-Shaori Coal Properties 117
Table 13-6. Tkibuli-Shaori Coal Field Profile 117
Table 14-1. Germany's Coal Reserves and Production 119
Table 14-2. Key Stakeholders in Germany's CMM Industry 121
Table 14-3. Germany's Coal Mining Statistics 2013 122
Table 14-4. Germany's CMM Emissions (million cubic meters) 122
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List of Tables (continued)
Table 14-5. Germany's Climate Change Mitigation Commitment 123
Table 14-6. Germany's CDM and JI Activity 124
Table 14-7. Germany's Mine Overview 125
Table 15-1. Hungary's Coal Reserves and Production 128
Table 15-2. Key Stakeholders in Hungary's CMM Industry 129
Table 15-3. Hungary's Largest Recoverable CMM/CBM Resources 130
Table 15-4. Hungary's CMM Emissions (million cubic meters) 130
Table 15-5. Hungary's Climate Change Mitigation Commitment 131
Table 16-1. India's Coal Reserves and Production 134
Table 16-2. Coal Distribution in India's Major Coalfields (million tonnes) 135
Table 16-3. Key Stakeholders in India's CMM Industry 137
Table 16-4. India's Hard Coal Production by Mine Type 137
Table 16-5. India's Classification System and Estimates of Mine Gassiness 138
Table 16-6. India's CMM Emissions (million cubic meters) 139
Table 16-7. CBM Project Blocks Offered for Lease 140
Table 16-8. CBM Projects Proposed or in Development 141
Table 16-9. India's Climate Change Mitigation Commitment 141
Table 17-1. Indonesia's Coal Reserves and Production 146
Table 17-2. Indonesia's Coal Reserves by Province (2011) 146
Table 17-3. Indonesia's Major Coal Producers 148
Table 17-4. Key Stakeholders in Indonesia's CMM Industry 149
Table 17-5. Indonesia's CMM Emissions (million cubic meters) 150
Table 17-6. Indonesia's CBM Resources 151
Table 17-7. Indonesia's Climate Change Mitigation Commitment 152
Table 18-1. Italy's Coal Reserves and Production 155
Table 18-2. Key Stakeholders in Italy's CMM Industry 156
Table 18-3. Italy's Projected CMM Emissions (million cubic meters) 157
Table 18-4. Italy's Climate Change Mitigation Commitment 159
Table 19-1. Japan's Coal Reserves and Production 162
Table 19-2. Key Stakeholders in Japan's CMM Industry 162
Table 19-3. Japan's CMM Emissions (million cubic meters) 164
Table 19-4. Japan's Climate Change Mitigation Commitment 164
Table 20-1. Kazakhstan's Coal Reserves and Production 167
Table 20-2. Kazakhstan's Major Coal Basins Production Capacity in 2012 168
Table 20-3. Key Stakeholders in Kazakhstan's CMM Industry 168
Table 20-4. Kazakhstan Mine and Production Statistics 170
Table 20-5. Kazakhstan's CMM Emissions (million cubic meters) 171
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List of Tables (continued)
Table 20-6. Summary of Kazakhstan's Selected CBM Resources 172
Table 20-7. Kazakhstan's Climate Change Mitigation Commitment 173
Table 21-1. Mexico's Coal Reserves and Production 178
Table 21-2. Mexico's Major Coal Basins 179
Table 21-3. Key Stakeholders in Mexico's CMM Industry 180
Table 21-4. Mexico's CMM Emissions (million cubic meters) 182
Table 21-5. Mexico's Climate Change Mitigation Commitment 185
Table 21-6. Coal Characteristics of Mexican Coal Basins 187
Table 21-7. Profile ofMINOSA Mines V, VI &VII 187
Table 22-1. Mongolia's Coal Reserves and Production 191
Table 22-2. Coal Resources Found in Major Coal Deposits 192
Table 22-3. Key Stakeholders in Mongolia's CMM Industry 193
Table 22-4. Mongolia's CMM Emissions (million cubic meters) 197
Table 22-5. Mongolia's Climate Change Mitigation Commitment 198
Table 23-1. New Zealand's Coal Reserves and Production 208
Table 23-2. Key Stakeholders in New Zealand's CMM Industry 210
Table 23-3. New Zealand's Production and Mine Statistics (million tonnes) 210
Table 23-4. New Zealand's Major Operating Coal Mines 211
Table 23-5. New Zealand's CMM Emissions (million cubic meters) 212
Table 23-6. New Zealand's Climate Change Mitigation Commitment 213
Table 24-1. Nigeria's Coal Reserves and Production 216
Table 24-2. Key Stakeholders in Nigeria's CMM Industry 217
Table 24-3. Nigeria's Coal Mines 219
Table 24-4. Nigeria's CMM Emissions (million cubic meters) 220
Table 24-5. Nigeria's Climate Change Mitigation Commitment 220
Table 25-1. Pakistan's Coal Reserves and Production 224
Table 25-2. Key Stakeholders in Pakistan's CMM Industry 225
Table 25-3. Operating Coal Mines in Pakistan 227
Table 25-4. Pakistan's CMM Emissions (million cubic meters) 227
Table 25-5. Pakistan's Climate Change Mitigation Commitment 228
Table 26-1. Philippines' Coal Reserves and Production 231
Table 26-2. Philippines' Coal Districts 233
Table 26-3. Key Stakeholders in the Philippines' CMM Industry 233
Table 26-4. Coal ProductionbyArea2011 235
Table 26-5. Coal-fired Power Plants as of 2013 235
Table 26-6. Philippines' CMM Emissions (million cubic meters) 237
Table 26-7. Philippines' Potential CBM In-Place Resources 237
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List of Tables (continued)
Table 26-8. Philippines' Climate Change Mitigation Commitment 238
Table 27-1. Poland's Coal Reserves and Production 241
Table 27-2. Key Stakeholders in Poland's CMM Industry 242
Table 27-3. Poland's Coal Mines, 2004 versus 2008 244
Table 27-4. Poland's CMM Emissions (million cubic meters) 245
Table 27-5. Poland's In-Place CBM Resources 246
Table 27-6. Poland's Climate Change Mitigation Commitment 247
Table 28-1. Korea's Coal Reserves and Production 250
Table 28-2. Key Stakeholders in the Republic of Korea's CMM Industry 251
Table 28-3. Korea's CMM Emissions (million cubic meters) 253
Table 28-4. Korea's Climate Change Mitigation Commitment 254
Table 29-1. Romania's Coal Reserves and Production 257
Table 29-2. Key Stakeholders in Romania's CMM Industry 258
Table 29-3. Romania's CMM Emissions (million cubic meters) 260
Table 29-4. Romania's CMM Utilization Projects 260
Table 29-5. Romania's Climate Change Mitigation Commitment 261
Table 30-1. Russia's Coal Reserves and Production 264
Table 30-2. Russia's Power Generation by Source, 2011 265
Table 30-3. Russia's Coal Production by Region, 2012 266
Table 30-4. Key Stakeholders in Russia's CMM Industry 267
Table 30-5. Russia's Coal Mining Statistics (2012) 268
Table 30-6. Russia's CMM Emissions (million cubic meters) 268
Table 30-7. Kuzbass CMM Emissions (million cubic meters) 269
Table 30-8. Estimate of CBM Resources 271
Table 30-9. Russia's Climate Change Mitigation Commitment 272
Table 30-10. Total Consumption by Potential CMM Markets 273
Table 31-1. South Africa's Coal Reserves and Production 278
Table 31-2. Key Stakeholders in South Africa's CMM Industry 280
Table 31-3. South Africa's Recent Production and Mine Statistics 281
Table 31-4. South Africa's CMM Emissions (million cubic meters) 283
Table 31-5. South Africa's Climate Change Mitigation Commitment 285
Table 31-6. Coaltech 2020 Consortium Members 285
Table 32-1. Spain's Coal Reserves and Production 289
Table 32-2. Key Stakeholders in Spain's CMM Industry 290
Table 32-3. Spain's CMM Emissions (million cubic meters) 292
Table 32-4. Spain's Climate Change Mitigation Commitment 292
Table 33-1. Turkey's Coal Reserves and Production 295
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List of Tables (continued)
Table 33-2. Key Stakeholders in Turkey's CMM Industry 297
Table 33-3. Turkey's CMM Emissions (million cubic meters) 298
Table 33-4. Turkey's Climate Change Mitigation Commitment 298
Table 34-1. Ukraine's Coal Reserves and Production 301
Table 34-2. Key Stakeholders in Ukraine's CMM Industry 303
Table 34-3. Ukraine - Number of Coal Mines by Type 305
Table 34-4. Ukraine's CMM Emissions (million cubic meters) 306
Table 34-5. Ukraine's Climate Change Mitigation Commitment 308
Table 34-6. Profile ofYuzhno-Donbasskaya #3 311
Table 34-7. List of Ukraine Joint Implementation Projects 312
Table 35-1. United Kingdom's Coal Reserves and Production 315
Table 35-2. United Kingdom's Coal Fields 315
Table 35-3. Key Stakeholders in the United Kingdom's CMM Industry 317
Table 35-4. United Kingdom's Current CBM Licenses/Agreements 319
Table 35-5. UK's Recent Coal Mine Statistics (2012) 319
Table 35-6. UK's Major Underground Mines in Production as of 2012 320
Table 35-7. UK's Surface Mines in Production as of 2012 320
Table 35-8. United Kingdom's CMM Emissions (million cubic meters) 322
Table 35-9. United Kingdom's AMM Projects 323
Table 35-10. UK's Climate Change Mitigation Commitment 325
Table 36-1. U.S. Coal Reserves and Production 329
Table 36-2. Key Coal Mine Companies Draining Gas at U.S. Mines 330
Table 36-3. Summary of U.S. Underground and Surface Mine Production, 2013 331
Table 36-4. U.S. CMM Emissions (million cubic meters) 332
Table 36-5. Summary of U.S. Mine Methane Recovery & Destruction Projects 334
Table 36-6. U.S. CBM Proved Reserves (billion cubic meters) 335
Table 36-7. The United States' Climate Change Mitigation Commitment 336
Table 36-8. Recent U.S. Natural Gas Prices 339
Table 37-1. Vietnam's Coal Reserves and Production 344
Table 37-2. Key Stakeholders in Vietnam's CMM Industry 346
Table 37-3. Vietnam's CMM Emissions (million cubic meters) 347
Table 37-4. Vietnam's Climate Change Mitigation Commitment 349
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List of Figures
Figure 1-1. Argentina's Coal Fields 5
Figure 2-1. Australia's Coal Fields 13
Figure 2-2. Australia's Fugitive Emissions from Coal Mining, 2000-2012 16
Figure 2-3. Location of Australia's Coal Seam Reserves 19
Figure 3-1. Botswana Coalfields Map 28
Figure 4-1. Brazil's Coal Fields 35
Figure 5-1. Bulgaria's Coal Fields 42
Figure 6-1. Canada's Coal Fields 49
Figure 6-2. Status of Canada's Coal Mines 51
Figure 6-3. Location of Probable Economically Recoverable CBM Reserves in Canada
(trillion cubic feet) 55
Figure 6-4. Primary CBM Potential Areas in Alberta 55
Figure 6-5. CBM Potential in British Columbia 56
Figure 7-1. China's Coal Fields 64
Figure 7-2. China's CBM Resources by Region 69
Figure 7-3. China's CBM Resources by Depth 69
Figure 7-4. China's Annual CBM Production 70
Figure 8-1. Map of Colombian Minerals 82
Figure 8-2. Map of Colombian Coal Mines 82
Figure 9-1. Coal Basins of the Czech Republic 91
Figure 9-2. Mining Areas & Coal Seam Gas Concessions in the OKR Coalfield 94
Figure 10-1. Location of Ecuador's Coal Reserves 99
Figure 11-1. Location of Finland's Coal Reserves 104
Figure 12-1. CMM Projects in France 109
Figure 13-1. Georgia's Main Coal Fields 112
Figure 13-2. Georgia Coal Production (thousand tonnes) 114
Figure 14-1. Germany's Coal Fields 120
Figure 15-1. Hungary's Coal Basin Fields 129
Figure 16-1. India's Coal Fields 136
Figure 17-1. Indonesia's Coal Fields 148
Figure 17-2. Indonesia's CBM Basins 151
Figure 18-1. The Only Underground Coal Mine in Italy 155
Figure 18-2. European Gas Limited's Tuscany Projects 158
Figure 19-1. Japan's Coal Fields 163
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List of Figures (continued)
Figure 20-1. Kazakhstan Annual Coal Production 167
Figure 20-2. Kazakhstan Coal Regions and Coal Methane Reserves 172
Figure 21-1. Mexico's Coal Fields 179
Figure 21-2: Estimated Boundaries of Recent CBM Staking by the Mexican Government 186
Figure 22-1. Mongolia's Coal Production, Consumption, and Exports (million tonnes) 191
Figure 22-2. Mongolia's Coal Basins 193
Figure 22-3. Mongolia's Electricity Supply 199
Figure 23-1. New Zealand's Coal Fields 209
Figure 24-1. Nigeria's Coal Fields 217
Figure 25-1. Pakistan's Coal Fields 225
Figure 26-1. Philippines' Coal Resources 232
Figure 27-1. Poland's Major Coal Basins 242
Figure 28-1. Korea's Coal Fields and Major Coal Terminals 251
Figure 28-2. Korea's Coal Production (million tonnes) 252
Figure 29-1. Romania's Coalfields 258
Figure 29-2. Romania's Annual Coal Production 259
Figure 30-1. Historical Russian Coal Production, Consumption, and Exports 265
Figure 30-2. Russia's Coal Reserves 266
Figure 30-3. Estimated Historical Methane Emissions from Russia's Underground and
Surface Coal Mines 269
Figure 30-4. CBM Distribution in the Kuzbass Basin in Russia 271
Figure 31-1. South Africa's Domestic Coal Consumption by Sector 279
Figure 31-2. South Africa's Coal Basins 279
Figure 31-3. 2012 Saleable Coal Production by Mining Company 280
Figure 31-4. Coal Tech 2020 Summary Results 283
Figure 32-1. Spain's Coal Fields 290
Figure 33-1. Turkey's Coal Fields 296
Figure 33-2. Turkey's Zonguldak Coal Basin 296
Figure 34-1. Ukraine's Historical Raw Coal Production Volumes, 2000-2012 302
Figure 34-2. Ukraine's Coal Fields 303
Figure 35-1. United Kingdom's Coal Fields 316
Figure 35-2. United Kingdom's Coal Methane Resources 322
Figure 35-3. Abandoned Mine Net Emissions 324
Figure 36-1. Map of U.S. Coal Basins 330
Figure 36-2. Active Underground Coal Mine Production and CMM Emissions in the U.S.,
2000-2013 (million cubic meters) 333
Figure 36-3. U.S. Interstate Natural Gas Pipelines, 2009 337
CMM Country Profiles
" 'Global
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List of Figures (continued)
Figure 36-4. Annual Increases in U.S. Natural Gas Pipeline Capacity (billion cubic feet per
day) 338
Figure 36-5. Annual Increases in U.S. Natural Gas Pipeline Length (thousand miles) 338
Figure 37-1. Vietnam's Coal Resources 345
fc-m% CMM Country Profiles
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Units of Conversions
Units
t
tonnes
Mt
thousand tonnes
Mmt
million tonnes
Mmt C02e
million tonnes C02 equivalent
bt
billion tonnes
kg
kilograms
Mg
megagram
Gg
gigagram
m
meters
m3
cubic meters
Mm3 or MMCM
million cubic meters
Bm3 or BCM
billion cubic meters
km
kilometers
MCM
thousand cubic meters
Mmcf
million cubic feet
TCM
trillion cubic meters
Tcf
trillion cubic feet
kW
kilowatts
MW
megawatts
MWe
megawatt electrical
kWhr
kilowatt-hours
J
joule
KJ
kilojoule
MJ
megajoule
PJ
petajoule
Btu
British thermal unit
Kpa
kilopascals
psia
pounds per square inch absolute
Conversions
It
1.102 US ton/short ton
lm
3.28 feet
1 km
0.62 miles
1 m3
35.32 cubic feet
1kg
2.21 pounds
1 kg CH4
1.47 m3 CH4
ltCH4
21 MmtC02e
1 MJ
0.28 kilowatt-hours
1 Btu
1055 joules
V 'Global ^
Methane Initiative CMM Country Profiles I
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Executive Summary
In 2004,14 countries came together to launch the Methane to Markets (M2M) Partnership —which
was re-launched as the Global Methane Initiative (GMI) in 2010—with the aim of reducing emissions
of methane, a potent greenhouse gas (GHG), by promoting the development of projects that recover
and use methane as a clean energy source. This international public-private partnership continues
to work with government agencies around the world to facilitate project development in five key
methane-producing sectors: agriculture (manure management), coal mines, municipal solid waste
(MSW), oil and natural gas systems, and wastewater. The efforts of this collaboration are yielding
important and diverse benefits across the globe, such as enhanced economic growth and energy
security, improved air quality and industrial safety, and reduced GHG emissions.
GMI has grown over the past 10 years to include 42 Partner Countries and the European
Commission, representing about 70 percent of the world's anthropogenic methane emissions. GMI
also includes a vibrant Project Network of more than 1,300 members from diverse sectors such as
international finance, development, the policy arena, and non-profit institutions whose common
goal is to promote methane recovery and use projects around the world.
This report was prepared to assist GMI's Coal Subcommittee in its goal of reducing methane
emissions in the coal mines sector. The study scopes out opportunities across the world for coal
mine methane (CMM) recovery projects, serving as a guide for the Coal Subcommittee to promote
the development of future CMM projects. The study profiles 37 countries—GMI Partner Countries
and otherwise—most of which are actively producing coal or have significant coal reserves (see
Table ES-1).
Countries Profiled in the Report
Argentina*
Finland*
Mexico*
South Africa
Australia*
France
Mongolia*
Spain
Botswana
Georgia*
New Zealand
Turkey*
Brazil*
Germany*
Nigeria*
Ukraine*
Bulgaria*
Hungary
Pakistan*
United Kingdom*
Canada*
India*
Philippines*
United States*
China*
Indonesia*
Poland*
Vietnam*
Colombia*
Italy*
Republic of Korea*
Czech Republic
Japan*
Romania
Ecuador*
Kazakhstan*
Russia*
*GMI Partner Countries
Each country profile includes an overview of its coal industry, and characterizes and quantifies its
CMM emissions. Brief descriptions of individual coal mines also have been provided wherever
possible. All information has been sourced from publicly-available literature, or from in-country
experts.
Global Overview at a Glance
Table ES-1 summarizes estimated coal reserves in the profiled countries. The United States, Russia,
and China are the top three ranking countries together accounting for more than half of the total
global coal reserves of 857,937 million tonnes (Mmt) (397,026 Mmt anthracite and bituminous;
CMM Country Profiles ii
Global
Methane Initiative
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460,912 Mmt sub-bituminous and lignite). The United States alone holds roughly 28 percent of the
world's total or 234,615 Mmt.
Table ES-1. Estimated Coal Reserves, 2011
Country
Anthracite &
Bituminous
(million tonnes)
Sub-bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Profiled Country
Rank
(# and %)
Argentina
a
550
550
23 (0.064%]
Australia
37,100
39,300
76,400
4 (8.905%]
Botswana
40
0
40
34 (0.005%]
Brazil
0
6,630
6,630
13 (0.773%]
Bulgaria
2
2,364
2,366
17 (0.276%]
Canada
3,474
3,108
6,582
14 (0.767%]
China
62,200
52,300
114,500
3 (13.346%]
Colombia
6,746
0
6,746
12 (0.786%]
Czech Republic
181
871
1,052
21(0.123%]
Ecuador
0
24
24
35 (0.003%]
Finland
0
0
0
36 (tie] (0.0%]
France
0
0
0
36 (tie] (0.0%]
Georgia
201
0
201
29 (0.023%]
Germany
48
40,500
40,548
6 (4.726%]
Hungary
13
1,647
1,660
19 (0.193%]
India
56,100
4,500
60,600
5 (7.063%]
Indonesia
0
28,017
28,017
10 (3.266%]
Italy
0
50
50
33 (0.006%]
Japan
337
10
347
25 (0.040%]
Kazakhstan
21,500
12,100
33,600
8 (3.916%]
Mexico
860
351
1,211
20 (0.141%]
Mongolia
1,170
1,350
2,520
16 (0.294%]
New Zealand
33
538
571
22 (0.067%]
Nigeria
21
169
190
30 (0.022%]
Pakistan
0
2,070
2,070
18 (0.241%]
Philippines
41
275
316
26(0.037%]
Poland
4,178
1,287
5,465
15 (0.637%]
Republic of Korea, South
0
126
126
32 (0.015%]
Romania
10
281
291
27 (0.034%]
Russia
49,088
107,922
157,010
2 (18.301%]
South Africa
30,156
0
30,156
9 (3.515%]
Spain
200
330
530
24 (0.062%]
Turkey
322
8,380
8,702
11 (1.014%]
& CMM Country Profiles iii
" 'Global
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Table ES-1. Estimated Coal Reserves, 2011
Anthracite &
Sub-bituminous
Profiled Country
Country
Ukraine
15,351
18,522
33,873
7 (3.948%]
United Kingdom
228
0
228
28 (0.027%]
United States
107,276
127,340
234,615
1 (27.346%]
Vietnam
150
0
150
31(0.017%]
Profiled Countries Total
397,026
460,912
857,937
Source: International Energy Statistics - Coal Reserves, U.S. Energy Information Administration (EIA], Washington, DC,
data as of 31 December 2014. http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm?tid=l&pid=7&aid=6
Note: EIA calculates U.S. reserves only. It reproduces international reserves data from World Energy Council (WEC] based
on WEC's definition of "Proved Recoverable Reserves" as the tonnage within the Proved Amount in Place that can be
recovered under present and expected local economic conditions with existing available technology.
Table ES-2. Estimated Coal Production, 2012
Country
Anthracite &
Bituminous
Lignite
Total
Profiled Country
Rank
(# and %]
Argentina
0.08
0.00
0.08
31 (tie] (0.001%]
Australia
347.20
73.54
420.74
5 (5.49%]
Botswana
0.74
0.00
0.74
29 (0.01%]
Brazil
3.26
3.04
6.30
24 (0.08%]
Bulgaria
0.01
32.51
32.52
19 (0.42%]
Canada
57.00
9.50
66.50
13 (0.87%]
China
3,510.25
141.52
3,651.76
1 (47.63%]
Colombia
89.45
0.00
89.45
11 (1.17%]
Czech Republic
11.44
43.53
54.97
15 (0.72%]
Ecuador
0.00
0.00
0.00
33 (tie]
(0.0000%]
Finland
0.00
0.00
0.00
33 (tie]
(0.0000%]
France
0.00
0.00
0.00
33 (tie]
(0.0000%]
Georgia
0.25
0.00
0.25
30 (0.003%]
Germany
11.56
185.43
196.99
8 (2.569%]
Hungaiy
0.00
9.29
9.29
22 (0.12%]
India
545.86
43.49
589.35
3 (7.69%]
Indonesia
442.81
0.00
442.81
4 (5.78%]
Italy
0.08
0.00
0.08
31 (tie] (0.001%]
Japan
0.00
0.00
0.00
33 (tie]
(0.0000%]
/i,
'Global
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CMM Country Profiles iv
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Table ES-2. Estimated Coal Production, 2012
Anthracite &
I ianitp
T Ot3l
Profiled Country
Country
Bituminous
LjlgllllC
Rank
(# and %}
Kazakhstan
120.50
5.52
126.02
10 (1.64%]
Mexico
15.19
0.00
15.19
21(0.20%]
Mongolia
23.63
9.98
33.61
18 (0.44%]
New Zealand
4.60
0.33
4.93
26 (0.06%]
Nigeria
0.03
0.00
0.03
32 (0.0004%]
Pakistan
1.92
1.17
3.09
27 (0.04%]
Philippines
8.00
0.00
8.00
23 (0.10%]
Poland
79.23
64.28
143.51
9 (1.87%]
Republic of Korea, South
2.09
0.00
2.09
28 (0.03%]
Romania
0.04
33.99
34.03
17 (0.44%]
Russia
276.09
77.85
353.94
6 (4.62%]
South Africa
259.30
0.00
259.30
7 (3.38%]
Spain
6.15
0.00
6.15
25 (0.08%]
Turkey
3.56
65.95
69.51
12 (0.91%]
Ukraine
64.63
0.00
64.63
14 (0.84%]
United Kingdom
16.29
0.00
16.29
20 (0.21%]
United States
850.51
71.60
922.12
2 (12.03%]
Vietnam
42.10
0.00
42.10
16 (0.55%]
Profiled Countries Total
6,793.84
872.52
7,666.37
WORLD
6,854.2
1,033.5
7,887.7
Source: International Energy Statistics - Coal Production, EIA, Washington, DC, data as of 31 December 2014.
http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm?tid=l&pid=7&aid=l
As seen in Table ES-2 above, China and the United States are by far the world's largest coal
producers, together accounting for nearly 65 percent of profiled countries' production. China alone
produces more than half of the profiled countries' total production. Of the countries evaluated in
this study, Ecuador, Finland, France, and Japan are currently not producing any coal.
Table ES-3. Methane Emissions from Coal Mining (MmtC02e)
Country
2000
2005
2010
2015*
Profiled
Country
Rank
(as of2015]
Argentina
0.23
0.04
0.11
0.13
30
Australia
20.84
22.76
27.24
29.57
5
Botswana
0.27
0.27
0.31
0.32
28
Brazil
0.90
1.03
1.15
1.46
20
Bulgaria
1.32
1.23
1.45
1.52
19
Canada
0.97
1.00
0.94
0.98
23
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Table ES-3. Methane Emissions from Coal Mining (MmtC02e)
Country
2000
2005
2010
2015*
Profiled
Country
Rank
fas of2015]
China
134.74
257.11
295.51
321.16
1
Colombia
3.28
5.08
7.29
9.26
8
Czech Republic
5.02
4.65
4.38
4.20
13
Ecuador
-
-
-
-
34 (tie]
Finland
-
-
-
-
34 (tie]
France
2.37
-
-
-
34 (tie]
Georgia
0.00
0.00
0.00
0.00
33
Germany
9.68
5.69
3.68
3.53
14
Hungary
0.31
0.02
0.02
0.02
32 (tie]
India
14.90
15.95
18.88
20.68
7
Indonesia
1.02
2.26
4.04
4.42
12
Italy
0.03
0.02
0.02
0.02
32 (tie]
Japan
0.77
0.07
0.05
0.05
31
Kazakhstan
18.32
17.51
22.30
23.28
6
Mexico
1.73
2.16
2.35
1.84
17
Mongolia
0.10
0.15
0.20
0.21
29
New Zealand
0.34
0.33
0.39
0.42
26
Nigeria
0.34
0.91
0.96
1.01
22
Pakistan
0.95
1.50
1.13
1.24
21
Philippines
0.20
0.43
0.38
0.41
27
Poland
10.96
9.58
7.90
7.58
10
Republic of Korea
1.16
0.79
0.81
0.88
24
Romania
2.67
2.49
2.73
2.85
15
Russia
41.95
45.39
48.82
50.97
3
South Africa
7.68
8.33
8.17
8.64
9
Spain
1.23
0.92
0.66
0.63
25
Turkey
1.62
1.48
1.90
1.82
18
Ukraine
31.38
29.90
29.71
31.02
4
United Kingdom
6.99
4.08
2.73
2.62
16
United States
60.41
56.91
67.47
69.98
2
Vietnam
1.87
5.23
6.91
7.57
11
Profiled Countries Total
386.56
505.28
570.58
610.31
World Totals
401.41
521.57
588.55
629.74
*2015 emissions: Extrapolated based on changes in coal production from 2000 to 2010.
Source: Global Anthropogenic Non-CC>2 Greenhouse Gas Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency (U.S. EPA], Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/Downloads/EPAactivities/EPA Global NonC02 Projections Dec2012.pdf
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In Table ES-3 above, total historical and/or projected methane emissions from coal mining are
shown for 2000, 2005, 2010, and 2015. China, which has the world's highest coal production, also
emits the greatest amount of CMM, estimated at more than 321 MmtCC^e per year. Other large
CMM emitters (i.e., more than 10 MmtCC^e per year) based on 2015 estimates are the United States,
Russia, Ukraine, Australia, Kazakhstan, and India.
GMI's International CMM Project Database (https://www.globalmethane.org/coal-
mines/cmm /index.aspx] provides a worldwide snapshot of CMM recovery and utilization
activities—both operating and in development—and the amount of CMM emissions avoided.
Ongoing CMM projects can be found in nearly half of the 37 countries profiled in this report China,
Australia, Czech Republic, Germany, Poland, United Kingdom, and the United States in particular
host numerous projects at active mines, while Germany, Ukraine, United Kingdom, and the United
States host many projects at abandoned mines.
According to data found in the International CMM Projects Database, Australia, China, Germany,
Poland, Ukraine, and the United States avoid a considerable amount of methane emissions from
their coal mines. Australia, Czech Republic, France, Germany, Japan, Mexico, Nigeria, Poland,
Ukraine, United Kingdom, and the United States get a portion of their reductions through recovery
at abandoned mines.
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Introduction
Methane is a potent greenhouse gas (GHG) that is more than 28 to 34 times as powerful as carbon
dioxide (CO2) at trapping heat in the atmosphere, on a mass-basis over a 100-year timeframe.1 By
2015, it is estimated that methane will account for 14 percent of global GHGs, with more than 60
percent of the total methane emissions coming from human-related activities, such as agriculture,
coal mining municipal solid waste (MSW), oil and natural gas systems, and wastewater.2 Since
methane has a much shorter atmospheric lifetime than CO2 (about 12 years compared to about 200
years for CO2), reducing methane emissions can achieve significant climate benefits over the next
2 5 years.
The Methane to Markets (M2M) Partnership was formed in 2004 as an agreement amongst 14
countries to work toward minimizing methane emissions from major sources. The goal of this
international public-private partnership is to reduce emissions of methane by advancing the
development of projects that recover and use methane as a clean energy source. M2M was re-
launched as the Global Methane Initiative (GMI) in October 2010 and membership has expanded to
42 countries (and the European Commission) as of 2015 (see text box below), representing about
70 percent of the world's anthropogenic methane emissions. Public and private sector
organizations around the world are also working together with government agencies to facilitate
project development These collaborative efforts are yielding important benefits across the globe,
including enhanced economic growth and energy security, improved air quality and industrial
safety, and reduced GHG emissions.
Global Methane Initiative Partners (as of 2015)
Albania
Ethiopia
Kazakhstan
Republic of Serbia
Argentina
European Commission
Mexico
Russia
Australia
Finland
Mongolia
Saudi Arabia
Brazil
Georgia
Nicaragua
Sri Lanka
Bulgaria
Germany
Nigeria
Thailand
Canada
Ghana
Norway
Turkey
Chile
India
Pakistan
Ukraine
China
Indonesia
Peru
United Kingdom
Colombia
Italy
Philippines
United States
Dominican Republic
Japan
Poland
Vietnam
Ecuador
Jordan
Republic of Korea
Methane released from coal mining activities in underground and surface mines is of particular
concern as methane is explosive in nature and poses a safety hazard to coal miners. Constituting 8
percent of the global anthropogenic methane emissions by 2015, coal mine methane (CMM)—if
recovered and utilized—not only provides valuable clean fuel and environmental benefits, but also
improves mine safety and productivity.
1 The fifth report of the Intergovernmental Panel on Climate Change (IPCC], released in the lastyear, included methane
GWP values of 28 to 34. The United States and other developed countries are currently using the fourth report's GWP
value of 25 to quantify the climate impact of U.S.-government-supported methane reduction projects.
2 Global Anthropogenic Emissions ofNon-CC>2 Greenhouse Gases: 1990-2030, U.S. Environmental Protection Agency (U.S.
EPA], Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/Downloads/EPAactivities/EPA Global NonC02 Projections Dec2012.pdf
** ,
Methane Stive CMM Country Profiles 1
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CMM varies in quality depending on the source of emission. CMM drained from underground mine
ventilation systems is veiy dilute. Referred to as ventilation air methane (VAM), it accounts for the
largest source of CMM emissions globally. In some instances, it is necessary to supplement
ventilation with a degasification system consisting of a network of boreholes and gas pipelines that
may be used to capture methane before, during and after mining activities to keep the methane
concentration within safe limits. Abandoned or closed mines may also continue to emit methane,
typically of low to medium quality, from ventilation pipes or boreholes.
A number of technologies are readily available to
recover and use methane from active or abandoned
coal mines, while technology has been demonstrated to
recover the energy content of dilute methane emissions
from coal mine ventilation shafts (i.e., VAM). Specific
uses for recovered CMM depend on the gas quality,
especially the concentration of methane and the
presence of other contaminants in the drained gas.
CMM is typically used worldwide for power generation,
district heating, boiler fuel, or town gas, or it is sold to
natural gas pipeline systems. CMM also can be used in
many other ways (see text box).
Although there are significant benefits and scope for
CMM recovery and use, developing CMM projects face
several challenges. These include accessing appropriate technology to assess resources, effectively
installing drainage systems, and selecting appropriate end use technologies. Market barriers
include appropriate price signals and adequate infrastructure to transport the gas. Lastly,
regulatory and policy issues such as clear establishment of property rights to the gas and access to
capital or financing also impede CMM project development.
Purpose of the Report
This report has been prepared under the aegis of the GMI Coal Subcommittee, responsible for
guiding GMI efforts to reduce methane emissions from coal mines. The Subcommittee identified the
lack of information about project opportunities in different countries as a major barrier to initiating
global CMM project development.
Coal Mine Methane Country Profiles was prepared by the Coalbed Methane Outreach Program
(CMOP), an initiative of the U.S. Environmental Protection Agency (U.S. EPA) that supports GMI's
efforts in promoting CMM project development in coal-producing countries. The information in this
report is based on country profiles submitted by GMI Partner Countries, as well as on publicly-
available data and consultation with in-country experts.
Organization of the Report
The following sections in the report profile 37 countries in alphabetical order. Each country's
overview addresses the following broad topical areas:
¦ Summary of the Coal Industry
- Coal production and the importance of coal in the country's economy and energy sector
CMM Country Profiles 2
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CMM Uses
Coal drying
Heat source for mine
ventilation or supplemental
fuel for boilers
Vehicle fuel as compressed
natural gas (CNG) or liquefied
natural gas (LN G)
Manufacturing feedstock
Fuel source for fuel cells and
internal combustion engines
-------
- Key stakeholders in CMM project development
- Status of the coal mining industry
¦ Overview of CMM Emissions, Projects, and Potential
- CMM from Operating Mines
- CMM from Abandoned Mines
- CBM from Virgin Coal Seams
¦ Opportunities and Challenges to Greater CMM Recovery and Use
¦ Profiles of Individual Mines
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1 Argentina
1.1 Summary of Coal Industry
l.l.l
Role of Coal in Argentina
Although Argentina is a significant energy producer and a net energy exporter, it has limited coal
reserves. Its energy resources are dominated by oil and natural gas, with coal playing a minor role
in the national energy mix. Only 1.5 percent of Argentina's primary energy supply came from coal
and peat combined in 2011 (IEA, 2013). Argentina currently has only one power plant in the
country that is partially coal fired; located in the Buenos Aires province, the San Nicolas plant
(which also utilizes oil and natural gas to generate electricity) has a total installed capacity of 650
MW (PennEnergy, 2014). By the end of 2014, Argentina's first 100 percent coal-fired power plant—
the 240 MW Rio Turbio power plant—was about 90 percent complete and will be the country's first
to run entirely on coal.
As shown in Table 1-1, Argentina's coal reserves were 550 million tonnes (Mmt) in 2011 and coal
production in Argentina amounted to only about 0.08 Mmt in 2012 (EIA, 2014a).
Table 1-1. Argentina's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million
tonnes)
Sub-
bituminous &
Lignite
(million
tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
Annual Coal Production (2012]
0
0.08
550
0
550
0.08
32 (0.062%]
61 (0.001%]
Source: EIA (2014a]
Coal and related organic-rich deposits are widely distributed in Argentina; however, its coal
reserves are not extensive (Brooks and Willett, 2004). Rio Turbio has the only operational coal
mine in Argentina. Figure 1-1 shows the location of these coal deposits.
A
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ARGENTINA
Figure 1-1. Argentina's Coal Fields
1.1.2 Stakeholders
Little information on business stakeholders in Argentinean coal mine methane (CMM) development
is available. Other potentially interested parties include natural gas transmission and distribution
companies and ENARGAS, the gas regulatory agency. Key stakeholders are listed in Table 1-2.
Table 1-2. Key Stakeholders in Argentina's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
¦ Yaciraiento de Carbon de Rio Turbio (YCRT)
Potential host mine
Natural Gas Transmission
¦ Transportadora do Gas del Norte
CMM pipeline
& Distribution Companies
¦ Transportadora del Gas del Sur (TGS)
distribution
Regulatory Agencies
¦ National Gas Regulatory Authority or Ente Nacional
Permitting, gas sale &
Regulador Del Gas (ENARGAS)
distribution
¦ Department of Environment and Sustainable Development
¦ Department of Energy
¦ Department of Mining
111
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Table 1-2. Key Stakeholders in Argentina's CMM Industry
Stakeholder Category
Stakeholder
Role
Developers
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Project opportunity
identification and
planning
Engineering, Consultancy,
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
and Related Services
Professional Associations
¦ Argentine Petroleum and Gas Institute
Facilitate government/
¦ Association of Sanitaiy Engineering and Environmental
industry interaction
Sciences
Other
¦ Natural gas T&D companies (e.g., MetroGAS]
1.1.3 Status of Coal and the Coal Mining Industry
Only one underground mine is active in Argentina - the Rio Turbio mine - currently operated by
Yacimientos Carboniferos Rio Turbio (YCRT), a company owned by the Argentine National State. It
was previously run by Yacimientos Carboniferos Fiscales, which privitized in 1994, but at a low
production rate. The Rio Turbio mine produces sub-bituminous coal, some of which is consumed
onsite in a rail car repair forge and the remainder is sent to Buenos Aires for power generation
(Perczyk, 2006).
Annual production statistics reveal a decline in production over the past three decades, from a
reported high of slightly over 500,000 tonnes per year in 1982 to less than 100,000 tonnes in 2012
(EIA, 2014a). Although five underground operations were actively exploiting high-volatile sub-
bituminous coal at Pico Quemado in the 1950s (M2M, 2005), they are now closed.
Coal production is, however, projected to increase as Argentina is expanding its electric grid to
connect the remote Rio Turbio mine to Rio Gallegos, a big city and potential consumption center for
coal-generated power (Perczyk, 2006).
Gas reserves in place at the currently operating Rio Turbio mine are not known.
1.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
projects in Argentina, in operation or under development (GMI, 2014). Updates on future CMM
projects in Argentina can be found at https://www.globalmethane.org/coal-
mines/cmm/index.aspx.
1.2.1 CMM Emissions from Operating Mines
Methane emissions in Argentina totaled 16.1 million cubic meters (m3) in 2000. Emissions are
expected to decrease to 9.1 million m3 by 2015, and are then anticipated to increase to 13.3 million
m3 by 2030 (see Table 1-3).
<
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Table 1-3. Argentina's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
16.1
2.8
7.7
9.1
Source: USEPA (2012]
Previously, Argentina's Department of Mining estimated the emission factor could be in the range of
0.8 to 1.2 m3 of methane per tonne of coal (Perczyk, 2006).
1.2.2 CMM Emissions from Abandoned Coal Mines
The five underground operations at Pico Quemado that were active in the 1950s but have ceased to
operate could be a potential source of abandoned mine emissions. However, no data on the
gassiness of the workings or quantifying methane emissions from these are currently available.
1.2.3 CBM from Virgin Coal Seams
No data is currently available on coal bed methane resources in Argentina.
1.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Argentina, a non-Annex I country, has signed and ratified the UNFCCC and the Kyoto Protocol, as
indicated in Table 1-4. While Argentina has numerous Clean Development Mechanism projects
underway of various types (e.g., biomass energy, landfill gas), none of them involve coal bed/mine
methane.
Table 1-4. Argentina's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 12,1992
March 11,1994
Kyoto Protocol
March 16,1998
September 28,2001
Source: UNFCCC (2014]
Argentina is currently in the process of developing a National Strategy on Climate Change to serve
as the framework for mitigation and adaptation measures that reinforce the country's commitment
to fight climate change. During the two first stages of development from 2011 to 2012, a set of
actions were agreed upon among different public agencies and various competencies (i.e., actions)
were assigned to each agency (GMI, 2013).
1.3.1 Market and Infrastructure Factors
Argentina has come a long way from its financial crisis in 2002 when energy prices dipped
dangerously low and the country's economy declined. In response, the Argentinean government
minimized the devaluation effect in the energy sector by freezing tariffs for gas and electricity and
removing taxes from exports. Local producers benefited from frozen tariffs while devaluation
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improved Argentina's competitiveness in the global market The government committed to increase
the regulated tariffs to industrial customers in an agreement signed with natural gas producers in
2004, allowing for gradual recovery of natural gas prices in the country. These strategies of
controlling tariffs helped Argentina emerge as competitive, providing a favorable climate for
investments (Perczyk, 2006).
Argentina also experienced an energy crisis in 2004 in which demand outstripped supply, leading
to a default on a gas export contract with Chile. In an effort to avoid future such scenarios, the
country instituted additional energy sector reforms. It established the Energia Argentina Sociedad
Anonima (ENARSA), a state-owned energy company that will be involved in all aspects of the
energy sector, while the government made plans to liberalize energy pricing and provide
downstream investment incentives (Perczyk, 2006).
The business climate for energy enterprises in Argentina has also improved significantly from the
regional integration of Latin American economies. MERCOSUR'S (South American Common Market
- Argentina, Uruguay, Paraguay, and Brazil) development in 1995 and its subsequent amendments
have spurred the investment climate; MERCOSUR members have achieved the greatest degree of
energy sector integration to date. Power system integration has occurred between Argentina and
Brazil, thereby providing the physical infrastructure necessary to facilitate exchange of electricity
between the two countries. Further, Argentina is a member of Organization Latinoamericana de
Energia, a Latin American Energy Organization, which provides a framework for developing,
integrating, selling etc. of energy resources in the region.
Argentina has also initiated steps to conserve the environment. In 2011, Argentina was South
America's second largest energy consumer and the second largest CO2 emitter from fossil fuel
consumption (EIA, 2014b). With environmental protection growing in importance, the government
has entered into cooperative relationships with the industry to facilitate environmental restoration.
Requirements to repair a legacy of abandoned drilling wells, production mud pits, and leaking
natural gas infrastructure, and to reduce gas-flaring were put in place.
Currently, Argentina has one of the most competitive and deregulated power sectors in South
America. Argentinian government has opened up generation, transmission, and distribution to the
private sector, and guarantees suppliers access to the grid. In a bid to meet its increasing electricity
demands, Argentina sought to expand its thermal generation capacity and released a tender in 2006
for a new 240-MW coal-fired power plant in Santa Cruz province, the Rio Turbio power plant
(PennEnergy, 2014). The Rio Turbio plant will be the country's first 100 percent coal-fired power
plant, and YCRT hopes to stockpile enough coal from its Rio Turbio mine to run the plant for two
years.
These changes in business environment and government requirements are creating a favorable
market for CMM development in Argentina. An added incentive is Argentina's substantial gas-in-
place resources. With natural gas being Argentina's primary energy source and with the third
largest gas reserves in South America, there is an extensive pipeline network not only domestically
but to the neighboring countries of Chile, Bolivia, Brazil, and Uruguay that could provide access to
both domestic and international markets for gas produced from coalfields (EIA, 2014b). Argentina
already has several landfill methane projects on the ground. A starting point for identifying and
quantifying CMM/abandoned mine methane development potential in Argentina would be
gathering basic information on the methane content of Argentinean coals. Similarly, site-specific
data on methane emissions from individual mines, active and abandoned, would be required.
A
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1.3.2 Regulatory Information
While ownership of most minerals in Argentina does not rest with the surface owner, the national
government nevertheless is bound to grant a mining license to the discoverer of new deposits. In
return, the licensee pays an annual royalty, invests a minimum amount of capital, and can execute
reasonable exploitation (MEOSP, nd).
In the natural gas sector, gas distribution is enhanced by open access to the distribution pipeline
system for producers and distributors, with transport rates regulated by ENARGAS (Natural Gas
Regulatory Authority). Gas users may build a pipeline at their own cost, connect it to the
distribution network, and purchase gas directly from producers to avoid distribution costs (MEOSP,
nd).
The following federal bodies regulate environmental compliance: Secretaria de Mineria
(Department of Mining), Secretaria de Ambiente y Desarrollo Sostenible (Department of
Environment and Sustainable Development), and Secretaria de Energia (Department of Energy).
Provincial authorities also play a role in ensuring environmental compliance, having established
their own policies that largely mirror the federal requirements.
1.4 Profiles of Individual Mines
Rio Turbio Mines
General Overview
Rio Turbio, an active mine located in the Austral Basin in Santa Cruz Province in southern
Argentina, is considered to be developed in an extension of the Magallanes Basin to the west (in
Chile).
General Information
Total mineable reserves (thousand tonnes]
750,000
General Geologic Information
Number of coal seams above currently mined
None. Five coal-bearing units (mantos] are present: Manto
Inferior (lowermost]; Manto Superior, Manto B, Manto A, and
Manto Doreta (uppermost]. At present, only Manto Doreta (1.92
m thick] is being mined.
Aggregate thickness of coal seams above currently
None
mined
Geologic and Mining Conditions
Rank of coal
Bituminous
Pitch, degrees
5-10 degrees, east dipping
Ash content, % (coal in place, run-of-mine]
12.05%
Moisture, % (coal in place, run-of-mine]
7.65%
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Coal Production, Methane Emissions, and Degasification (and Use) Statistics
1990
1991
1992
1993
1994
1995
1996
Coal Production (million tonnes] 0.28 0.29 0.20 0.16 0.14 0.30 0.31
Methane Emissions (bm3] 0.13 N/A N/A N/A N/A 0.007 N/A
1997
1998
1999
2000
2001
2002
2003
Coal Production (million tonnes] 0.25 0.29 0.35 0.26 0.19 0.04 0.20
Methane Emissions (bm3] N/A N/A N/A 0.018 N/A N/A N/A
Source: Perczyk, 2006
Pico Quemado Mines
General Overview
This mine, located in the south central part of the country, is currently abandoned.
General Information
Total mineable reserves (thousand tones]
75,000 (estimated as regional total less Rio Turbio reserves]
General Geologic Information
Number of coal seams above currently mined
N/A; volcanic intrusions overlay the coal seams
Faults?
Yes, minor
Geologic and Mining Conditions
Ash content, % (coal in place, run of mine]
47.03%
Moisture, % (coal in place, run of mine]
17.61%
Coal Production, Methane Emissions, and Degasification (and Use) Statistics
1990
1991
1992
1993
1994
1995
1996
Coal Production (million tonnes]
None
None
None
None
None
None
None
Degasification
None
None
None
None
None
None
None
1997
1998
1999
2000
2001
2002
2003
Coal Production (million tonnes] None None None None None None None
Degasification None None None None None None None
Source: Perczyk (2006]
1.5 References
Brooks and Willett (2004): Update: World Coal Quality Inventory - Argentina, William E. Brooks and Jason C.
Willett, U.S. Geological Survey, Reston, Virginia, Open-File Report, 2004.
http://pubs.usgs.gov/of/2004/1022/lQ22.html
CIA (2014): The World Factbook - Argentina, Central Intelligence Agency, accessed July 2014.
https://www.cia.gov/library/publications/the-world-factbook/geos/ar.html
EIA (2014a): International Energy Statistics, U.S. Energy Information Administration, Washington, DC, data
accessed July 2014. http: IIwww.eia.gov/cfapps /ipdbproi ect/1ED Index3.cfm
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EIA (2014b): Country Analysis Note - Argentina, U.S. Energy Information Administration, Washington, DC,
last updated April 2014. http://www.eia.gov/countries/country-data.cfin?fips=AR
GMI (2013): Argentina Country Update, presented at Global Methane Initiative Steering Committee Meeting,
March 2013. https://www.globalmethane.org/expo-
docs/canada!3/steer Argentina March2013 SC update.pdf
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
IEA (2013): Share of Total Primary Energy Supply in 2011 - Argentina, International Energy Agency, 2013.
http: / /www.iea. org /stats / WebGraphs /ARG E NTINA4.p df
MEOSP (nd): Investment Opportunities, Ministerio de Economi'a y Obras y Servicios Publicos, The Consulate
General of the Republic of Argentina in Montreal, not dated.
http://www.oceandocs.net/bitstream/1834/2 606/l/Rev%20Invest%20INIDEP%2 013.pdf
M2M (2005): Methane to Markets Partnership, Argentina, Coal Mine Methane, presented at the Methane to
Markets Regional Workshop, Beijing, China, 2 December 2005.
PennEnergy (2014): "Argentina's first fully coal-fired power plant nears completion," PennEnergy, 28
February 2014. http://www.pennenergy.eom/articles/pennenergy/2014/02/argentina-s-first-fully-
coal-fired-power-plant-nears-completion.html
Perczyk (2006): Coal Industry Situation in Argentina, Daniel Perczyk, Instituto Torcuato Di Telia, 2006.
https://www.globalmethane.org/documents/events coal 20060525 argentina.pdf
UNFCCC (2014): Ratification Status - Argentina, United Nations Framework Convention on Climate Change,
accessed July 2014. http: //maindb.unfccc.int/public/country.pl?country=AR
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
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2 Australia
*
2.1 Summary of Coal Industry
2.1.1 Role of Coal in Australia
Australia is the fifth largest producer of coal in the world, behind China, the United States, India, and
Indonesia. Although rich in energy resources with significant petroleum, natural gas, and coal
reserves, its energy consumption is dominated by coal, which fuels most of the country's power
generation. In 2011, coal accounted for 69 percent of the country's electricity generation (IEA,
2013). This is a decrease from previous years where coal has consistently accounted for 75 percent
of power generation.
Australia ranks fifth in black coal (all non-lignite coal) production, with its current economic
reserves estimated to sustain production for the next 200 years. About 97 percent of Australia's
black coal production comes from Queensland and New South Wales (NSW) with very small
production in Tasmania and Western Australia, and it ranks second in metallurgical coal
production. Australia also produces about 8 percent of the world's brown coal and ranks third after
Germany and Russia. All of its brown coal (lignite) production comes from Victoria, with more than
98 percent sourced from the LaTrobe Valley (ACA, 2009; M2M - Australia, 2005; WCA, 2013;
UNFCCC, 2014a).
Australia is the world's second largest coal exporter. It exported 301 million tonnes (Mmt) in 2012,
comprising 24 percent of total world coal exports. As of 2012, Australia exported about 70 percent
of its annual coal production, with the largest share going to Japan. Other markets included Taiwan,
South Korea, China, and India (WCA, 2013; UNFCCC, 2014a).
Table 2-1 quantifies Australian coal reserves and recent production.
Table 2-1. Australia's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million
tonnes)
Sub-
bituminous &
Lignite
(million
tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2012]
Annual Coal Production (2012]
37,100
317,3*
39,300
113.4*
76,400
430.7*
4 (8.9%]
5 (5.4%]
Sources: BP (2013]; *IEA (2013]
Australia has large deposits of both brown and black coals, located on the east coast in the states of
Queensland, NSW, and Victoria (see Figure 2-1). In NSW, the principal coal fields are the Southern,
Newcastle, Hunter, and the Western NSW. In Queensland, the main coal fields are the Northern
Bowen Basin, the Central Bowen Basin, and the Southern Basin. Since 1990, there has been strong
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growth in production from the Hunter and Bowen Basins and declines from the Southern and
Newcastle Basins (IJNFCCC, 2014a], Hard coal reserves are located primarily in NSW (37 percent]
and Queensland (59 percent] (EIA, 2009], The Bowen Basin in Queensland contains the largest
reserves at 37.8 billion tonnes (Bt], Reserves in the Sydney-Gunnedah Basin and surrounding areas
of northern NSW contain about 32.1 Bt (EIA, 2009], Minor reserves are also located in Southern and
Western Australia, as well as Tasmania (USGS, 2002],
Figure 2-1. Australia's Coal Fields
750 km
J
MARYBOROUGH
BASIN
PERTH BASIN
PERTH
Coal-Seam Gas Potential
Brown coal basin
Black coal basin
Major coal-seam gas
Coal-seam gas
production area
Gas pipeline
Gas pipeline (proposed)
exploration area
Source: Australian Gas Resource Assessment [2012]
GLOUCESTER
BASIN
(CSG exploration)
SYDNEY
SYDNEY BASIN
MELBOURNE OAKLANDS BASIN
GIPPSLAND BASIN
TASMANIA BASIN
HOBART
2.1.2 Stakeholders
Table 2-2 identifies potential key stakeholders in Australian coal mine methane (CMM]
development.
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Table 2-2. Key Stakeholders in Australia's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
¦ BHP-Billiton
¦ Rio Tinto (Coal & Allied Industries Limited; Pacific Coal]
¦ GlencoreXstrata
¦ Anglo Coal
¦ Peabody Energy
¦ Vale
¦ Ensham Resources
¦ Anglo Coal Australia Pty Ltd
¦ Illawarra Coal Holdings Pty Ltd
¦ Planet Gas Ltd.
¦ Centennial Coal
Project hosts /
potential project hosts
Developers
¦ Arrow Energy
¦ BG Group
¦ Santos
¦ Queensland Gas Company (QGC] - a BG subsidiaiy
¦ Petronas
¦ Energy Developments Ltd.
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Project opportunity
identification and
planning
Equipment Manufacturers
¦ BCCK
¦ BOC Gases
¦ Caterpillar
¦ ComEnergy
¦ Cummins Engine
¦ Engelhard
¦ Ingersoll-Rand
¦ MEGTEC Systems
¦ Northwest Fuels Development
¦ Solar Turbines
¦ Waukesha Engines
Methane treatment and
utilization equipment
Engineering, Consultancy,
and Related Services
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
Natural Gas Transmission
& Distribution Companies;
Power Companies
¦ Stanwell Corporation
¦ CS Energy
¦ Tarong Energy Corporation
¦ AGL Energy
¦ Epic
¦ Ergon
¦ Energex
Universities, Research
Establishments
¦ Australian Coal Association Research Program
¦ Commonwealth Scientific and Industrial Research
Organization (CSIRO]
¦ Energy Development Limited
Technical assistance
Regulatory Agencies
¦ Queensland Department of Natural Resources and Mines
¦ NSW Department of Primary Industries Minerals
Project identification
and assessment
support
Government Groups
¦ Department of Industry, Tourism, and Resources
¦ Australian Greenhouse Gas Office
¦ Department of Environment, Water, Heritage, and the
Arts
Licensing and
permitting
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Table 2-2. Key Stakeholders in Australia's CMM Industry
Stakeholder Category
Stakeholder
Role
Other
¦ Large-scale industrial applications
¦ Fertilizer plants (Incitec]
¦ Retail consumers
2.1.3 Status of Coal and the Coal Mining Industry
Australia's coal production has increased by 88 percent over the last two decades, with more
operations coming online every year (BP, 2013). There were 137 coal mines operating in 2012,
located across Australia: 89 open pit and 48 underground operations (UNFCCC, 2014a).
Underground mines account for 59 percent of coal production in NSW and 10 percent of coal
production in Queensland. Table 2-3 breaks up Australia's coal production by mining method and
region (ACA, 2009).
In addition to Australian private mining companies, international companies also play a large role
in Australian coal production. Major coal companies operating in Australia include: BHP-Billiton,
Rio Tinto Coal, GlencoreXstrata, Peabody, Vale, and Anglo Coal. Australia mostly produces high-
quality coking and steaming coals that are high in energy content and low in sulfur, ash, and other
contaminants.
Table 2-3. Australia's Coal Production by Mining Method and Region (Mmt)
Black Coal
(Raw Production)
2006/07
2007/08
2008/09
2009/10
2010/11
2011/12
2012/13
NSW
130.9
135.0
137.8
147.3
157.0
167.2
185.6
Queensland
184.1
180.5
190.5
208.9
179.8
188.2
202.7
South Australia
3.9
3.9
3.6
3.8
3.7
2.6
2.2
Western Australia
6.0
6.2
7.0
6.7
7.2
7.0
7.5
Tasmania
0.4
0.4
0.4
0.4
0.4
0.3
0.4
Total Production
325.2
326.0
339.3
367.1
348.1
365.3
398.4
Source: BREE (2014]
2.2 Overview of CMM Emissions and Development
Potential
Globally, Australia ranks fifth in annual CMM emissions behind China, the United States, Russia and
Ukraine. By 2020, however, Australia's emissions are expected to surpass Ukraine's (USEPA, 2012).
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Although Australia's coal production has doubled since 1990, CH4 emissions have not grown as fast.
Production from surface mines is increasing at a faster rate than coal production at underground
mines, and there is a decreasing share of underground production from the gassiest southern NSW
coalfield according to the Australian National Inventory (UNFCCC, 2014a).
2.2.1 CMM Emissions from Operating Mines
In 2012, net emissions associated with coal mining and handling and decommissioned mines were
24.9 metric tons of carbon dioxide equivalent (MTCC^e) and accounted for 4.6 percent of Australia's
total net greenhouse gas (GHG) emissions of 543.6 MTCC^e (UNFCCC, 2014a). Coal sector methane
emissions increased 44 percent between 1990 and 2012, while coal mine production doubled.
Emissions per 1000 tonnes of coal produced decreased by 29 percent from 82 MTCC^e to 58
MTC02e over the same time period and this reduction is primarily attributed to the mining of less
gassy coal reserves and the expanding implementation of methane recovery, use, and flaring
technologies (BP, 2013; UNFCCC, 2014a).
The Australian government estimates that ventilation air methane (VAM) is responsible for 60
percent of Australia's underground coal mine emissions, with a typical gassy mine producing VAM
at a rate of 150 to 300 cubic meters/second(m3/s) (M2M - Australia, 2005). Figure 2-2 shows
Australia's CMM emissions (including emissions from abandoned mines) from 1990-2012.
Figure 2-2. Australia's Fugitive Emissions from Coal Mining, 2000-2012
~ Underground mining - active ~ Underground - post-mini ng ~ Surface mining - active ¦ Abandoned Mi nes
Source: Australian Government Department of the Environment (2012]
Table 2-4 shows Australia's historic and projected CMM emissions.
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Table 2-4. Australia's CMM Emissions 2000-2012 (million cubic meters)
Emission Category
2000
2005
2010
2015
(projected)
Underground mining - active
1,030
966
1,035
Underground - post-mining
46.01
43.36
58.87
Surface mining - active
329.18
486.59
559.46
Surface - post-mining
N/A
N/A
N/A
Abandoned Mines
54.99
99.02
66.28
TOTAL
1,460.18
1,594.97
1,719.61
2,069.97*
Sources: UNFCCC (2014a]; *USEPA (2012]
There are currently 25 CMM projects registered in Australia at 19 mines, 14 of which are active
underground mines and 5 are abandoned mines. Nine of the projects involve flaring recovered gas;
10 projects generate electricity using reciprocating engines; three projects destroy VAM, two
projects involve injection of high quality CMM into a sales pipeline, and there is one boiler fuel
project (GMI, 2014a).
Nine projects use CMM to generate 215 MW of electricity sold into the national grid, and the Clean
Energy Future Plan has a goal of a five percent reduction on 2000 levels GHG emissions by 2020
(GMI -Australia, 2013). The largest CMM power station is located at BHP Billiton's Appin and
Tower mines near Sydney. Commissioned in 1996, this project consists of 94 1-MW reciprocating
engines and consumes 600,000 m3 of CMM a day. Other large power plants, built and operated by
Energy Developments Ltd., include a 32MW project at the German Creek coal mine (uses 16 2MW
engines and came on-line in November 2006) and the $60 million 45MW plant at Anglo's Moranbah
North coal mine (uses 15 3MW engines and started operation in late 2008). Both of these plants are
located in the Bowen Basin in central Queensland (Energy Developments, 2010).
In one landmark CMM project, BHP Billiton was awarded up to $6 million from the Australian
Greenhouse Office (AGO) to construct a CMM power station at the West Cliff Colliery, near
Wollongong NSW, to allow the combustion of very dilute methane contained in coal mine
ventilation air (also known as VAM) (BHP, 2010). The West Cliff VAM Project (WestVAMP) officially
opened on 14 September 2007 and was the first to generate commercial power solely from VAM.
The project burns 0.9 percent VAM concentration to produce 6 MW of electricity via a conventional
steam turbine. Along with displacing coal-fired electricity generation, WestVAMP is estimated to
reduce emissions by up to 0.250 million MTC02e each year (MEGTEC, 2008; 2010).
2.2.2 CMM Emissions from Abandoned Coal Mines
The latest report on Australia's GHG emission trends, released by the Department of Climate
Change, notes that emissions from decommissioned mines are small (relative to total emissions), at
0.53 MTC02e in 2012 (UNFCCC, 2014a). Emission levels vary with mine closures, but are projected
to be 1.3 MTC02e in 2020 (DCC, 2009).
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2.2.3 CBM from Virgin Coal Seams
Australia has the most active development of unconventional gas outside of North America. Coal
bed methane (CBM) recovery activity has been focused predominately in NSW and Queensland,
Australia's two largest coal-producing states, with 97 percent of CBM production occurring in
Queensland and 3 percent in the Sydney Basin of NSW (IEA, 2012). Exploration for CBM is also
occurring in Victoria (M2M - Australia, 2005). Drained CBM has been used to generate electricity in
NSW since the 1980s, while commercial CBM production began in Queensland in 1996, providing
pipeline-quality gas to three coastal cities (Schwochow, 1997).
Annual CBM production in Australia more than doubled between 2003 and 2006, from 538 million
m3 to 1.6 billion m3 (Bern). The rapid rate of increase in production has continued with 2.9 Bern
produced in 2007, 3.7 Bern in 2008, and 5.2 Bern in 2011 (AIMR, 2014). In 2003, CBM accounted for
3 percent of Australia's total gas production. By 2010, CBM's share had increased to 10 percent
(AIMR, 2014). At the same time, proved and probable reserve estimates have risen rapidly to 934
Bern (33 Tcf) in 2011 with 92 percent of reserves located in Queensland and the rest in NSW (AIMR,
2014). At current production this is a 150 year reserve life. Total CBM resources including
Economic, Subeconomic, and Inferred Resources (JORC Code) was 5.75 Tcm (203 Tcf) in 2012
(Australian Gas Resource Assessment, 2012).
In 2011, 97 percent of Australia's CBM production came from the Bowen and Surat Basins in
Queensland representing 88 percent of Queensland's gas production for that year (Queensland,
2014). Analysts believe CBM could provide up to 50 percent of the Australian east coast natural gas
supply by 2020 (AIMR, 2009).
During 2012-2013, CBM exploration in Queensland continued at record levels with about 1315
CBM wells drilled (Queensland, 2014). The Bowen, Galilee and Surat Basin continue to be the main
areas of focus, while the Sydney, Gunnedah, Gloucester and Clarence-Morton Basin are being
targeted in NSW.
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Figure 2-3. Location of Australia's Coal Seam Reserves
Gas pipeline
Gas pipeline (proposed)
CSG-LNG processing plant
(under construction)
I I
0 750km
1 I
CLARENCE-
MORETON BASIN
Cost sear gas 42B
GUNNEDAH BASIN
Coal scam gas -1530
GLOUCESTER BASIN
CoaJ scan gac 655
SYDNEY BASSN
Coai ieam gas 227
40" -
12-6135-19
SURAT BASIN
Coa gas 24 &71
20"-
| | Coal seam gas basin
Coal seam gas
~ Coai seam gas EDR
as at 2010 in PJ
Source: Australia Gas Resource Assessment (2012]
Driving much of the recent CBM activity, several major international companies have acquired
stakes in Australia's CBM industry with plans to convert CBM into liquid natural gas (LNG) for
export to the energy hungry markets of Southeast Asia. The BG Group, Santos Ltd. (with Petronas),
ConocoPhilips (with Origin Energy), and Royal Dutch Shell are planning four separate CBM-to-LNG
projects in Queensland (Dow Jones Newswires, 2010).
For details on all ongoing CBM operations and the vested companies, visit the Australian Mines
Atlas at http://www.australianminesatlas.gov.au/aimr/commodity/coal bed methane 09.jsp.
2.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Australia is a signatory to the UNFCCC and ratified the Kyoto Protocol in 2007 (see Table 2-5).
Australia is committed to meeting its Kyoto target to reduce GHG emissions by 5 percent below
2000 levels by 2020 as well as a very ambitious internal target of 80 percent reduction of 2000
levels by 2050 (Calder, 2011).
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Table 2-5. Australia's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 4,1992
December 30,1992
Kyoto Protocol
April 29,1998
December 3,2007
Source: UNFCCC (2014b]
Having ratified the Kyoto Protocol, Australia is now able to take advantage of the revenues
generated by its carbon emission reductions. Other opportunities for project financing include the
Greenhouse Gas Abatement Program (GGAP), providing up to $43.47 million to support the
development of power stations using CMM. GGAP aims to reduce Australia's net GHG emissions by
limiting emissions to 108 percent of 1990 levels between 2008 and 2012. The country is on track to
meet this target The Australian government is funding four CMM projects (for seven individual
power stations) in Queensland and NSW under the GGAP (IEA, 2009).
Australia's Carbon Pricing Mechanism (CPM) came into effect on 1 July 2012. Regulated entities
were required to pay a fixed price for their emissions until 1 July 2015, when the carbon price will
change to a market-determined floating price. The carbon pricing mechanism covered a range of
large business and industrial facilities. The carbon price was fixed for the first three years of the
CPM. In 2013-14, it was AUS$24.15 a tonne.
In April 2014, the Liberal Government, elected in 2013, released a white paper offering an
alternative to the CPM, and in July 2014, Australia's Senate repealed the CPM.
The white paper proposes to replace the CPM with an Emissions Reduction Fund of AUS$2.55
billion, part of the Government's Direction Action Plan. Under the proposed incentive-based plan,
emission reduction projects would be voluntary and the project sponsors would offer emission
reductions to be generated by the project in an auction. Actual emission reductions would be
purchased by the Government as they are generated using the Emissions Reduction Fund (ERF).
The proposed scheme is similar to approaches being considered in other markets, collectively
referred to as Results Based Financing.3 However, international offsets will not be accepted into the
ERF.
Technical working groups have been established to develop methodologies for certain source
categories including CMM. Sources with straightforward methods that can be developed quickly are
being prioritized so that those methodologies are being developed first CMM, in particular, is noted
in the White Paper as an example because emissions are already covered under the National
Greenhouse and Energy Reporting Scheme. The CMM methodology will reportedly cover the
capture and flaring and/or electricity generation at underground and open cut mines and, in time,
VAM oxidation at active underground mines. It will use existing factors used under the National
Greenhouse and Energy Reporting (NGER) Scheme to directly measure the amount of methane
captured and destroyed (Australia Ministry of Environment, 2014).
On 31 October 2014, the Australian Senate passed the Carbon Farming Initiative Amendment Bill
2014. The Bill will take effect once passed by the House as amended. This will establish the
3 See World Bank:
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Emissions Reduction Fund. The Clean Energy Regulator will begin administering the scheme once
legislative amendments start and the necessary legislative rules are made (Department of
Environment, 2014).
Australia has included coal seam methane in its Renewable Energy Target definition for a
transitional period to greater renewable production (Renewable Energy, 2010). Aside from the
federal level support for CMM/CBM development, the governments of NSW and Queensland
provide further incentives for their development Queensland is promoting a transition to gas
supplies via its Smart Energy Policy. Starting in 2010,15 percent of all electricity sold in
Queensland has to be from gas-fired generation, which may be increased to 18 percent by 2020
(Smart Energy, 2010). NSW has had a Greenhouse Gas Reduction Scheme since 2003 that
encourages a switch from coal-based energy production to natural gas-based production, including
CBM/CMM (GHG Reduction, 2010).
2.3.1 Market and Infrastructure Factors
Although Australia's CMM development has been primarily driven by mine safety concerns, the
industry has received a boost from the country's GHG emissions reduction obligations and
accompanying incentives from the national government (see GGAP discussion in section 2.1). State-
based schemes have also provided additional incentives to encourage a shift in energy use towards
natural gas, including CBM and CMM.
Electricity generation has provided the main market for drained CMM and based on expected
growth in the industry, there is potential to double generating capacity over the next decade (GMI,
2014a). Growth in the coal mining industry is robust with six new coal mine projects, valued at
more than $1.5 billion, completed in 2008-2009, and a further twenty-one projects scheduled for
completion in the near to medium term (ACA, 2009).
While Queensland produces more than 90 percent of CBM volumes, NSW coal basins hold greater
potential for CMM development with greater coal production from underground mines in NSW than
in Queensland (51.6 Mt versus 30.8 Mt, respectively) (NSWMC, 2009; GSQ, 2010) and generally
gassier mines. With natural gas infrastructure in place and serving the Sydney-Newcastle corridor,
local major energy markets are conveniently accessible.
In contrast with eastern NSW, gas transport infrastructure is more limited in Queensland, and CBM
projects have historically been sited near existing gas pipelines, such as the 750 km Wallumbilla-
Ballera pipeline which connects the gas fields of the Cooper Basin to eastern Queensland. But major
pipeline projects are in development, driven by planned CBM to LNG projects. The BG Group is
planning a 380 km underground pipeline from the Surat Basin to the port of Gladstone to deliver
CBM to its proposed LNG plant Additional pipeline capacity will be built to link BG's CBM resources
to the new transmission pipeline. In 2009, BG Group signed an LNG Project Development
Agreement with China National Offshore Oil Corporation (CNOOC) who is the intended customer
for the produced LNG (BG Group, 2010). Santos Ltd reports that itplans to upgrade field
infrastructure at the Fairview CBM field and also build a pipeline to Gladstone as part of its
proposed CBM to LNG project (OGJ, 2010).
Major pipeline operators such as Epic Energy and the APA Group have been active in expanding the
capacity of existing pipelines in Queensland and NSW, adding compression facilities, building links
A
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between the major pipelines and adding new inlet stations to receive CBM from new production
areas (AGL, 2009; APA, 2010).
Australia has been a world leader in work on the development and trial of technologies to capture
and use CMM, VAM, and CBM. Commonwealth Scientific and Industrial Research Organization
(CSIRO), Energy Development Limited, and BHP Billiton, are some of the Australian organizations
who have conducted research, development, and demonstration work related to the recovery and
utilization of CMM and VAM.
BHP Billiton's WestVAMP project (see section 2.2.1) was the first commercial demonstration using
a thermal flow-reversal oxidizer for VAM-fueled power generation, while CSIRO has funded the
development of new lean-fuel catalytic gas turbines designed to capture 1 to 2 percent of methane
from ventilation air (VAMCAT). The first trial of the technology, sponsored by AGO, took place at the
Huainan mine in China. Other VAM mitigation technologies being researched include catalytic flow
reverse reactors; catalytic monolith combustors; and recuperative gas turbines.
CSIRO is also investigating enhanced CBM techniques to increase methane drainage from coal
seams before opencast mining takes place. Other research topics include gas drainage systems
improvement and cogeneration of electricity using CMM in coal fired power plants (M2M -
Australia, 2010; M2M - Australia, 2005).
Other important projects in which the Australian Governmenthas invested include (GMI, 2014b):
¦ The University of Newcastle VAM Abatement Safety Project demonstrating large-scale VAM
capture duct complete with safety control measures and supporting design and testing
information and understanding the underlying scientific and engineering principals behind
methane ignition, deflagration, and detonation. Australian Government funding is AUS $12.5
million and total project value is AUS $27 million.
¦ The University of Newcastle Chemical Looping VAM Abatement Project investigating
mitigation of VAM flows at concentrations ranging from 0.005 percent to 2.0 percent using a
l-m3/s VAMCO prototype and then a 10 m3/s pilot scale demonstration unit. Australian
Government funding is AUS $2.7 million and total project value is AUS $8.5 million.
¦ Glencore Coal Australia Methane Capture and Abatement Optimization to increase the
longwall gas capture efficiency from 60 percent to 80 percent. Site characterization,
monitoring and measurement, a fundamental modeling study and development are mostly
completed.
2.3.2 Regulatory Information
The legal framework governing resource ownership and licensing in Australia is complex because
there is currently no national legislative framework in place for CMM. Each state has its own
legislation and licensing arrangements.
In Queensland, a Mining Lease for coal does not provide rights to the contained coal seam gas. CMM
production comes under the Petroleum and Gas (Production and Safety) Act of2004 and requires a
Production License which can co-exist with a Mining Lease covering the same area. The Queensland
government had released a new regimen in November 2002 to address issues that arise where CBM
and coal exploration and production activities may occur under different tenures granted over the
same area. To implement the regimen, a new Petroleum and Gas (Production and Safety) Act was
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passed in 2004 to replace the Petroleum Act of1923. Recent amendments to legislation in
Queensland have established a clear distinction between resources administered under the Mineral
Resources Act of1989 and those coming under the Petroleum and Gas (Production and Safety) Act of
2004.
In NSW, a Mining Lease or Exploration License is required before mining operations commence. If
the holder of the lease wants to extract coal seam gas, an application must be made for the inclusion
of petroleum in the Mining Lease. Although CMM extraction and utilization currently falls under a
coal extraction or Mining Lease, more specific regulation is being drafted. The Mining Act of1992 is
the principal legislation governing mineral exploration in NSW. Under the Mineral Resources Act
1989 (NSW), where CMM is produced as a by-product of coal mining, there is no provision for
payment of royalties on VAM, or on pre- or post-drainage methane that is flared. Waste methane
flaring in NSW has been standard, but further legislative changes to the Mineral Resources Act now
require that pre- and post-drainage methane is used or flared rather than simply being vented. CBM
is however considered a petroleum product in NSW and hence, falls under the Petroleum (Onshore)
Act of 1991.
In Queensland, where an oil and gas exploration tenement co-exists with a coal mining lease, and
production testing within that exploration tenement yields in excess of 3 million m3 of gas, the
tenement holder is liable for royalty payments. However, in order to facilitate the development of
deep coal seams in and around Sydney, the NSW state government has not been imposing royalties
on the capture and utilization of waste gases from coal mining and is providing a 5-year exemption
for stand-alone coal seam gas operations.
In Victoria, CBM resources are administered under the legislation for mineral resources
development.
2.4 Profiles of Individual Mines
Some of Australia's most productive underground coal mines are listed in Table 2-6.
Table 2-6. Major Australian Underground Coal Mines
Mine
Location
Operator
Annual Coal
Production
(million tonnes)
Broadmeadow
Bowen Basin, Queensland
BMA (BHP Billiton Mitsubishi Alliance]
4
Moranbah North
Bowen Basin, Queensland
Anglo Coal
4.5
German Creek mines
Bowen Basin, Queensland
Anglo Coal
6
Kestrel
Bowen Basin, Queensland
Rio Tinton Coal Australia
4
North Goonyella
Bowen Basin, Queensland
Peabody Energy
2-3
Oaky Creek
Bowen Basin, Queensland
Xstrata
11 (rom]
Beltana
Hunter Valley, NSW
Xstrata
7.6
Clarence
Western Coalfield, NSW
Centennial Coal
2.5
Springvale
Western Coalfield, NSW
Centennial Coal
7
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2.5 References
ACA (2009): Black Coal Australia - Statistical Summary, Australian Coal Association, 2009.
http://www.australiancoal.com.au/
AGL (2009): Opening of major expansion of eastern Australian gas grid by AGL Energy and Epic Energy, AGL
Energy website, 11 May 2009. http: //agl.com.au/about/media/archive/Pages/May09.aspx
AIMR (2009): Coal Bed Methane Fact Sheet, Australia's Identified Mineral Resources, Australian Atlas of
Mineral Resources, Mines and Processing Centres, 2009.
AIMR (2014): Coal Seam Gas Fact Sheet, Australia's Identified Mineral Resources 2012, Australian Atlas of
Mineral Resources, Mines and Processing Centres, 2014.
http: / /www.australianminesatlas.gov.au/education /fact sheets/coal seam gas.html
APA (2010): Gas transmission & distribution - Queensland, NSW, APA Group website, accessed August 2010.
http://apa.com.au/our-business/gas-transmission-and-distrihution.aspx
Australian Gas Resource Assessment (2012): Bureau of Resources and Energy Economics, 2012.
http://www.ga.gov.au/corporate data/74032/AustralianGasResourceAssessment2012.pdf
Australia Ministry of Environment (2014): Emissions Reduction Fund White Paper, April 2014.
http://www.environment.gov.au/topics/cleaner-environment/clean-air/emissions-reduction-fund
BG Group (2010): BG Group Operations website, accessed August 2010. www.bg-group.com
BHP (2010): WestVAMP, BHP Billiton website, accessed June 2010.
http://www.bhpbilliton.eom/bb/ourBusinesses/metallurgicalCoal/illawarraCoal/aboutillawarracoal/w
estvamp.isp
BP (2013): Statistical Review of World Energy, June 2013.
http://www.bp.com/content/dam/bp/pdf/statisticalreview/statistical review of world energy 2013.p
df
BREE (2014): Energy in Australia 2013 and supporting data, Bureau of Resources and Energy Economics,
Government of Australia, 2014. http://www.bree.gov.au/publications/energv-australia
Calder (2011): Clean Energy Future: Australia's Climate Change Plan, Wayne Calder, Australia Department of
Resources, Energy and Tourism, presented to GMI Coal Subcommittee, Krakow, Poland, 14 October 2011.
https://www.globalmethane.org/documents/events coal 101411 tech calder.pdf
DCC (2009): Tracking to Kyoto and 2020, Australia's Greenhouse Emissions Trends, 1990 to 2008-2012 and
2020, Department of Climate Change, Canberra, Australia, August 2009.
Department of the Environment (2012): National Inventory Report 2012, Volume 1, Department of the
Environment, Australian Government, 2012. http://www.environment.gov.au/climate-
change/greenhouse-gas-measurement/publications/national-inventorv-report-2012
Department of the Environment (2014): Emission Reduction Fund, Department of the Environment,
Australian Government, 2014. http: //www.environment.gov.au/climate-change/emissions-reduction-
fund
Dow Jones Newswires (2010): BG Group Project Approved by Australia's Queensland State by Ross Kelly,
Dow Jones Newswires, 24 June 2010. http: //www.foxbusiness.eom/markets/2010/06/24/bg-group-lng-
proiect-approved-australias-queensland-state/
EIA (2009): Country Analysis Brief: Australia - Coal, U.S. Energy Information Administration, Washington, DC,
September 2009.
Energy Developments (2010): German Creek and Moranbah North poject fact sheets, Energy Developments
website, accessed August 2010. http: //www.energydevelopments.com/01 cms/details.asp?ID=4
A
Methane Stive CMM Country Profiles 24
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AUSTRALIA
GHG Reduction (2010): Greenhouse Gas Reduction Scheme, New South Wales Government, Australian
Government, accessed 30 July 2010. http: //www.greenhousegas.nsw.gov.au
GMI - Australia (2013): Australian Coal Action Plan, Global Methane Initiative, 2013.
https://www.globalmethane.org/documents/coal cap australia.pdf
GMI (2014a): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed
September 2014. https: //www.globalmethane.org/coal-mines/cmm/index.aspx
GMI (2014b): Australian Coal Sector Update, presented to the 20th Session of the Global Methane Initiative
Coal Subcommittee, 22 October 2014.
http://www.unece.org/fileadmin/DAM/energy/se/pp/coal/cmm/9cmm gmi ws/2 AUSTRALIA.pdf
GSQ (2010): Queensland's Coal - Mines and Advanced Projects - Industry Update, Department of
Employment, Economic Development and Innovation, Geological Survey of Queensland, June 2010.
IEA (2009): Coal Mine Methane in Russia - Capturing the Safety and Environmental Benefits, International
Energy Agency, Paris, France, 2009. http: //www.iea.org/papers/2009 /cmm russia.pdf
IEA (2012): Australia: Energy Policies of IEA Countries, International Energy Agency, Paris, France, 2012.
https://www.iea.org/countries/memhercountries/australia/
IEA (2013): Australia: Coal for 2012, International Energy Agency, Paris, France,
2013.http://www.iea.org/statistics/statisticssearch/report/?country=AUSTRALI&product=coal&year=2
012
M2M - Australia (2005): Methane to Markets Partnership Coal Mine Methane Technical Subcommittee Country
Specific Profile - Australia, Australian Government, Department of Industry, Tourism and Resources &
Department of the Environment and Heritage, 2005.
http://www.methanetomarkets.org/documents/events coal 20050427 australia profile.pdf
M2M - Australia (2010): Australia's Experience and its Impact on Coal Mine Methane Project Development,
presented by John Karas at the Methane to Markets Partnership Expo, New Delhi, India, March 2010.
http: //www.methanetomarkets.org/expo/docs/postexpo/coal karas.pdf
MEGTEC (2008): MEGTEC Wins 2008 EPA Climate Protection Award, MEGTEC, 21 May 2008.
http://www.megtec.com/news article.php?news id=40
MEGTEC (2010): MEGTEC to build world's largest coal mine ventilation methane emissions abatement
system in China, MEGTEC, 8 June 2010. http: //www.megtec.com/news article.php?news id=58
Mineral Resources (2009): Australia's Identified Mineral Resources 2009, Geoscience Australia, Australian
Government, 15 December 2009. http: //www.ga.gov.au/servlet/BigObiFileManager?bigobiid=GA16805
0GJ (2010): Santos lets contract for CSG-LNG project in Queensland, Oil and Gas Journal online, May 2010.
NSWMC (2009): Key Industry Statistics 2009, New South Wales Minerals Council, Sydney, Australia, 2009.
http://www.nswmin.com.au
Queensland (2014): Queensland's Coal Seam Gas Review, Geological Survey of Queensland, January 2014.
http://mines.industry.qld.gov.aU/mining/queensland-mining-update.htm#csg-industry-update
Renewable Energy (2010): RET - The Basics, Office of the Renewable Energy Regulator, Australian
Government, July 2010. http://www.orer.gov.au/publications/ret-overview.html
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
Smart Energy (2010): Smart Energy Policy, Queensland Government, Australian Government, 31 May 2010.
http://www.dme.qld.gov.au/Energy/energy policv.cfm
Strategic (2008): Strategic Review of Australian Government Climate Change Programs, Australian
Government, 31 July 2008. http://www.finance.gov.au/publications/strategic-reviews/index.html
A
Methane Stive CMM Country Profiles 25
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AUSTRALIA
UNFCCC (2104a): National Inventory Submissions 2014 - Australia, United Nations Framework Convention
on Climate Change, accessed September 2014.
http: / /unfccc.int/national reports /annex i ghg inventories/national inventories submissions /items /81
08.php
UNFCCC (2014b): Status of Ratification - Australia, United Nations Framework Convention on Climate
Change, accessed September 2014. http: //maindb.unfccc.int/public/countrv.pl?countrv=AU
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2002): The Mineral Industry of Australia, U.S. Geological Survey, Country Profiles, 2002.
http://minerals.usgs.gOv/minerals/pubs/country/2002/asmyb02.pdf
WCA (2014): Coal Facts, World Coal Association, accessed 2014. http: //www.worldcoal.org/
CMM Country Profiles 26
Methane Initiative
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3 Botswana
3.1 Summary of Coal Industry
3.1.1 Role of Coal in Botswana
Botswana possesses huge coal resources estimated at greater than 200 billion tonnes. However,
only three to five billion tonnes can be economically mined (Mmegi, 2009). The quality of coal is
suitable for power generation and is the feedstock for 99.4 percent of electricity generated in the
country (eStandards Forum, 2009). Table 3-1 quantifies total recoverable reserves and recent coal
production in Botswana.
Table 3-1. Botswana's Coal Reserves and Production
Anthracite &
Sub-
Indicator
Bituminous
bituminous &
Total
Global Rank
(million
tonnes)
Lignite
(million tonnes)
(million tonnes)
(# and %)
Estimated Proved Coal Reserves 39.99 0 40 67 (0.0045 %]
(2011]
Annual Coal Production (2012] 0.740 0 0.740 47(0.02%]
Source: EIA (2013]
In 2012, coal represented 21.6 percent of Botswana's total primary energy supply (IEA, 2014). At
present, all coal mined is used domestically for power production, but studies are under way to
explore the possible exportation of coal mined at the Morupule mine, the country's only operating
mine (Mining Journal, 2005). The Morupule mine has completed Phase I of its expansion and is
investigating reserves in the northern boundary of its mining lease to establish an open pit mine to
meet additional demand as a part of Phase II (BCM, 2014). The Morupule Mine is located in the
Morupule coalfield near the town of Serowe (Figure 3-1) and is the most thoroughly explored of
Botswana's coal fields. The only other major coal field to be explored in some detail is Mmamabula,
situated about 81 miles south of Morupule (IEA, 2010).
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Methane Stive CMM Country Profiles 27
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BOTSWANA
Figure 3-1. Botswana Coalfields Map
3.1.2 Stakeholders
Table 3-2 identifies potential key stakeholders in Botswana's coal mine methane (CMM) and coal
bed methane (CBM] development
Table 3-2. Key Stakeholders in Botswana's CMM Industry
Stakeholder Category
Stakeholder
Role
Developers
Kalahari Energy
Tlou Energy Limited (TLOU)
Anglo Thermal Coal ( formerly Anglo Coal Botswana)
Jindal Power & Steel
Many other small developers
See http://www.epa.gov/coalbed/networkcontacts.html
Project developer
Engineering, Consultancy
Scales & Associates
Technical assistance
and Related Services
Advanced Resources International
See httD://www.epa.eov/coalbed/networkcontacts.html
Botswana Development Corporation
Research
3.1.3 Status of Coal and the Coal Mining Industry
The Morupule Mine is 93 percent owned by Debswana (a joint venture of DeBeers and the
Government of Botswana] and supplies coal to Botswana's only coal-fired power station.
Methane iniSe CMM Country Profiles 28
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BOTSWANA
Production from the mine is relatively stable (0.7-1 Mtper year) as it is essentially a captive mine
for the Morupule Power Station. The mine also supplies coal to hard rock mining operations at
Selebi-Phikwe and to the Sua Pan soda ash plant, and coal is exported to Zimbabwe, Zambia and the
Democratic Republic of the Congo.
Debswana has completed Phase I of its coal production expansion at the Morupule Mine and raised
production capacity to 3.4 million tonnes per year (Mmt/yr) to accommodate Botswana Power
Corporation's (BPC) plans to add four 150 MW coal-fired power stations alongside the existing four
33 MW units currently at Morupule (eStandards Forum, 2009).
CIC Energy Corporation, which for several years had been trying to develop the Mmamabula coal
mining and energy project, was acquired in 2012 by Jindal Steel & Power, one of India's major steel
producers with a significant presence in the mining power generation, and infrastructure sectors.
The initial Mmamabula efforts included a proposed export coal project, one or more power
projects, and a potential coal-to-hydrocarbons project. The acquisition makes Jindal Africa the
frontrunner for building a 1,200-MW power plant in Botswana to supply power to South Africa
(ESI-Africa, 2012).
3.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
CMM recovery projects for Botswana, in operation or development (GMI, 2014). Updates on future
CMM projects in Botswana can be found at: https: //www.globalmethane.org/coal-
mines/cmm/index.aspx.
3.2.1 CMM Emissions from Operating Mines
Methane emissions in Botswana were estimated at 18.9 million cubic meters (m3) in 2000, and are
projected to increase to 22.4 million m3 by 2015, and then to 26.6 million m3 by 2030 (see Table 3-
3).
Table 3-3. Botswana's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
18.9
18.9
21.7
22.4
Source: USEPA(2012)
3.2.2 CMM Emissions from Abandoned Coal Mines
There are no reported emissions from abandoned mines in Botswana.
3.2.3 CBM from Virgin Coal Seams
A CBM feasibility study conducted for the Botswana Department of Geological Study estimated that
Botswana contains about 5.6 trillion cubic meters (Tcm) of CBM reserves in the Central Kalahari
Karoo Basin (ARI, 2003). However, these estimates are tenuous as they were derived from only a
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BOTSWANA
few core holes drilled into the coals of the basin. Helping Botswana meet growing domestic and
regional demand for low-cost, clean and efficient fuel for power plants was the goal of a USTDA
grant awarded to the Botswana Development Corporation (BDC). The grant funded a feasibility
study on a CBM project that was estimated to have 1.7 Tcm in CBM reserves with some of the most
prospective areas being found in the eastern portions of the basin (ARI, 2008). Following the
completion of the study the project was successfully implemented and yielded more than $52
million in U.S. exports for power generation units, drilling equipment, compressors, and hydraulic
fracturing equipment (USTDA, nd).
In recent years, there has been a tremendous increase in interest in developing CBM projects in
Botswana. The Department of Geological Survey (DGS) reported a 50 percent increase in the
number of exploration licenses issued between January and December 2009 for various energy
minerals, which includes coal and CBM (UGC, 2010). This interest is being driven by the favorable
investment climate in Botswana, coupled with an increasingly dire power situation in the region.
However, out of more than 50 companies that have taken out CBM leases in the country, very few
carried out any substantial resource assessment work to date.
The main companies that have carried out significant CBM exploration activity in Botswana are
Kalahari Energy (now Karoo Sustainable Energy), Anglo Thermal Coal (formerly Anglo Coal
Botswana) and Tlou Energy (TLOU). Kalahari Energy (KE) has been actively pursuing CBM
development since 2000, and in 2008 drilled a five-well pilot program that is currently in the
production testing phase. This was financed with a U.S. Overseas Private Investment Corp (OPIC)
$8.5 million investment guarantee for the purchase of equipment and the drilling of wells. In 2009,
KE formed a joint venture with Exxaro Resources to perform ongoing exploration work and
completed a five-well production test in late 2010 (KE, 2010). KE, which continues to pioneer
energy growth in Botswana through coal-based methane exploitation, currently operates the small
90-MW Orapa power plant and is in the process of developing a new 180-MW power project in the
country (EN, 2012).
Anglo Thermal Coal embarked on a major CBM exploration drive, which started in late 2008, with
the aim of delineating gas reserves totaling at least 110 billion m3 (Bern), sufficient to justify
construction of a dedicated synfuels plant In March 2013, Anglo Thermal Coal emerged the winner
of some 23 applicants for the coal blocks - the Mmamabula South and Central blocks - which are
adjacent to the Mmamabula East property owned by Jindal Steel & Power, the company that
recently bought CIC Energy (MiningMx, 2013). The former Saber Energy drilled over 80 exploratory
holes on their lease areas from 2008 to 2010 to test coal gas content and permeability. Saber
Energy was acquired by TLOU, which merged with Talon Metals Corporation in 2010. Following
acquisition, TLOU performed pilot horizontal well drilling and in the coming years will prepare
updated reserve/resource statements, complete marketing and commercialization arrangements
(i.e., contracts), and continue to consolidate/upgrade the resource classification through additional
exploration drilling (TLOU, 2013).
3.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Botswana, a non-Annex I country, has signed and ratified the UNFCCC and Kyoto Protocol as shown
in Table 3-4.
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BOTSWANA
Table 3-4. Botswana's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
Kyoto Protocol
June 12,1992
April 27,1994
August 8, 2003
Source: UNFCCC (2014]
In 2013, the Government of Botswana—with support from the Common Market for Eastern and
Southern Africa (COMESA) and the United Nations Development Programme (UNDP)—
commissioned a team of consultants to develop a National Climate Change Policy, Strategy and
Action Plan. Botswana's national climate change policy was expected to be ready in 2014, while the
strategy and action plan will follow (UNDP, 2013).
It is doubtful whether Botswana will have significant CMM emissions in the foreseeable future. This
is because there are abundant reserves of coal at relatively shallow depths and the overall demand
for coal in the country is limited. Currently, the prospects for exporting coal are not good, given the
distances to available ports in South Africa and limited rail infrastructure. However, in cooperation
with the government of Namibia, Botswana is considering the construction of a $6 billion, 1500-
mile rail link between the Mmamabula Coalfields of southeastern Botswana to either the ports of
Walvis Bay or Luderitz in Namibia (Mmegi, 2009).
Since there is negligible domestic demand and support infrastructure for natural gas, the market for
methane in Botswana is fairly limited (EIA, 2013).
However, CBM projects may see increased attention thanks to a report titled, Botswana Technology
Needs Assessment on Climate Change, jointly produced by several Ministries and the UNDP. The
report acknowledges Botswana's CBM reserve potential, and advises that Botswana determine such
resource potential. CBM, it concludes, may be used to provide fuel for cars and power generation,
and alleviate potential power crises. CBM may also be exported to Mozambique through the Maputo
pipeline and to the Secunda Sasol Plant in South Africa (TNA, 2004), although this option is
probably not viable now given the large offshore gas reserves recently discovered by Anadarko,
ENI, and others.
To support more domestically driven power production, Kalahari Sustainable Energy (KSE) has
been active in converting the 90-MW diesel turbines at the Orapa power plant over to natural gas
and negotiating the development of the 180-MW Mmashoro power station. Both projects would be
supplied from domestic CBM resources (CR, 2013).
As there are no operating CMM projects, a legal framework regulating them does not exist.
3.3.1 Market and Infrastructure Factors
3.3.2 Regulatory Information
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BOTSWANA
3.4 Profiles of Individual Mines
Morupule
Morupule is located along the eastern margin of the Kalahari Basin. Production began in 1973, and
the mine has a production capacity of 1 Mmt/yr.
General Information
Total mineable reserves (thousand tones]
44,000
General Geologic Information
Coal seams (thickness]
Faults?
Morupule Main (6.5-9.5 m]
Lotsane (0.6-4.5 m]
Serowe Bright (average 1.8 m]
Yes, minor. Some dolerite dyke intrusives.
Geologic and Mining Conditions
Ash content, % (coal in place, run of mine]
Moisture, % (coal in place, run of mine]
40 - 50%
5 - 10%
Coal Production, Methane Emissions, and Degasification (and Use) Statistics
2006
2007 2008 2009 2010 2011
2012
Coal Production (million tonnes]* 0.962
Degasification None
0.828 0.910 0.737 0.987 0.787
None None None None None
0.740
None
Source: *EIA (2013]
3.5 References
ARI (2003): Results of the Central Kalahari Karoo Basin Coalbed Methane Feasibility Study, prepared for the
Department of Geologic Survey, Botswana, Lobatse, by Advanced Resources International, Arlington,
Virginia, USA, 2003.
ARI (2008): Technical and Economic Feasibility Study for Coalbed Methane Development in Eastern
Botswana, prepared for Botswana Development Corporation and U.S. Trade and Development Agency by
Advanced Resources International, Arlington, Virginia, USA, 2008.
BCM (2014): Morupule Coal Mine Ltd Overview, Botswana Chamber of Mines, website accessed June 2014.
http://www.bcm.org.bw/members morupule.html
CR (2013): Botswana Resource Sector Overview 2013/2014, Capital Resources (PTY) Limited, February
2013.
http://www.capconferences.coin/files/2013/06/BOTSWANA-RESOURCE-SECTOR-OVERVIEW-2013.pdf
EIA (2013): International Energy Annual 2012, U.S. Energy Information Administration, Washington, DC,
table posted in 2013. http: //www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm?tid=l&pid=7&aid=l
(production) http: //www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm?tid=l&pid=7&aid=6 (reserves)
EN (2012): Botswana can become major energy corridor - Kalahari Energy, Engineering News - Mining
Weekly, 26 June 2012. http://www.engineeringnews.co.za/article/botswana-can-become-maior-energy-
corridor-kalahari-energv-2 012-06-2 7
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BOTSWANA
ESI-Africa (2012): "Jindal acquisition a boost for Mmamabula energy project," ESI-Africa, 11 September 2012.
http://www.esi-africa.com/iindal-acquisition-a-boost-for-mmamabula-energy-proiect/
eStandards Forum (2009): Country Brief Botswana, 27 August 2009.
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed October
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
IEA (2010): Coal Online, International Energy Agency Clean Coal Center, website accessed June 2010.
http://www.coalonline.org/site/coalonline/content/hrowser/B1343/Coal-resources
IEA (2014): Energy Statistics: Share of Total Primary Energy Supply in 2012 - Botswana, International
Energy Agency, Paris, France, 2014. www.iea.org/stats/WehGraphs/B0TSWANA4.pdf
IEA Coal Research (1983): Concise Guide to the World Coalfields, Cope, J.H.R., Duckworth, N.A., Duncan, S.V.,
Holtom, J.E.B., Leask, A.L., McDonald, K.A. and Woodman, S.P., compiled by Data Bank Service, World Coal
Resources and Reserves, IEA Coal Research, London, England, 1983.
KE (2010): Kalahari Energy's Joint Venture - Exploration Progress, Kalahari Energy, 9 July 2010.
http://www.kalaharigas.com/news.php7ick36
Mining Journal (2005): "A message from MC Tibone, Minister of Minerals, Energy and Water Resources,"
Mining lournal: Special Publication. London, October 2005.
MiningMx (2013): "Anglo swoops on Botswana's Mmamabula coal," MiningMx.com, 14 March 2013.
http://www.miningmx.com/page/news/energy/1547459-Anglo-swoops-on-Botswana-s-Mmamabula-
coal#.U7086GdQWM8
Mmegi (2009): "Botswana Sees Coal Alternative to Diamonds." Mmegionline, Vol. 26, No. 20,9 February 2009.
http://www.mmegi. hw/index.php?sid=4&aid=2 0&dir=2 009/February/Mondav9
TNA (2004): "Botswana Technology Needs Assessment on Climate Change," Botswana Ministry of
Environment, Wildlife, and Tourism; Botswana Department of Meteorological Services, UN Development
Programme, 2004.
TLOU (2013): Botswana CBM Project Update, Botswana Resource Sector Conference, TLOU Energy, June
2013. http://www.tlouenergy.com/pdfs/130611%20BRSC%20Presentation.pdf
UGC (2010): "Botswana Energy Minerals Most Sought After in 2000," Unconventional Gas Center, 5 February
2010.
UNDP (2013): "Botswana gears up for climate change; embarks on preparing a Policy, Response Strategy and
Action Plan," United Nations Development Programme, 28 August 2013.
http://www.bw.undp.org/content/botswana/en/home/presscenter/pressreleases/2013/08/28/botsw
ana-gears-up-for-climate-change-embarks-on-preparing-a-policy-response-strategy-and-action-plan-/
UNFCCC (2014): Ratification Status - Botswana, United Nations Framework Convention on Climate Change,
accessed September 2014. http: //maindb.unfccc.int/public/countrv.pl?countrv=BW
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USTDA (nd): Botswana Coalbed Methane Power Generation Project, Traditional Energy & Power Sector Brief,
U.S. Trade and Development Agency, not dated.
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4 Brazil
4.1 Summary of Coal Industry
4.1.1 Role of Coal in Brazil
Brazil is the world's eighth largest energy consumer and the third largest in the Western
Hemisphere, trailing the United States and Canada (EIA, 2013). Total primary energy consumption
in the country has been increasing in recent years, but coal only accounted for approximately 5
percent in 2011 compared to 35 percent from hydroelectricity and 47 percent from oil and other
liquid fuels. The country's domestic annual coal production is approximately 6.3 million tonnes
(Mmt) (EIA, 2014). Brazil's annual coal consumption, however, was estimated at 24.8 Mmt in 2012,
relying on 18.0 Mmt of coal imports for its energy requirements (EIA, 2014).
Brazil has recoverable coal reserves of approximately 6.6 billion tonnes, the third largest reserves
in the Western Hemisphere, after the United States and Colombia (EIA, 2014). Table 4-1 presents
most recent statistics for coal mining in Brazil.
Table 4-1. Brazil's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-bituminous
& Lignite
(million tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
0
6,630.0
6,630.0
14 (0.75%]
(2011]
Annual Coal Production (2012]
3.26
3.04
6.3
31(0.08%]
Source: EIA (2014]
Demand for metallurgical coal in Brazil, the world's ninth-largest steel producer in 2011, accounts
for 84 percent of the region's coal consumption from 2010 to 2040, with demand for steel in both
domestic and international markets expected to increase throughout that period (EIA, 2013).
Brazil's coal mining operations are concentrated in the southern states of Santa Catarina (46
percent), Rio Grande do Sul (53 percent), and Parana (1 percent) as shown in Figure 4-1.
\ /Global
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CMM Country Profiles 34
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BRAZIL
Figure 4-1. Brazil's Coal Fields
N
.A
\
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Source: Maps ofWorld (2010)
4.1.2 Stakeholders
Table 4-2 lists potential stakeholders in Brazilian coal mine methane (CMM) development
Table 4-2. Key Stakeholders in Brazil's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies
¦ Companhia Riograndense de Mineracao (CRM]
Project hosts
¦ Copelmi Mineracao Ltda.
¦ Carbonifera Palermo Ltda.
¦ Nova Prospera Mineracao S.A.
¦ Carbonifera Metropolitana S.A.
¦ Carbonifera Criciuma S.A.
¦ Companhia Carbonifera de Urussanga
¦ Carbonifera Treviso S.A.
¦ Carbonifera Barro Branco S.A.
¦ Ibracoque Mineracao Ltda,
¦ Companhia Brasileira Carbonifera Ararangua
¦ Industria Carbonifera Rio Deserto Ltda.
111
Methane iniSe CMM Country Profiles 35
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BRAZIL
Table 4-2. Key Stakeholders in Brazil's CMM Industry
Stakeholder Category
Stakeholder
Role
¦ Carbonifera Belluno Ltda.
¦ Companhia Carbonifera Catarinese (CCC]
¦ Campanhia Carbonifera do Cambui
¦ Klabin S.A.
Government Groups
¦ Ministry of Environment
¦ Ministiy of Mines and Energy (MME]
¦ National Department of Mineral Production
¦ Coal Mining Industry Union of the State of Catarina
¦ Sindicato da Industria da Extracao de Carvao do Estado
de Santa Catarina (SIECESC]
Licensing and permitting
Developers
¦ See
http://www.epa.gov/coalbed/networkcontacts.html
Project opportunity
identification and
planning
Engineering, Consultancy,
and Related Services
¦ See
http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
Universities
¦ Federal University of the State of Rio Grande do Sul
¦ Associa^ao Beneficente da Industria Carbonifera de
Santa Catarina (SATC]
Technical assistance
4.1.3 Status of Coal and the Coal Mining Industry
As previously stated, the Brazilian coal industiy's mining operations are concentrated in three
southernmost states. It has 15 coal mining companies, all owned by Brazilian investors. The main
producers that have underground mines are the following:
Companhia Riograndense de Minera^ao (CRM) (State of Rio Grande do Sul) - CRM, a state-
owned company, is the largest Brazilian coal producer with a current output of nearly 2.4 Mmt per
year (CRM, 2014). Most of CRM's output comes from surface mines, but it has two underground
mines. Mina do Leao I is 125 meters deep, has two shafts, and is highly mechanized, but
underground production halted in 2002 due to high costs. The mine remains open as an opencast
mine. Mina do Leao II is six km from Mina do Leao I and has a projected capacity of 2.4 Mmt/year of
run-of mine (ROM) coal, using the longwall method at an average depth of 200 meters.
Carbonifera Criciuma S.A. (State of Santa Catarina) - The Verdinho Mining Unit II—the company's
underground mine—began operations in 1982, is approximately 170 m deep, and has a capacity of
2.8 Mmt/yr ROM (CC, 2014).
Industria Carbonifera Rio Deserto Ltda. (State of Santa Catarina) - This company has two
underground mines: Mina do Trevo in the municipality of Sideropolis producing 1.6 Mmt ROM
annually; and Mina Barro Branco in the municipality of Lauro Muller producing 0.85 Mmt of ROM
annually. Both are room and pillar mines. The company is also responsible for providing coal to
Tractebel, the largest private energy generator in Brazil (RD, 2014).
Carbonifera Metropolitana S.A. (State of Santa Catarina) - This company has an annual output of
nearly 1.2 Mmt ROM and 0.6 Mmt of processed coal. It has two underground room and pillar mines,
Esperan^a and Fontanella, both in the municipality of Treviso. The Esperan^a mine was opened in
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1984 with a nominal annual capacity of 3.0 Mmt ROM, and the Fontanella mine was opened in 1985
with a nominal annual capacity of 2.4 Mmt ROM.
Carbonlfera Belluno Ltda. (State of Santa Catarina) - This company has three coal mines, only one
of which is underground (Meia Encosta Fiorita), located in the municipality of Sideropolis. The
company's total output is nearly 0.24 Mmt of processed coal. Its underground mine has a nominal
capacity for 0.36 Mmt ROM annually.
Companhia Carbonifera Catarinense (CCC) (State of Santa Catarina) - It has two underground
mines, named Bonito I and Novo Horizonte. Both are room and pillar mines (Vasconcelos, 2006).
In the near term, coal consumption in Brazil's electricity sector is set to increase with the
completion of the Pecem I, Pecem II, and Itaqui power plants (EIA, 2013). Since 2011, Brazil has
expanded its coal-fired power generation by 1,440 MW as shown in Table 4-3 (GEO, 2014). The
number of coal-fired plants had remained unchanged for many decades, until these new projects
were commissioned.
Table 4-3. Brazil's Coal-Fired Power Plants
Name of Plant
Year
Commissioned/Last
Unit Installed
Generating
Capacity
(MW)
Location
(State)
Porto do Itaqui
2012
360
Maranhao
Porto do Pecem
2011/2012
1080
Ceara
President Medici (Candiota]
1974/2010
796
Rio Grande do Sul
Jorge Lacerda Thermal
1965/1997
857
Santa Catarina
Figueira
1963/1974
20
Parana
Charqueadas
1962/1969
72
Rio Grande do Sul
St. Jerome (UTSJ] Thermal
1953/1955
20
Rio Grande do Sul
Source: GEO (2014]
4.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
projects in Brazil, in operation or development. Updates on future CMM projects in Brazil can be
found at https: //www.globalmethane.org/coal-mines/cmm/index.aspx.
4.2.1 CMM Emissions from Operating Mines
Methane emissions in Brazil totaled 63.0 million cubic meters (m3) in 2000, are expected to
increase to 102.2 million m3 by 2015, and then further increase to 146.4 million m3 by 2030 (see
Table 4-4).
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Table 4-4. Brazil's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
63.0
72.1
80.5
102.2
Source: USEPA (2012]
4.2.2 CMM Emissions from Abandoned Coal Mines
No data were found quantifying methane emissions from abandoned mines.
4.2.3 CBM from Virgin Coal Seams
No data were found quantifying production from virgin coal seams.
4.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Brazil has signed and ratified both the UNFCCC and the Kyoto Protocol (see Table 4-5). As a party to
the Kyoto Protocol, CMM projects in Brazil can be expected to benefit from revenues deriving from
the sale of carbon emission reduction credits.
Table 4-5. Brazil's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 4,1992
February 28,1994
Kyoto Protocol
April 29,1998
August 23, 2002
Source: UNFCCC (2014]
Brazil's National Plan on Climate Change (Piano Nacional sobre Mudan^a do Clima or PNMC, in
Portuguese), finalized in December 2008 and last amended in 2010, established a voluntary
national greenhouse gas (GHG) reduction target of between 36.1 percent and 38.9 percent of
projected emissions by 2020 (CPW, 2014). Unlike other top GHG-emitting countries, however, more
than 75 percent of Brazil's emissions are attributed to deforestation, agriculture, and land use
change rather than with energy consumption (Yale, nd). In international climate negotiations (e.g.,
COPs), Brazil typically coordinates with the other BASIC nations (i.e., Brazil, South Africa, India,
China) and hosted the Rio+20 United Nations Conference on Sustainable Development in 2012.
4.3.1 Market and Infrastructure Factors
Brazil's coal mining industry has become increasingly important in recent years attributable to
periods of economic uncertainty, instability in the energy sector, and a resulting shift in energy
policy. Santa Catarina, the largest coal-producing state, has been the primary beneficiary of the
industry's increase in status and importance. However, it also faces increased scrutiny from
environmental groups concerned about the negative socioeconomic and environmental impacts
caused by the growing industry.
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On the technology front, groups are working in Brazil's mining regions to implement Integrated
Resource Management techniques. These technical improvements are intended to reduce
transportation costs, reduce waste and harmful emissions, and increase the scale of production to
increase domestic coal supplies and reduce reliance on imports. Thus far, efforts have resulted in
the 1989 establishment of an association of coal mining companies in the State of Santa Catarina,
the Sindicato da Industria da Extracao de Carvao do Estado de Santa Catarina (SIECESC). SIECESC
actively works with the Brazilian Ministry of Environment, the Ministry of Mines and Energy, the
National Mineral Production Department (NMPD), and several international organizations to devise
strategies to implement regional and global sustainable mining and industry development In Santa
Catarina, for example, SIECESC is coordinating a recovery project (i.e., Project for Environmental
Recovery Carboniferous Basin Southern Santa Catarina) to restore lands previously degraded
through mining activities and whose results are already being noted (CPRM, 2002).
4.3.2 Regulatory Information
Aiming to adjust the current mining regulation and simplify mining procedures, the creation of a
new agency—the National Mining Agency—has been proposed, similar to those already in place for
petroleum and electricity regulation (the National Petroleum Agency and the National Electric
Energy Agency, respectively). The new agency will regulate, supervise, encourage, and increase the
development of mineral policy, including the penalties applied to irregular mining activities. These
roles have been performed to date by DNPM, which is the entity in charge of authorizing research,
permits, and mineral mining concessions, and for other relevant aspects of the industry. Under the
new proposal, DNPM is expected to be disbanded, with its functions encompassed by the new
agency (ILO, 2011). Despite the new mining agency, no information on regulations pertaining to
CMM development in Brazil was found.
4.4 Profiles of Individual Mines
No information profiling individual Brazilian mines was found.
4.5 References
CC (2014): Mines of Carbonifera Criciuma S.A., accessed July 2014.
http://www.carhocri.coin.hr/site/einpresa/inineracao/
CPRM (2002): Geological Survey of Brazil - CPRM presentation, delivered in 2002, website accessed July
2014. http://www.cprm.gov.br/geoecoturismo/coluna white/carvaomin eral.html
CPW (2014): Climate Policy Watcher - Brazil, accessed July 2014. http: IIwww.climate-policv-
watcher. or g/?q=Br azil
CRM (2014): Mines of Companhia Riograndense de Minerafao (Riograndense Mining Company), accessed
July 2014. http://www.crm.rs.gov.br/lista/529/Minas
EIA (2013): Country Analysis Overview- Brazil, U.S. Energy Information Administration, Washington, DC, last
updated 1 October 2013. http: //www.eia.gov/countries/cab.cfm?fips=BR
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed July 2014, http: IIwww.eia.gov/cfapps /ipdbproi ect/1ED Index3.cfm
GEO (2014): Current List of Coal Power Plants - Brazil, Global Energy Observatory, accessed July 2014.
http://glohalenergvohservatory.org/list.php?dh=PowerPlants&type=Coal
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GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
ILO (2011): "Expectations for mining in Brazil: new regulatory milestone," International Law Office, 24
October 2011. http://www.internationallawoffice.com/newsletters/detail.aspx?g=cc8d588b-8dd9-47c4-
b89b-a9b7c628b883
Maps of World (2010): Brazil Mineral Map, Mapsofworld.com, accessed July 2010.
http://www.mapsofworld.com/brazil/brazil-mineral-map.html
RD (2014): Industria Carbonifera Rio Deserto Ltda - Energy Products, website accessed in July 2014.
http://www.riodeserto.com.br/produtos/energetico/
UNFCCC (2014): Ratification Status - Brazil, United Nations Framework Convention on Climate Change,
accessed July 2014. http: //maindb.unfccc.int/public/country.pl?country=BR
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
Vasconcelos (2006): Vasconcelos, Mauricio. "Coal Mining in Brazil." U.S. & Foreign Commercial Service, July
Yale (nd): Climate Policy & Emissions Data Sheet: Brazil, Yale Center for Environmental Law & Policy Webinar
Series, "Climate Change Solutions: Frontline Perspectives from Around the Globe," accessed July 2014.
http://envirocenter.yale.edu/uploads/pdf/Brazil Climate Policy Data Sheetpdf
2006.
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5 Bulgaria
5.1 Summary of Coal Industry
5.1.1 Role of Coal in Bulgaria
Most of the coal consumed in Bulgaria is used for power production. A substantial portion of its
thermal electric power plants, which produce more than one-half of the country's total production
of about 45 billion kilowatts, operate on domestic coal (Steblez, 2000). A reliable supply of higher-
quality hard coal is, however, necessary for Bulgaria's metallurgical industries, and such coal is
obtained from as near as Ukraine and as far away as Australia (USDOE, 2004). Bulgaria's annual
coal production and consumption both remained relatively constant from 1990 through 2010,
peaking in 2011, and the country is expected to remain a net coal importer (EIA, 2014).
Bulgaria's coal reserves include about 88.7 percent lignite, 10.9 percent brown coal, and 0.4 percent
hard coal (Euracoal, 2014). Much of the household coal heating is with briquettes, especially in the
vicinity of the state-owned briquette factory, Stara Zagora (see Figure 5-1). About 9 percent of
Bulgaria's coal production is used for making briquettes (USDOE, 2004).
Table 5-1. Bulgaria's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous & Total Global Rank
Lignite (million tonnes) (# and %)
(million tonnes)
Estimated Proved Coal Reserves
2.0
2,364 2,366 20 [0.266%]
[2011]
Annual Coal Production (2012]
0.01
32.51
32.52
22 (0.41 %]
Source: EIA (2014]
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Figure 5-1. Bulgaria's Coal Fields
Hard coal
Lignite Brown coal Hard coal Anthracite and
' Anthracite
Source: Euracoal (2014)
5.1.2 Stakeholders
Table 5-2 summarizes key stakeholders in Bulgaria's coal mine methane (CMM) industry.
Table 5-2. Key Stakeholders in Bulgaria's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies
¦ Mining companies (see Section xx.1.4)
Project host
Universities, Research
¦ University of Mining and Geology "St. Ivan Rilski" -
Consulting assistance
Establishments
Bulgaria
¦ Geological Institute "St. Dimitrov"
Government Groups
¦ Ministry of Energy and Economy
Permitting and
licensing
Other
¦ Bulgaria's Energy Efficiency Center in the Industry
Transfer of
Efficiency Agency (executive agency to the Minister of
technologies.
Energy and Energy Resources]
knowledge, and
experience in the field
of energy efficiency and
use of renewable
energy sources
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5.1.3 Status of Coal and the Coal Mining Industry
Bulgaria produced 32.52 million tonnes (Mmt) of coal in 2012 (EIA, 2014b), with most of the lignite
reserves found in the central (Maritsa East) and western part of the country (Sofia and Bobov dol)
(Euracoal, 2014). There are three opencast mines operated in the Maritsa East coalfield—
Troyanovo-1 mine, Troyanovo-North mine and Troyanovo-3 mine—which have the potential to
produce more than 30 Mmt of lignite per year (Euracoal, 2014). Their supplies feed 2,240 MWe of
three mine-mouth power plants (USDOE, 2004).
Other mines in Bulgaria have much lower production rates. The brown coal from the one open cast
and two underground Bobov Dol Mines, in southwestern Bulgaria, and the lignite from the
Stanyantsi, Bely Brag, and Choukourovo Mines are used mostly at the 630-MWe Bobov Dol power
plant The two open cast Pernik Mines, west of Sofia, have been supplying mainly for the Republica
power plant(USDOE, 2004; Euracoal, 2008). Table 5-3 summarizes coal production by type of mine
and from individual mines in Bulgaria.
Table 5-3. 2012 Statistics for Bulgaria's Coal Mining
Company/Mine Name
Coalfield
Mine Type
Coal Type
Annual Production
(million tonnes)
Mini Maritsa Iztok EAD
¦ Maritsa East
¦ 3 Opencast
¦ Lignite
32.1
Bely Brag Mine AD
¦ Sofia
¦ 1 Opencast
¦ Lignite
0..6
Choukourovo Mine AD
¦ Sofia
¦ 1 Opencast
¦ Lignite
0.2
Stanyantsi Mine AD
¦ Sofia
¦ 1 Opencast
¦ Lignite
0.6
Vagledobiv Bobov Dol EOOD
¦ Bobov Dol
¦ 1 Opencast,
¦ 2 Underground
¦ Brown
0.97
Otkrit Vagledobiv Mines EAD
¦ Pernik
¦ 2 Opencast
¦ Brown
1.1
Balkan 2000 Mines EAD
¦ Sliven
¦ Underground
¦ Black
0.007
Source: MEET (2013]
Currently, there are 17 coal licensees and as of 2005, there were 19 companies operating mines
(Ilkova, 2005). The Bulgarian coal industry has been restructured and certain mines have closed
down, mainly underground, that have proven to be inefficient The closing of mines is consistent
with government rules and regulations. These mines namely are Zdravets, Antra, Marbas, Pirin,
Bistritsa, Balkanbas, Balkan mine, Ivan Roussev mine, and Kolosh mine (Ilkova, 2005).
There are five mines considered potentially gassy - Bobov dol (two underground mines), Minior,
and Balkan-2000 (two deposits are operated there - Tvarditsa and Paisii). The gas emissions are
measured regularly (Ilkova, 2005).
5.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
projects in Bulgaria, in operation or under development (GMI, 2014). Updates on future CMM
projects in Bulgaria can be found at https://www.globalmethane.org/coal-mines/cmm/index.aspx.
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5.2.1 CMM Emissions from Operating Mines
Methane emissions in Bulgaria were estimated at 92.4 million cubic meters (m3) in 2000, are
projected to increase to 106.4 million m3 by 2015, and then anticipated to remain relatively steady
with only a slight increase to 107.1 million m3 by 2030 (see Table 5-4).
Table 5-4. Bulgaria's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
92.4
86.1
101.5
106.4
Source: USEPA(2012)
5.2.2 CMM Emissions from Abandoned Coal Mines
No data quantifying CMM emissions from abandoned mines were found.
5.2.3 CBM from Virgin Coal Seams
In April 2014, Park Place Energy Corp. (headquartered in Texas) announced an agreement with the
Bulgarian Ministry of Economy and Energy to explore the Vranino coal block in the country's
northeast region as a source for natural gas. The company will drill five wells and utilize seismic
data to get a better understanding of the potential to exploit coal resources for natural gas
development (Park Place Energy Corp, 2014).
Table 5-5 summarizes coal bed methane (CBM) resources in Bulgaria's Dobroudja Basin.
Table 5-5. CBM and Coal Resources of Bulgaria's Dobroudja Basin
CBM Resource
Proven
Probable
Possible
Total
Billion m3
3.2
81.6
80.8
195.6
Coal Resource
Measured
Indicated
Inferred
Total
Billion tonnes
2.8
6.8
11.8
21.4
Source: Marshall (2001]
5.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Bulgaria signed and ratified the United Nations Framework Convention on Climate Change and
Kyoto Protocol (see Table 5-6) as an Annex 1 country. As such, it is eligible to host Joint
Implementation projects that generate revenue by creating emission reduction credits. Bulgaria's
greenhouse gas (GHG) emission reduction target under the Kyoto Protocol was 8 percent of base
year 1988 emissions during the first commitment period from 2008-2012 (UNFCCC, 2000; UNFCCC,
2002).
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Table 5-6. Bulgaria's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
Kyoto Protocol
June 5,1992
September 18,1998
May 12,1995
August 15, 2002
Source: UNFCCC (2014]
An evaluation of 2011 GHG data revealed Bulgaria's emissions had decreased by approximately 50
percent against the Kyoto base year, and the countiy was likely to meet its Kyoto target through
domestic emissions reductions directly (Ecologic Institute/eclareon, 2014). In May 2012, Bulgaria's
Ministry of Environment and Water (MoEW) issued its Third National Action Plan on Climate
Change (NAPCC). Bulgaria's climate change policy is based on two essential aspects: 1) the
country's international commitments under UNFCCC/Kyoto Protocol (described above) and 2) the
newly-adopted European climate legislation that seek to reduce emissions from member countries
by 2020. The Third NAPCC outlines a framework to combat climate change for the period from
2013 to 2020, and focuses Bulgaria's efforts on actions leading to commitment(s) implementation
and climate impacts reduction (MoEW, 2012).
The Bulgarian coal industry has been restructured, shifting the focus to privatization and
compliance with environmental standards. Certain mines, mainly underground, that have proven to
be inefficient per government rules and regulations, have closed, and a gradual shift toward the
privatization of Bulgaria's mines has encouraged foreign investment. AES Corporation, of the
United States, took over operations of the Maritsa Unit 1 power plant, part of the Maritsa East
mining and power generation complex, in late 2008. As part of the transaction, AES financed the
construction of a newer 2 x 300-MW lignite-fired power plant, which became operational in 2011
(PowerEng, 2011). The new plant replaced an older, inefficient, 500-MW plant An earlier analysis
revealed the effort as one of Bulgaria's largest foreign investment projects, and construction of the
adjacent state-of-the-art ash disposal facility would help the coal industry comply with European
Union environmental standards (EBRD, 2005). Also, the Kanina Mine, Oranovo Mine, and Otkrit
Vagedobiv Mines were privatized in 2004. The Stanyantsi Mines, Bely Brag Mines, Choukourovo
Mines, and Pernik Mines have also been privatized (Euracoal, 2008).
The Maritsa East Mines and the Bobov Dol Mines are state-owned and sell coal at state-regulated
prices to consumers. Similarly, the briquette factory at Maritsa East sells briquettes to consumers at
state-regulated prices (USDOE, 2004).
Besides these state-owned mines, there are some coal mines that sell their products at contracted
prices. The largest of these are the Pirin Mine, the Maritsa Basin Mine, the Balkan Mine, the Cherno
More Mine, the Vitren Mine, and the Anthra Mine (USDOE, 2004).
No regulatory information was found specifically applicable to CMM development in Bulgaria.
5.3.1 Market and Infrastructure Factors
5.3.2 Regulatory Information
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5.4 Profiles of Individual Mines
See Table 5-3 above for information on individual mines in Bulgaria.
5.5 References
EBRD (2005): "Maritza East I Power Company Environmental Impact Assessment Executive Summary,"
European Bank for Reconstruction and Development, February 2005.
http://www.ebrd.com/pages/proiect/eia/11865e.pdf
Ecologic Institute and eclareon (2014): Assessment of climate change policies in the context of the European
Semester - Country Report: Bulgaria, Ecologic Institute and eclareon, January 2014.
http://www.ecologic.eu/sites/files/publication/2014/countryreport bg ecologiceclareon ian2014 O.pdf
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC, website
accessed July 2014. http: IIwww.eia.gov /cfapps /ipdbproi ect /1ED Index3.cfm
Euracoal (2008): Euracoal Country Profiles: Bulgaria, website accessed June 2010.
Euracoal (2014): Euracoal Country Profiles: Bulgaria, website accessed July 2014.
http://www.euracoal.be/pages/layoutlsp.php?idpage=69
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed in July
2014. https://www.glohalinethane.org/coal-inines/cinm/index.aspx
Ilkova (2005): Information provided by Stephania Ilkova, Republic of Bulgaria Ministry of Energy and
Economy, 2005.
Marshall (2001): "Coalbed Methane Opportunities in Bulgaria," World Coal, 1 September 2001, James
Marshall, 2001.
MEET, (2013): Bulletin on the State and Development of the Energy Sector in the Republic of Bulgaria, Republic
of Bulgaria Ministry of the Economy, Energy and Tourist, Sofia, Bulgaria, 2013.
MoEW (2012): Third National Action Plan for Climate Change for the Period 2013-2020, Republic of Bulgaria
Ministry of Environment and Water, Sofia, Bulgaria, May 2012.
http://www3.moew.government.bg/files/file/Climate/Climate Change Policy Directorate/THIRD NATI
ONAL ACTION PLAN.pdf
Park Place Energy Corp (2014): Vranino Gas Project, company website accessed July 2014.
http://parkplaceenergy.com/proiects/vranino-gas-proiect/
PowerEng (2011): "Coal-fired power plant enters service in Bulgaria," Power Engineering, 3 June 2011.
http://www.power-eng.com/articles/2011 /06/coal—fired-power-plant-enters-service-in-hulgaria.html
Steblez (2000): The Mineral Industrial of Bulgaria and Romania - The USGS Minerals Yearbook, Walter Steblez,
2000. http://minerals.usgs.gOv/minerals/pubs/country/2000/9408000.pdf
UNFCCC (2000): In-depth review of the second national communication, United Nations Framework
Convention on Climate Change, 7 April 2000. http://unfccc.int/resource/docs/idr/bul02.htm
UNFCCC (2002): Third National Communication on Climate Change, United Nations Framework Convention on
Climate Change, 2002. http://unfccc.int/resource/docs/natc/bulnc3.pdf
UNFCCC (2014): Ratification Status - Bulgaria, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=BG
USDOE (2004): Energy Overview of Bulgaria, updated 15 November 2004, cited August 2005.
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USEPA (2012): Global Anthropogenic N011-CO2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
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6 Canada
6.1 Summary of Coal Industry
6.1.1 Role of Coal in Canada
Coal is the most abundant fossil fuel in Canada, comprising 61 percent of all its fossil fuel reserves
(CCPC, 2010). Coal accounted for 10 percent of Canada's total energy consumption in 2010 (EIA,
2012). Canada exports more than 40 percent of its tonnage as coking coal for steelmaking to Asian
countries and some to Europe and Latin America. Conversely, Canada imports coal for electricity
generation—estimated at about 11.2 million tonnes (Mmt) in2012 (EIA, 2014)—largely from the
United States, with smaller volumes from Colombia, Venezuela, and Russia (NRC, 2014). About 89
percent of the coal consumed in Canada is for thermal power generation and the remainder is used
in the steel (7 percent), cement, and other industries.
The recoverable coal reserves in the country are estimated at 6.6 billion tonnes and Canada's coal
production has been declining dropping from 78.7 Mmt in 1997 to 66.5 Mmt by 2012 (EIA, 2014).
Table 6-1 quantifies recoverable reserves and recent coal production in Canada.
Table 6-1. Canada's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous &
Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
3,474
3,108
6,582
15 (0.74%]
Annual Coal Production (2012]
57.0
9.5
66.5
13 (0.84%]
Source: EIA (2014]
Production occurs mainly in Alberta (43 percent), British Columbia (BC) (35 percent), and
Saskatchewan (11 percent), as shown in Figure 6-1. Coal mines in eastern Canada, New Brunswick,
and Nova Scotia are small operations.
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Figure 6-1. Canada's Coal Fields
|flNTHflflCITt
^BITUMINOUS
A SUB-BITUMINOUS
^LIGNITE
6.1.2
Source: CAC (2006)
Stakeholders
Table 6-2 identifies potential key stakeholders in coal mine methane (CMM] development in
Canada,
Table 6-2. Key Stakeholders in Canada's CMM industry
Stakeholder Category
Stakeholder
Role
Mining Companies
It
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The three giants in the coal industry (Luscar Ltd., Teck Project hosts
Cominco Ltd., and Fording Inc.) have merged to form the
Elk Valley Coal Corp., with Teck Cominco as the managing
partner.
Western Canadian Coal Corp.
Grande Cache Coal Corp.
Encana
MGV Energy Inc.
Apache Canada Ltd.
Trident Exploration Co.
Burlington
Nexen
Anadarko
Talisman
CDX
Thunder
Dominion
APF
Vectren
Walter Energy Inc.'s Canadian Operations
Winsway Coking Coal Holdings Ltd
Marubeni Corporation
Anglo American Pic's Peace River Coal Inc.
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Table 6-2. Key Stakeholders in Canada's CMM Industry
Stakeholder Category
Stakeholder
Role
¦ Sherritt International Corporation
Mining Companies (con't]
¦ Vitol Group's Hillsboruough Resourced Ltd.
¦ NB Power (power-producing company that also mines
coal]
¦ TransAlta Corporation (power-producing company that
also mines coal]
Project hosts
Developers
¦ VWVulcan Energy of Canada, Ltd.
Project opportunity
¦ Trident Exploration
identification and
¦ Husky Energy
planning
¦ Nexen
¦ Red Willow
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Engineering, Consultancy,
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
and Related Services
Universities, Research
¦ University of Montana (Water Quality Management]
Technical assistance
Establishments
¦ Alberta Research Council
¦ Natural Resources Canada
¦ Canadian Mineral and Energy Technologies (CANMET)
Government Groups
¦ Natural Resources Canada
Permitting and
¦ Alberta Ministiy of Energy
licensing
¦ British Columbia Ministiy of Energy, Mines, and
Petroleum Resources
Professional Associations
¦ Canadian Association of Petroleum Producers (CAPP]
¦ The Mining Association of Canada
¦ Coal Association of Canada
¦ Saskatchewan Mining Association
Technical assistance
Sources: AAPL (2005]; NRC (2014]
6.1.3 Status of Coal and the Coal Mining Industry
Canada has 24 coal mines. Practically all coal mined in Canada (97 percent) is extracted by surface
mining methods, specifically open-pit mining in the mountainous regions of Alberta and BC and
strip mining in BC and the Prairies of central and southern Alberta and southern Saskatchewan.
Nova Scotia also hosts two surface pits. There are only two operating underground mines in
Canada, the Quinsam mine on Vancouver Island in BC and the Grande Cache mine in Alberta, which
has both surface and underground operations (NRC, 2012). However, several underground mines
are in various stages of planning, and it is likely that the number of underground mines and their
contribution to total coal production will grow in the future. Table 6-3 provides statistics on
Canadian coal mining as of 2012.
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Table 6-3. Canada's Most Recent Statistics for Coal Mining
Type of Mine
Production
(million tonnes]
Number of Mines
Underground (active) mines -
total
*0.5(2012)
1 (2012)
Surface (active) mines - total
66 (2012)
20 (2012)
Source: *NRC [2012]
The country largely produces bituminous coal, which accounted for 48 percent of its entire coal
production in 2001. Sub-bituminous coal, mined in Alberta, forms the next largest component in
Canada's coal production at 35 percent. No anthracite currently is mined in Canada, although some
has been discovered in BC, Lignite occurs in Saskatchewan and Alberta and is used to produce 65
percent of Saskatchewan's electricity.
The operational status of Canadian coal mines is illustrated in Figure 6-2, while Table 6-4 lists mine
status by region.
Figure 6-2. Status of Canada's Coal Mines
-82 4
ELLESMERE ISLAND, NUNAVUT
PERMITTED AND/OR OPERATING MINES
MINE PROJECTS, NOT YET PERMITTED
BC ALBERTA SASKATCHEWAN
r
NOVA SCOTIA
Source: CAC (2014)
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Table 6-4. Status of Canada's Coal Mines
Region
Permitted and/or Operating Mines
(operated by)
Mine Projects, Not Yet Permitted
(owned*/operated by)
Alberta
Nova Scotia
Saskatchewan
Yukon
Ellesmere
Island,
Nunavut
British
Columbia
1. Gregg River (Sherritt International]
2. Grande Cache (Grande Cache Coal]
3. Highvale Mine (TransAlta and SunHills Mining
Partnership]
4. Coal Valley (Sherritt]
5. Paintearth Mine (Sherritt]
6. Sheerness Mine (Sherritt]
7. Genesee Mine (Sherritt]
8. Obed Mountain (Sherritt]
9. Cheviot (Teck]
10. Ryley (Dodds Coal]
1. Stellarton Mine (Pioneer Coal Limited]
3. Point Aconi [currently in reclamation phase]
1. Boundary Dam (Sherritt]
2. Poplar River Mine (Sherritt]
3. Bienfait Mine (Sherritt]
1. Fording River Mine (Teck]
2. Greenhills Mine (Teck]
3. Line Creek Mine (Teck]
4. Coal Mountain Mine (Teck]
5. Elkview Mine (Teck]
6. Wolverine Mine (Walter Energy Inc.]
7. Brule Mine (Walter Energy Inc.]
8. Willow Creek Mine (Walter Energy Inc.]
9. Trend Mine (Anglo American]
10. Quinsam Mine (Hillsborough Resources]
11. Vista (Coalspur]
12. Palisades (Altitudes Resources Ltd.]
2. Donkin Mine Project (Morien Resource
Corporation]
4. Border Mine ( GoldSource Mines]
1. Division Mountain coal deposit (Pitchblack
Resources]
1. Fosheim Property (Canada Coal Inc.]
11. Raven (Compliance Energy Corporation
12. Quintette (Teck]
13. Arctos (Arctos Anthracite Joint Venture]*
14. Groundhog (Atrum Coal]
15. Carbon Creek (Cardero Resource Corp.]
16. Sukunka (Xstrata Coal Canada]
17. Suska (Xstrata Coal Canada]
18. Mt. Hudette/Brazion (Walter Energy's
Canadian Operations
19. Gething (CKD Mines Co. Ltd.]
20. Echo Hill (Hillsborough Resources Limited]
21. Murray River (HD Mining Ltd.]
22. Roman Mountain (Anglo American]
23. Belcourt (Walter Energy's Canadian
Operations]
24. Huguenot (Colonial Coal International
Corporation]
25. Saxon (Walter Energy's Canadian Operations]
26. Basin (Coalmont Energy Corp]
27. Bingay (Centermount Coal Limited]
28. Marten-Wheeler (Teck]
29. Crown Mountain (Jameson Resources]
30. Coal Creek (Crows Nest Pass Coal Mining]
Note: Number by mine name indicates location on Figure 6-2
Source: CAC (2014]
<
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The coal deposits in central and southern parts of Alberta and Saskatchewan lie in blankets of
uniform thickness close to the surface, while the coal around the BC/Alberta border run into
mountainous terrain and the seams can be as thick as 15 meters, deeply buried and inclined,
making mining a challenge. In eastern Canada, Nova Scotia contains the largest coal deposits. The
largest one, Sydney coalfield, has 11 seams that are 1.0 to 4.5 meters thick and is located under the
ocean. Economics posed challenges to extracting that coal, however, and the mines were closed.
Furthermore, the mining conditions are quite difficult and dangerous in the region as evidenced by
an explosion and fatalities at the Westray mine. The coal in Ontario has a low-heat value and is not
exploited. Finally, the potential of coal deposits in the northern half of the country have yet to be
explored (CAC, 2003).
The Canadian coal industiy has undergone major restructuring recently with the consolidation of
mining companies starting in 2003. The three giants in the coal industry—Luscar Ltd., Teck
Cominco Ltd., and Fording Inc. —merged to form the Elk Valley Coal Corp. (EVCC), with Teck
Cominco as the managing partner of EVCC. As part of the deal, Luscar Energy Partnership bought
the thermal coal assets of Fording to become the largest producer of thermal coal in Canada.
Luscar's assets include the undeveloped coalfields, royalty interests, mining service contracts, and
an interest in a joint mining venture. With these mergers, Luscar Coal Ltd. and EVCC are in charge of
99.5 percent of the entire Canadian coal production, operating all 15 large-scale mining operations
(>1 Mmt/yr) (NRC, 2005). In 2008, Teck bought out the Fording Canadian Coal Trust (Mining
Exploration News, 2008). In 2011, Anglo American acquired an additional 25.17 percent interest of
Peace River Coal Limited Partnership thus making Anglo American the 100 percent owner of PRC.
PRC operates the Trend mine in the Rumbler rage of BC and is conducting future exploration
studies. Also in 2011, Xstrata pic took over First Coal Corporation through its subsidiary, Xstrata
Coal Canada Ltd, while Walter Energy acquired Western Coal Corporation and GCC entered an
acquisition agreement with Winsway and Marubeni through the partnership "1629835 Alberta
Ltd." (NRC, 2011).
Although domestic consumption of coal has declined recently, coking coal exports are on the rise
with an increasing demand for metallurgical coal worldwide, especially as China turns into an
importer of coking coal. Canada was the world's third largest exporter of coking coal in 2012 when
coking coal exports reached 30.7 Mt, an 11-percent increase from 2011 to 2012. EVCC has
increased metallurgical coal production and opened the Cheviot Creek Pit near Hinton, Alberta,
which has a production capacity of 1.7Mt/y. Walter Energy, Winsway Coking Coal Holdings Ltd.,
and Marubeni Corp also produce coking coal for export In recent years, six more mining projects
have been or are under development by individual companies, five of which are in BC (i.e., Carbon
Creek, Murray River, Echo Hill, Bingay, and Sukunka). Four of the mines plan to produce coking coal
while the other mine plans to produce bituminous thermal coal for export (NRC, 2012). In eastern
Canada, Nova Scotia is taking steps to restart coal mining although a contract has not yet been
assigned.
6.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
projects in Canada, in operation or under development (GMI, 2014). Updates on future CMM
projects in Canada can be found at https://www.globalmethane.org/coal-mines/cmm/index.aspx.
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6.2.1 CMM Emissions from Operating Mines
There are no CMM utilization projects in Canada. Methane emissions in Canada were estimated at
67.9 million cubic meters (m3) in 2000, are expected to increase slightly to 68.6 million m3 by 2015,
and then anticipated to further increase to 76.3 million m3 by 2030. Table 6-5 summarizes the
country's CMM emissions.
Table 6-5. Canada's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
67.9
70.0
65.8
68.6
Source: USEPA (2012]
6.2.2 CMM Emissions from Abandoned Coal Mines
Closed coal mines on Cape Breton Island in Nova Scotia may hold the greatest promise for
abandoned mine methane (AMM) recovery in Canada. Four closed mines on Cape Breton Island
near New Waterford (the Phalen and Lingan collieries), Glace Bay (No. 26 mine) and at the
northeastern tip of Boularderie Island (Prince colliery) were large, high production longwall
operations when operating. The No. 26 colliery opened in 1944, and the other three mines began
operations between 1972 tol975. Attheir peak, the No. 26 produced 900,000 tonnes, the Lingan
mine produced nearly 2 Mmt of raw coal and the Prince colliery produced nearly 1 million tonnes of
coal (Nova Scotia Department of Mines, 1985). The No. 26 colliery operated until 1984 when it
closed due to a fire. The Lingan colliery closed in 1992, the Phalen closed in 1999 and the Prince
colliery closed in 2001. A fifth mine, the Donkin mine on Cape Breton Island began development in
1987 and operated for several years in the 1990s, but also closed in the 1990s. However, a
significant effort is underway to reopen the Donkin mine, with several permitting steps already
accomplished. Although information on methane emissions is limited, the Phalen mine was
considered a gassy mine. However, a significant challenge with AMM recovery from any of these
mines is that they are submarine mines extending underneath the surface of Atlantic Ocean
requiring an offshore production system or use of horizontal drilling from the surface. Flooding of
the mine workings is also a potential problem.
In addition to these mines, several other smaller mines have operated in Nova Scotia (Nova Scotia
Department of Mines, 1985).
6.2.3 CBM from Virgin Coal Seams
Assessing the extent of coal bed methane (CBM) prospects in Canada started within the last decade.
The results are illustrated in Figures 6-3, 6-4, and 6-5 on following pages. According to the
Canadian Gas Potential Committee, however, they could be anywhere between 5.3 and 13 trillion
m3. These estimates are from exploration mainly in the Western Canada Sedimentary Basin. Table
6-6 lists the major Canadian CBM exploration sites.
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Table 6-6. Canada's Major CBM Reserves
Location
Reserves
(trillion cubic meters)
Horseshoe Canyon 1.04
Pembina (including Ardley) 0.84
Mannville 4.76
Alberta/BC Foothills (Gates/Mist Mtn) 3.7
Source: AAPL (2005)
Canadian coal seams with CBM potential are found beneath much of Alberta, especially in the
southern and central regions, in which the Alberta Geological Survey (AGS) have estimated there
could be as much as 14 trillion m3 (about 500 trillion cubic feet or Tcf) of CBM held in Alberta coal
(AGS, 2013). The primary CBM potential areas in Alberta are the Ardley, Horseshoe Canyon, and the
Mannville coal zones, with the Upper Manville being the gassiest zone. Alberta offers particularly
favorable conditions for CBM development as the geology of CBM deposits are relatively simple and
uniform over a wide area (Amazouz, 2006). Within BC, the major concentration is in the northeast
and to a much lesser extent in the southeast of the province, amounting to a total of 2.5 trillion m3
(BC, 2002). Nova Scotia forms the third largest portion of the Canadian CBM reserve.
Figure 6-3. Location of Probable
Economically Recoverable CBM
Reserves in Canada (trillion cubic
feet)
¦ Alberta
~ British
Columbia
¦ Nova Scotia
Figure 6-4. Primary CBM Potential
Areas in Alberta
Source: AEUB (2004)
Source: AEUB (2004)
The CBM industry is relatively new in Canada compared to its neighbor, the United States. However,
in Alberta alone, there were more than 3,500 CBM wells in place by 2004, with most of these
Met ha n e initiative CMM Country Profiles 55
0 100 200 km
l>li I
~
n
~
m
~
n
Mannville Group
Horseshoe
Formation
Belly River Group
Scollard Formation (Ardley)
Kootenay Group
Luscar Group
[p"B i AGS
I b)h*Mf Snr
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concentrated in Alberta and BC (Snyder, 2005). A forecast report projected annual CBM production
of 14.5 billion m3 by 2015 for all of Canada (NAEWG, 2005; Amazouz, 2006).
The first Canadian methane production began in 2002 in the Horseshoe Canyon region in Alberta.
The Horseshoe Canyon coals are dry and relatively close to the surface, enabling easy gas recovery.
Therefore, these fields accounted for 90 percent of the producing wells in Alberta in 2005 (Snyder,
2005), generating more than 2.8 million m3 per day of methane. Alberta's CBM production in 2005
totaled 2.5 billion m3 (Amazouz, 2006). By 2008, there were 6000 wells producing 5.2 billion m3per
year, all located in Alberta (International, 2008). By 2010, a total of 14,000 wells had been drilled
(not all of which are active) and production is approximately 7.2 billion m3 per year (Ember, nd).
Figure 6-5. CBM Potential in British Columbia
Coal Rivet
Coalfield
~6Bcf
Klappan and
Groundhog I
Coalfields
up to 8.1 Tcf
Peace River
Coalfield -
66-200 Tcf
Tclkwa
Coalfield .
p tit l.iO Ri f
Telkwa
Prince Rupert
"W >;
i, Bowron River '•?
V\ Coalfield
V' up to 50 Bcf
j Island. nSV<3
^Coalfielda^^
Hat Creek-.
Coalfield J
up lo 0.5 Tci
East Kootenay
Coalfields
-19 Tcf 1
^33 Tcf incl
Saquash Coalfit
up to 45 Bcf
Cajpox Coalfiek
Princetoni
Coalfield
V 80 Bcf
N.ui.lifUn CoalfiettK&>
up to 3Q0 Bcf
Tulameen
BCf/d
Coalfields and Coalbed Methane Potential
in British Columbia
Sedimentary Basins
Mines
a Fording River
b Greenhills
*5? C Line Creek
d Elkview
"X1 6 Coal Mountain
"5? f Bullmoose
g Quinsam
*5? h Willow Creek
Properties
Wolvenne*Perry Creek (W&PC)
Tulameen
Tsable River
Telkwa
Gas Pipeline
Oil Pipeline
Alliance Pipeline
MMCf/d Million Cubic Peel per da\
BCf/d Billion Cubic Feet per day
Area Underlain by Coal
(above 2000 m depth)
Anthracite
Coking
High Volatile Bituminous
Sub-bituminous to Lignite
¦*1
Estimated Coalbed Methane Gas in Place
(to maximum 2000 m depth)
Bcf = Billion Standard Cubic Feet
Tcf = Trillion Standard Cubic Feet
Tulameen
Coalfield
-42 Bcf
Basin Outlines : Geological Survey ofCanada. unpublished: P. Hannigan, P.J. Lec, K Osadetz et a!.. 1993-1998.
Source: BC (2002)
Additional CBM Exploration and Production
A number of companies have explored CBM projects on Vancouver Island where the coal rank is
bituminous with cumulative coal seam thickness of 23 feet. Priority' Ventures Ltd. conducted some
test drilling in 2001, while Quinsam Coal Corporation allied with Cornerstone Gas to explore CBM
development on the island (BC, 2009).
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Trident Exploration worked with Husky Energy to develop CBM in the Fenn Rumsey area. The joint
venture started in 2002, was extended in 2004, and planned to drill some 400 exploratory wells by
2006 (Husky, 2005). In a second project, Trident worked with Nexen and Red Willow to start the
first CBM venture in the Mannville formation in Alberta (Bennettjones, 2005), and by 2008, they
had completed 650,000 meters of drilling in Mannville (Trident, 2008). Royal Dutch Shell had
licenses for tenure to explore for CBM in the Klappan area of northwest BC, but a four-year
moratorium has been declared on development of CBM resources in that region (Shell, 2008) and
the BC government officially ruled the Klappan region off-limits for further gas exploration
(Vancouver Sun, 2012). BP had tenure at its CBM project at Mist Mountain in southeast BC, but later
sold its Western Canadian upstream gas assets to Apache Corporation (BP, 2010).
By mid-2008, approximately 60 CBM exploration wells had been drilled outside of Alberta but no
commercial production existed. The BC and Nova Scotia coals generally exhibited low permeability,
and coals in Ontario and Saskatchewan showed insufficient gas for commercial production
(International, 2008). But by December 2008, GeoMet Inc. began the first commercial delivery of
CBM from the Peace River project in BC (GeoMet Inc., 2009). By January 2009, Nova Scotia also had
three CBM projects, two of which are Stealth Ventures Inc. projects in Cumberland and Stellarton
basins. The third project is in the Sydney basin of northern Nova Scotia (Prospect Profile, 2009).
In April 2012, Toyota Tsusho Corp. invested more than $600 million to acquire a share of Encana
Corporation's extensive CBM reserves in southern Alberta, and the Japanese company will acquire a
32.5 percent royalty interest in about 5,500 existing and future Encana CBM wells (Encana, 2012).
6.4 Opportunities and Challenges to Greater CMM Recovery
and Use
Canada is a signatory to both the UNFCCC and the Kyoto Protocol (see Table 6-7). As an Annex I
Party, its emissions target under the Kyoto Protocol is to achieve a 6 percent reduction of 1990
greenhouse gas emission levels by 2010.
Table 6-7. Canada's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 12,1992
December 4,1992
Kyoto Protocol
April 29,1998
December 17,2002
Source: UNFCCC (2014]
Canada has demonstrated its commitment to addressing climate change by providing international
climate finance in support of mitigation actions by developing countries and support for adaptation
by the poorest and most vulnerable countries. This included Canada's fast-start financing
contribution of $1.2 billion (from 2010 to 2012) to support a range of climate change projects in
more than 60 developing countries, as announced in Durban (Government of Canada, 2014).
Canada withdrew from the Kyoto Protocol agreement in 2012, and began extending its efforts
beyond the UNFCCC by working with other countries through complementary forums such as the
Arctic Council, for which Canada has assumed the two-year chairmanship through 2015, and the
Climate and Clean Air Coalition (CCAC) to develop practical and collaborative initiatives to reduce
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GHG emissions and short-lived climate pollutants (Government of Canada, 2014). In 2013, Canada
announced its commitment of an additional $10 million—on top of its $10 million commitment in
2012—to the CCAC. Canada, together with the United States and Mexico, is also leading
international efforts to use the expertise and institutions of the Montreal Protocol to phase out
hydrofluorocarbons production and consumption.
6.4.1 Market and Infrastructure factors
The major issues that concern the Canadian CBM industry are geology, land consolidation and
access, freehold leases, water disposal (both brine and fresh), regulatory matters, and CBM
technology (Ziff, 2004). In general, all CBM projects are private-industry-driven in Canada, with
companies typically forming partnerships (i.e., joint ventures) to commercially develop CBM
projects.
Canada joined the Global Methane Initiative (formerly the Methane to Markets Partnership) in July
2005. Canada's efforts thus far, however, have been largely limited to the oil and gas industry
(Canada is a member of the GMI Oil and Gas Subcommittee). Long-term consumption of natural gas
is expected to grow steadily in Canada, while domestic production of conventional natural gas is
believed to have peaked in 2003 (Amazouz, 2006). The expected shortfall will be met by a number
of alternative natural gas resources:
¦ Mackenzie Delta and Beaufort Sea fields
¦ Other remote gas fields (north of 60th parallel)
¦ Liquefied natural gas importation
¦ Offshore East Coast and West Coast gas fields
¦ CBM reserves estimated at 4.7 trillion m3 (CAPP, 2004)
Canada is also pursuing other avenues of alternative gas resources. In 1996, Natural Resources
Canada's Canmet Energy Technology Centre -Varennes initiated the development of a catalytic
reactor that could, both technically and economically, recover the methane of coal mine ventilation
air. The technology, called CH4MIN, recovers the energy of the dilute ventilation air methane, with
an efficiency varying between 40 and 95 percent, depending on the methane concentration in the
ventilation air (Amazouz, 2006). The CH4MIN was tested at bench scale at the CANMET lab in
Quebec and large pilot-scale at the now closed Phalen Coal Mine in Nova Scotia. CANMET has
licensed the technology to several companies including the current global license holder,
Sindicatum Sustainable Resources. Sindicatum built and operated a commercial-scale 15 m3/sec
(32,000 cfm) demonstration reactor to test the CH4MIN technology under field conditions. The
company is exploring the economic viability of the CH4MIN technology in China (Talkington, 2014).
Further on R&D front, the Alberta Research Council (previously known as the Alberta Chamber of
Resources) has been collaborating with the American, Canadian, and other international
governments to improve CBM recovery efficiency (ACR, 2003). Non-nuclear government R&D
spending is managed by Natural Resources Canada. The Program of Energy Research and
Development (PERD), managed by Natural Resources Canada's Office of Energy Research
(OERD15), is the major source of government funding for non-nuclear public and private research
and development. Natural Resources Canada's Energy Technology Branch (ETB), which includes
three laboratories in the Canada Centre for Mineral and Energy Technology, is the largest federal
participant in, and manager of, non-nuclear science and technology programs. ETB receives a large
share of PERD funds.
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Canadian infrastructure is also being adapted to keep in step with its growing CBM/CMM industry.
The Alberta Energy and Utilities Board (AEUB) recently approved Canada's major pipeline network
for natural gas transportation, TransCanada Pipelines, to reconfigure its system to allow the low-
pressure intake of CBM (Bennettjones, 2005). CBM has to compete with other sources of Canadian
gas in order for it to be purchased by pipelines that transport the gas to the U.S. or Canadian
consumers.
6.4.2 Regulatory Information
Initially, there was controversy regarding the ownership of CBM rights in Canada since coal and
natural gas come under different jurisdictions. CBM rights in both BC and Alberta now follow the
legal framework for natural gas. The provinces own and can sell the rights to develop CBM at their
discretion. The Coalbed Gas Act clearly attributes all CBM rights to the owners of natural gas
mineral rights and none to the owner of coal rights (ASB, 2004). This was upheld by the Alberta
courts in 2011 (Canadian Energy Law, 2011). Canadian regulations enforce consultation with
affected stakeholders and governments before development begins (CAPP, 2003). In BC, a potential
producer must get Petroleum and Natural Gas tenure rights before production (BC, nd). In Nova
Scotia, the Petroleum Resources Act recognizes coal gas as a distinct resource but has included it
with the definition of petroleum as "coal gas, existing in its natural condition in strata." A specific
coal gas agreement is also required before exploration, development, or production of CBM (Blakes,
2006). In Saskatchewan, CBM is defined by The Petroleum and Natural Gas Regulations of 1969 and
is administered just like any other petroleum or natural gas development (Saskatchewan, nd).
Canada does not have federal tax credit incentives in place to stimulate investment in CBM
technologies because legislative power rests largely with provincial governments. BC relies on a
royalty incentive program to encourage CBM production. Recent amendments to the BC Petroleum
and Natural Gas Royalty Freehold Production Tax Regulation allow water treatment costs to be
included in the producer's cost of service allowances for CBM wells, place the production threshold
at 17,000 m3/day before a royalty is imposed on a CBM well, and raise the royalty credit on each
well to $50,000 (BC Royalty, nd).
In the Petroleum and Natural Gas Act, CBM projects are not subject to well-spacing regulations
(more wells are often required per field compared to natural gas resources) and CBM production
data can stay confidential for an extended period (ASB, 2004).
CBM producers are subject to strict rules that apply at every stage of project development All the
federal and provincial wildlife and environmental laws and the elaborate industry-specific
regulations apply to the CBM producers as well (CAPP, 2003).
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6.5 Profiles of Individual Mines
Ardley and Lower Edmonton Mines, Alberta
General Overview
Total mining area, km2
Several hundreds
No. of coal seams
1-30
Total methane resource
0.84 trillion cubic meters
Rank of coal
Sub-bituminous, high-volatile
Cumulative thickness
Up to 25 meters
Depth of mining
200 to 700 meters
Moisture
Dry
Gas content average
1.87 m3/tonne
Mining method
Surface
Upper Mannville Mines, Alberta
General Overview
No. of coal seams
2-5
Total methane resource
4.76 trillion cubic meters
Rank of coal
Bituminous
Cumulative thickness
Up to 20 meters
Depth of mining
800 to 1500 meters
Moisture
High (dewatering required]
Gas content average
9.4- 15.6 m3/tonne
Mining method
Surface
Source: Sproule (2004]
6.6 References
AAPL (2005): Regulation of the CBM Industry in the United States and Canada, presented at the American
Association of Professional Landmen Annual Meeting, Banff, Alberta, Canada, 2 July 2005.
ACR (2003): Coal bed methane the energy industry's next big play?, Alberta Chamber of Resources, 2003.
AEUB (2004): EnerFAQs 10: Coalbed Methane, Alberta Energy and Utilities Board, 11 February 2004.
AGS (2013): "Coalbed Methane" page, Alberta Geological Survey, last modified on 17 June 2013.
h ttp: II www, a gs. go v. a b. ca /en er gv / chm /
Amazouz (2006): Information provided by Mouloud Amazouz, Natural Resources Canada, 2006.
ASB (2004): Coal Bed Methane: the Past, Present and Future of Alberta's Most Abundant Non-traditional Source
of Natural Gas, Alberta School of Business, 2004. http://business.ualberta.ca/centres/applied-research-
energy-and-environment/energy/%7E/media/98EB3F7A9723481AACD9D988DDD2C465.ashx
BC (2002): Coal in British Columbia, Ministry of Energy, Mines, and Petroleum Resources, Government of
British Columbia, 2002. http: //www.empr.gov.bc.ca/MINING/GEOSCIENCE/Pages/default.aspx
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BC (2009): British Columbia Oil and Gas Exploration Report 2007-2008, Legislative Assembly of British
Columbia, 2009.
http://www.llbc.leg.bc.ca/public/pubdocs/bcdocs/405260/exploration report 2007 2008.pdf
BC (nd): Coalbed Gas, Ministry of Energy, Mines, and Petroleum Resources, Government of British Columbia,
not dated.
http://www.empr.gov.hc.ca/OG/oilandgas/petroleumgeologv/CoalhedGas/Pages/default.aspx
BC Royalty (nd): Coalbed Gas Royalty Program, Ministry of Energy, Mines, and Petroleum Resources,
Government of British Columbia, not dated.
http://www.empr.gov.hc.ca/OG/OILANDGAS/ROYALTIES/Pages/CoalhedGas.aspx
Bennettjones (2005): Canadian Energy Investment Backgrounder,Bennettjones LLP, 2005.
http://www.bennettiones.ca/Images/Guides/updatel832.pdf
Blakes (2006): Coalbed Methane - Split Title, Blakes.com, 1 March 2006.
http://www.mondaq.com/canada/x/38984/Utilities/Coalbed+Methane+Split+Title
BP (2010): BP Signs North America and Egypt Asset Deals with Apache, BP, 20 July 2010.
http:// www.bp.com/en / global / corporate / press / press-releases /bp-signs-north-america-egypt-assets-
apache.html
CAC (2003): Coal Kit: Module 1 - Evolution, The Coal Association of Canada, 2003. http://www.coal.ca/wp-
content/uploads /2012/04/modulel evolution.pdf
CAC (2006): "Coal Related Maps," The Coal Association of Canada, 2006.
CAC (2014): Careers in Coal Mine Map, The Coal Association of Canada, accessed in July 2014.
http://www.careersincoal.ca/mine-map/
Canadian Energy Law (2011): Natural Gas Rights Holders Win Big in Landmark CBM Litigation, Michael
Mestinsek, 19 July 2011. http://www.canadianenergylaw.com/tags/coalbed-methane/
CAPP (2003): Environment & Community FAQs, Canadian Association of Petroleum Producers, 2003.
http: II www, capp.ca /library / faq /Pages / Envir onmentFAO. aspx
CAPP (2004): Outlook for Natural Gas Supply from Western Canada, Canadian Association of Petroleum
Producers, 2004.
CCPC (2010): The Role of Coal, Canadian Clean Power Corporation, 2010.
http://www.canadiancleanpowercoalition.com/index.php/power-generation-in-canada/the-role-of-
coal/
EIA (2012): Country Analysis Briefs - Canada, U.S. Energy Information Administration, Washington, DC, last
updated 17 September 2012. http://www.eia.gov/countries/cab.cfm?fips=CA
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, accessed July 2014.
http://www.eia.gov/cfapps/ipdhproiect/IEDIndex3.cfm
Ember (nd): Information on Coalbed Methane and CBM Drilling, Ember Resources, not dated.
http://emberresources.ca/coalbed-methane/cbm-background/
Encana (2012): "Toyoto Tsusho invests C$600 million in Encana's coalbed methane development in southern
Alberta," Encana Corporation, 20 April 2012. http: //www.encana.com/news-stories/news-
releases/details, html ?release=6659 64
GeoMet Inc. (2009): GeoMet Announces Commencement of Gas Deliveries from British Columbia Coalbed
Methane Project, geometinc.com, 5 January 2009. http: //www.geometinc.com/home/PR01-05-Q9.aspx
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed in July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
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Government of Canada (2014): Canada's Action on Climate Change, Government of Canada, accessed July
2014. http://www.climatechange.gc.ca/default.asp?lang=En&n=E18C8F2D-l
Husky (2005): Husky Energy Announces 2005 Third Quarter Results, Lexdon - The Business Library, 18
October 2005. http://www.lexdon.com/article/Husky Energy announces 2005 third/13947.html
International (2008): Coalbed methane development in Canada- challenges and opportunities, presented at
thelnternational Geological Congress - Oslo 2008, \ August 2008.
http://www.cprm.gov.br/33IGC/1324175.html
Mining Exploration News (2008): Teck Cominco, Coal Mine Industry Company, Buyout Fording Canadian Coal
Trust, Paguntaka.org, 30 July 2008.
NAEWG (2005): North American Natural Gas Vision Report 2005, North American Energy Working Group
Experts Group on Natural Gas Trade and Interconnections, January 2005.
http://www.wilsoncenter.org/sites/default/files/nothamericangasvision.pdf
Nova Scotia Department of Mines (1985): Coal in Nova Scotia, Nova Scotia Department of Mines, 2005.
http://novascotia.ca/natr/meb/data/pubs/is/is08.pdf
NRC (2005): Year in Review, Natural Resources Canada, 2005.
NRC (2011): Year in Review, Natural Resources Canada, 2011. http: IIwww.coal.ca/wp-
content/uploads/2 013/12/NRCAN-Coal-Report-2011.pdf
NRC (2012): Year in Review, Natural Resources Canada, 2012. http: //www.coal.ca/wp-
content/uploads/2 014/09/Coal-2 012-Annual-Review.pdf
NRC (2014): Coal and CO2 Capture & Storage, Natural Resources Canada, modified 24 June 2014.
http://www.nrcan.gc.ca/energv/coal/4275
Prospect Profile (2009): Nova Scotia Prospect Profile Onshore 2009, Government of Nova Scotia, January
2009.
Saskatchewan (nd): Natural Gas in Coal, Energy and Resources, Government of Saskatchewan, not dated.
http://www.ir.gov.sk.ca/Default.aspx?DN=5108.3384.2936.Documents#sect2a
Shell (2008):Shell faces coal-bed moratorium in northern B.C., Royal Dutch Shell pic, 6 December 2008.
http://royaldutchshellplc.eom/2008/12/06/shell-faces-coal-bed-moratorium-in-northern-bc/
Snyder (2005): North American Coalbed Methane Development Moves Forward, World Oil Magazine, Robert
E Snyder, Executive Engineering Editor, July 2005.
Sproule (2004): Overview of Coalbed Methane in Canada, Sproule Worldwide Petroleum Consultants, 2005.
Talkington (2014): Interview with Clark Talkington, Advanced Resources International, Inc., Arlington,
Virginia, USA, 6 November 2014.
Trident (2008): Trident Resources Corp. - About Us, Trident, 2008.
UNFCCC (2014): Ratification Status - Canada, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=CA
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
Vancouver Sun (2012): "Klappan region permanently off-limits to gas exploration, B.C. announces,"
Vancouver Sun, 18 December 2012.
http://www, vancouversun.com/business/2 035/Klappan+region+permanentlv+limits+exploration+ann
ounces/7715067/story.html
Ziff (2004): Coalbed Methane - A Significant Gas Supply from Western Canada, Ziff Energy Report, 2004.
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7.1 Summary of Coal Industry
7.1.1 Role of Coal in China
Coal accounts for 69 percent of total national energy consumption in China (EIA, 2014a). Ranking
first in the world in production of coal, China exported 16.5 million tonnes (Mmt) of coal in 2011; a
sharp decline from a peak of 108.8 Mmt in 2003 (EIA, 2014b). Historically, a net coal exporter,
China became a net coal importer in 2009 for the first time in more than two decades (EIA, 2014a).
Table 7-1 provides recoverable reserve and recent coal production data for China.
Table 7-1. China's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous &
Lignite
(million tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
62,200
52,300
114,500
3 (12.9%]
Annual Coal Production (2012]
3,510.2
141.5
3,651.8
1 (46.3%]
Note: Numbers may not add due to rounding
Source: EIA (2014b]
As shown in Figure 7-1, the following major coal basins are located in four regions of China (USEPA,
1996):
¦ Sanjuang-Mulinghe, Songliao, Donhua-Fushun, and Hongyang-Hunjiang basins in the
Northeast;
¦ Taixing-Shandou, Qinshui, Daning Ordos, Hedong Yuxi, Xuhuai, and Huainan basins in the
North;
¦ Chuannon-Qianbei, Huayingshan-Yongrong, and Liapanshui basins in the South; and
¦ Tarim, Qaidam, and Junggar basins in the Northwest
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Figure 7-1. China's Coal Fields
CHINA'S COAL BASINS AND COALBED METHANE RESOURCES
Zhunbei (N. Junggar)
Zhunnan (S. Junggar!
You'erdusi
Songliao Nanyuan
Yilan-Yitong
Jiaohe-Liaoyuan
Wuqla
Kunlun
Hongyang-
Hunjiang
Guangfang
Luzhong
Luxinan
Lunan
Xuhai
Huainan
Suzhe-Wanbian
Cbangjiang Zhongxia You
(Lower Yangtze River)
Nanning
r
~ Wuganbian
^Zheganbiar
- Pingdong
"* Jiyou
Yongmei
^ \ Yubei (Old Canton)
Liffllshao Guangzhou
Source: Liu (2006)
7.1.2 Stakeholders
Table 7-2 identifies some of the key stakeholders for coal mine methane (CMM) project
development in China.
Table 7-2. Key Stakeholders in China's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies
¦ Large coal groups, such as:
Project hosts
¦ Chongqing Energy Investment Group
¦ Datong Coal Group
¦ Fushun Mining Group
¦ Hebi Coal Industiy Group
¦ Henan Energy and Chemical Group
¦ Huaibei Mining Group
¦ Huainan Mining Group
¦ Jincheng Anthracite Coal Group
¦ Panjiang Coal & Power Group
¦ Shenhua Group
¦ Shenhuo Group
¦ Shuicheng Mining Group
¦ Songzao Coal & Power Group
¦ Tiefa Mining Group
¦ Xinji Group
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Table 7-2. Key Stakeholders in China's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies (con't]
¦ Yangquan Coal Group
¦ Zhengzhou Coal Group
Project hosts
Equipment manufacturers
¦ Atlas Copco
Methane treatment and
¦ Capstone Turbine Corporation
utilization equipment
¦ Caterpillar
¦ GE Jenbacher
¦ Shengli Power Machineiy
Developers
¦ China National Petroleum Corporation
Project opportunity
¦ China United Coalbed Methane Corporation Ltd.
identification and
¦ CBM Exploitation and Development Company of the
planning
PetroChina Company Ltd.
¦ Far East Energy
¦ Lanyan CBM Company of the Jincheng Anthracite Coal
Mining Group
¦ Sindicatum Carbon Capital, SCC Americas
¦ See also www.epa.gov/coalbed/networkcontacts.html
Engineering, consultancy.
¦ China Coalbed Methane Clearinghouse, affiliated with the
Technical assistance
and related services
China Coal Information Institute
¦ Guizhou International Cooperation Center for
Environmental Protection
¦ See also www.epa.gov/coalbed/networkcontacts.html
Universities, Research
¦ China Coal Research Institute
Technical assistance
Establishments
¦ China University of Mining and Technology
¦ China University of Petroleum, Beijing
¦ China National Administration of Coal Geology
¦ China Coal Information Institute
Regulatory Agencies and
¦ National Development and Reform Commission
Project identification
Government Groups
¦ National Institute for Occupational Safety
¦ State Administration of Coal Mine Safety, within State
Administration of Work Safety
¦ China National Coal Association
¦ International Exchange Center of National Work Safety
Administration
and assessment support
Source: GMI (2005], Huang (2007]
7.1.3 Status of Coal and the Coal Mining Industry
China is the world's leading producer of coal, producing almost 3.56 billion tonnes of coal in 2012
(Table 7-1). In 2013, production continued to rise at nearly a one percent increase on ayear-on-
year basis, with 3.68 billion tonnes (Huang 2014).
Coal is produced throughout China in 28 provinces. Northern China, particularly Shanxi, Inner
Mongolia, Shaanxi, and Xinjiang Provinces, contain most of China's easily accessible coal and
virtually all of the large state-owned mines (EIA, 2014a).
China has a large number of coal mines but has been attempting consolidation. It is estimated that
in the mid-1990s, there were nearly 100,000 coal mines in China (IEA, 2009). The majority of these
mines belonged to villages and towns. In the last decade, China has implemented programs to close
down underperforming or unsafe mines, especially town and village coal mines. China's State
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Council has mandated the phasing out of mines producing less than 90,000 tonnes of coal per year.
China's National Energy Administration (NEA) reports that 1,725 small-scale mines will be closed
in 2014, with a total capacity of 117.48 Mmt (NEA, 2014).
As of 2014, there are approximately 12,000 coal mines operating in China (EIA, 2014a). Of these,
2,059 mines are owned by large, state-owned coal mine groups (known as "key coal mine groups"),
accounting for 61.7 percent of total coal production. An additional 10,067 mines are operated by
villages and towns (Guoquan, 2010). See Table 7-3 below.
Most coal mines in China are underground mines. As of 2012, underground mining accounted for
90 percent of Chinese coal production (Huang, 2013a).
Table 7-3. China's Mines by Category and Percent of Total Production (2004)
Mine Category
Number of
Percent of Total
Mines
Production
Local State-owned Key Coal Mine Groups
1,190
12
Other State-owned Key Coal Mine Groups
869
49.7
Mines Belonging to Villages and Towns
10,067
38.2
Source: Guoquan (2010]
7.2 Overview of CMM Emissions and Development
Potential
Large, state-owned coal mines dominate Chinese coal production and CMM emissions. About 44
percent of large, state-owned mines are considered gassy (Huang 2013a). Large, state-owned
mines accounted for more than 86 percent of CMM emissions (2000), and produced 42 percent of
total national coal production in 2004 (Zhang et al., 2004).
7.2.1 CMM Emissions from Operating Mines
Increasing numbers of Chinese mines are installing drainage (degasification) systems. By 2006,
more than 300 mines had installed CMM drainage systems (Huang 2007) and as of 2011 this
number had increased to 1,047 (Huang 2013a). China's CMM drainage volume experienced a five-
fold increase between 2005 and 2013, reaching 12.6 billion cubic meters (m3), up from 2.2 billion
m3 in 2005 (Huang 2014). Approximately 80 percent of all CMM drained was from key, state-
owned coal mines (Huang 2007). The volume of CMM recovered and used in 2012 was 3.75 billion
m3, more than six times 2005 levels (Huang, 2013a).
In 2011 China's mines emitted more than 19 billion m3 of ventilation air methane (VAM), almost 8
billion m3 of which was emitted from large, state-owned mines (Huang 2013a).
Table 7-4 shows historical data (where available) for CMM emissions, drainage, and utilization
levels in China.
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Table 7-4. China's CMM Emissions (million cubic meters)
Year CMM Emissions CMM Drainage CMM Utilized
2000
9,435*
870
318.4
2005
18,005*
2,300f
900f
2010
20,694*
7,500**
2,500ft
2011
9,200**
3,500A
2012
11,400**
3,500AA
2013
12,600+
4,2 50+
2015(projected]
22,490*
Sources: GMI (2005]; *USEPA (2012a]; **Huang (2013a]; fHuang (2007]; ffCCII (2011];
AHuang & Liu (2012]; AAHuang (2013b]; +Huang (2014]
In China, the main types of CMM use projects are town gas, electricity generation, industrial boiler
fuel feed, vehicle fuel, and thermal applications (e.g., office space heating). Some Chinese CMM
projects involve multiple end uses. As of 2013, China's CMM use projects utilized 4.25 billion m3 of
methane (Huang, 2014). CMM-to-power projects generated a total of more than 1,500 MW of power
by the end of 2011 (Huang 2013a). Additionally, approximately 4,000 vehicles operate on CMM as
fuel (Huang 2010).
As technology has advanced, the utilization efficiencies of CMM projects have also improved,
increasing the size of individual projects (Huang, 2007).
The largest CMM power project in the world is located at the Sihe Mine in Jincheng, Shanxi
Province. This project uses Caterpillar engines to generate electricity at a 120-MW capacity power
plant. The project utilizes more than 187 million m3 of both coal bed methane (CBM) and CMM from
the Sihe mine (USEPA, 2006; Huang, 2008; Huang 2013a; Sun, 2014). The Sihe project avoids the
release of more than 3 million metric tons of carbon dioxide equivalent (MMTCO2E) annually (Sun,
2014).
Use of CMM resources is being expanded for application in the chemical industry in China. For
example, formaldehyde and carbon black are being produced using CMM in Fushun, Huainan,
Zhongliangshan, Songzao, andTianfu.
Information on individual CBM/CMM use projects in China can be found in the Global Methane
Initiative (GMI) International CMM Projects Database, which includes information on more than
350 current and planned CMM projects around the world (GMI, 2014). The database includes 67
active CMM projects in China, all at active underground mines. Of these projects, seven use CMM as
boiler fuel; four provide methane for industrial use; 29 use CMM for power generation; 14 provide
town gas; two provide vehicle fuel; and three are VAM mitigation projects (GMI, 2014).
China is host to the first VAM project approved by the UNFCCC. The VAM abatement and energy
recovery project was commissioned in October of 2008 in Zhengzhou and provides hot water for
local use (Mattus, 2012). Annual emission reductions average 382 thousand MTCO2E (UNFCCC,
2008). Additionally, at the Datong mine in Chongqing Municipality, hosts the largest VAM
abatement system in the world, operating since mid-2011. This project, which includes hot water
for local use, reduces greenhouse gas (GHG) emissions by approximately 184 MTCO2E per year
(Mattus, 2012; UNEP, 2014).
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Chongqing Energy Investment Group Corporation, Chongqing Songzao Coal and Electricity Co., Ltd.
and DKT Technology, signed a joint venture for construction and operation of a CMM project at the
Songzao coal mines. This project is a result of a feasibility study funded by the U.S. Environmental
Protection Agency (U.S. EPA). DKT will construct a CMM to liquefied natural gas (LNG) plant that
will connect to Songzao's gas pipeline network. The plant will use CMM with a concentration of 30
percent methane in air as feed gas. The plant capacity is designed to process 15,000 standard m3 of
CMM per hour yielding 35 million m3 of methane per year. Due to expected fluctuations of CMM
flow and concentration, production will vary from 30 to 40 million m3 (25,000 - 30,000 tonnes) of
LNG per annum (DKT, 2015).
7.2.2 CMM Emissions from Abandoned Coal Mines
The China Coal Information Institute (CCII) established the Abandoned Mine Methane Project
Advice Centre (AMMPAC) to advise and promote the country's abandoned mine methane (AMM)
use (CCII, 2010). Initially funded by the UK Foreign and Commonwealth Office through its Climate
Change Challenge Fund, the program was designed to help build capacity for CCII to provide
guidance and disseminate training to mining enterprises and project developers, through activities
ranging from assistance evaluating and developing AMM schemes to technical guidance documents
to assistance finding potential investors and technical specialists (Creedy et al., 2010). Further
information about this program is available at http: //www.coalinfo.net.cn/cnuk/eprojects/05.htm.
Additionally, GMI funded a cooperative agreement to investigate abandoned mine methane
emissions in China entitled, "Methane Emissions from Abandoned Coal Mines in China."
Information about this project and results of analysis can be found atwww.chinamethane.org.
The closing of state-owned coal mines and town and village coal mines that do not meet production
and safety requirements has left a large number of abandoned mines throughout China. Hundreds
of coal mines have been abandoned since the 1950s and abandoned reserves are estimated at more
than 30 billion tonnes. To date, no AMM projects have been initiated in China.
CCII's Xi'an branch has also studied AMM resources in China, focusing on detailed geological
conditions, characteristics of AMM reservoirs, gob/goaf area and coal reserve estimation, ground
water study and mine gas sampling and AMM resource estimation (CCBMC, 2004).
7.2.3 CBM from Virgin Coal Seams
China's CBM resources contained in bituminous and anthracite coal deposits at depths between 300
and 2000 meters are estimated to be 36.8 trillion m3 (Huang, 2010; Huang 2013a). Figures 7-2 and
7-3 display China's distribution of CBM resources by region and depth.
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Figure 7-2. China's CBM Resources by Region
China's CBM Resources by Region
(trillion m3)
4.7
Southern
Western
Eastern
Central
11.3
31%
Source: Huang (2013a)
Figure 7-3. China's CBM Resources by Depth
China's CBM Resources by Depth
(trillion m3)
11.9
32%
143
39% ¦ 300-1000m
¦ 1000-1500m
¦ 1500-2000m
10.6
29%
Source: Huang (2013a]
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The total production of CBM has increased dramatically within the last decade as shown by Figure
7-4. Total Chinese CBM production was estimated to be 3.5 billion m3 in 2013. The national
production target for CBM is 10 billion m3 by 2010 (Huang, 2007; EIA (2009); Merrill, 2007).
Figure 7-4. China's Annual CBM Production
CBM Extraction Volume
(billion m3)
Source: Huang (2013a]
By the end of 2012, a total of 12,547 CBM wells had been drilled in China. Of these, 4,420 wells have
been drilled by the Jincheng Anthracite Mining Group (JAMG). JAMG had 2,650 wells in production
in 2012, producing 3.9 million m3 per day for an annual total of 713 million m3 (Huang 2013a).
Between 2011 and 2015, China National Petroleum Corp. (CNPC), China's largest oil and gas
producer, is investing $1.14 billion in drilling 371 horizontal wells in the Zhengzhuang Qinnan,
Mabi, and Xiadian blocks of the Qinshui Basin in Shanxi Province to increase annual production
capacity (China Coal Resource, 2010; CNPC, 2013). In 2011, CNPC enhanced CBM production
capacity in the Qinshui Basin and expanded into the eastern edge of the Ordos Basin, supplying 420
million m3 of commercial CBM. In 2012, CNPC proved 78.8 billion m3 of CBM in place, built an
additional 1.35 billion m3 of production capacity, and supplied 600 million m3 of commercial CBM
(CNPC, 2013).
7.3 Opportunities and Challenges to Greater CMM Recovery
and Use
China is a signatory to both the UNFCCC and the Kyoto Protocol (Table 7-5). As a Non-Annex I Party
to the Kyoto Protocol, China was eligible to host GHG mitigation projects, such as CMM projects,
under the Clean Development Mechanism (CDM). The CDM created additional revenues for CMM
projects in China through carbon credits trading. As of 2014 China had 3,750 registered CDM
projects. Of these, 83 are CMM projects (UNEP, 2014).
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Table 7-5. China's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
Kyoto Protocol
UNFCCC
June 11,1992
May 29,1998
January 5,1993
August 30, 2002
Source: UNFCCC (2014]
Though China has no emissions targets under the UNFCCC or Kyoto Protocol, China's government
announced in November of 2009 that it would cut emissions of carbon relative to economic growth
by 40 percent to 45 percent by 2020 compared with 2005 levels (Huang and Wu, 2010). In 2010,
the Chinese government announced its Twelfth Five-year Plan, which required the development of
an emissions trading scheme (ETS) in China. In 2011, the National Development and Reform
Commission (NDRC) General Office published the "Notice on Carbon Emissions Trading Pilot," in
which Beijing Tianjin, Shanghai, Chongqing Guangdong Hubei and Shenzhen, in total, seven
provinces and cities were assigned as ETS pilots in China. As of early 2014, programs have been
initiated in six of these regions as shown in Table 7-6 (Environomist, 2014). These pilotprograms
are expected to serve as testing ground for a national ETS to be implemented after 2016 (Carbon
Market Watch, 2013).
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Table 7-6. China's Regional Pilot Emissions Trading Schemes
Guangdong
Hubei
Shanghai
Tianjin
Shenzhen
Beijing
Chongqing
2015 Emission
Reduction Target
(compared to
2010)
19.5%
17%
19%
15%
15%
18%
17%
Reporting
Obligations
Industrial
companies
emitting more than
10,000 tons of CO2
Companies
consuming more
than 8,000 tons of
standard coal per
year
Companies
emitting more than
10,000 tons of CO2
per year
Carbon-intensive
industries such as
iron and steel,
chemical, power,
heating,
petrochemical and
exploitation and
those of civil
buildings, which
emit more than
10,000 tons of CO2
annually
Companies
emitting more than
3,000 but less than
5,000 tons of CO2
annually, and other
enterprises and
buildings in
specific area
Companies
consuming more
than 2,000 tons of
standard coal per
year in the
provincial area
Pending
Compliance
Coverage
Companies
emitting more than
20,000 tons of CO2
in industries of
power, cement,
iron and steel,
ceramic,
petrochemical,
textile, non-ferrous
metals, plastics,
and paper
Industrial
companies
consuming more
than 60,000 tons of
standard coal
annually
Carbon-intensive
industries such as
iron and steel,
which emit more
than 20,000 tons of
CO2 annually; non-
industrial
enterprises which
emit more than
10,000 tons of C02
annually
Carbon-intensive
industries such as
iron and steel,
which emit more
than 20,000 tons of
CO2 annually
Enterprises and
institutional
organizations
which emit more
than 5,000 tons of
CO2 per year, large
public buildings
over 20,000 square
meters, office
buildings for
governmental
agencies over
10,000 square
meters
Companies
emitting more than
10,000 tons of CO2
annually, both
direct and indirect
Pending
Commenced
December 2013
December 2013
November 2013
December 2013
June 2013
November 2013
Pending
Source: Environomist (2014]
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7.3.1 Market and Infrastructure Factors
Coal provides 69 percent of the energy consumed annually in China, with only four percent
provided by natural gas. The NEA's Twelfth Five-year Natural Gas Development Plan called for the
natural gas percentage to reach about eight percent by year-end 2015, and it is commonly projected
that the percentage will exceed 10 percent by 2020 (EIA, 2014a; USEPA, 2012b).
Methane that occurs in coal has gradually evolved from a pure mine safety concern to a valued
commodity and a significant component of the natural gas resources that the government plans to
develop under its Twelfth Five-year Plan. The Twelfth Five-year Natural Gas Development Plan
explicitly includes CBM for the first time, targeting consumption to rise to 20 billion m3 by 2015, or
about eight percent of the total. The NEA's Twelfth Five-year Plan for CBM and CMM is even more
ambitious, calling for total production to rise to 30 billion m3 by 2015 - 16 billion for CBM and 14
billion for CMM. The utilization rate for pumped CMM is called to rise to 8.4 billion m3 from the
2010 level (NEA, 2011).
Of the 16 billion m3 of CBM captured through surface drilling, the NEA projects that 10 billion
should come from the Qinshui Basin, 5.4 billion from Ordos Basin, with the remaining 600 million
coming from smaller developments in 1) the Tiefa and Fuxin areas of Liaoning Province, 2) from
"experimental" programs in the Jiaozuo and Pingdingshan areas of Henan Province, 3) the Anshun
and Zhijin areas of Guizhou Province, and 4) other areas in Xinjiang, Anhui, Sichuan, and Gansu
Provinces, where drilling conditions are more challenging. Significantly, the plan also calls for the
construction of 13 pipelines with total length of more than 2,000 kilometers and 12 billion m3 per
year total transport capacity, signaling a significantly stepped-up effort to integrate CBM into the
largest natural gas economy. These efforts were already underway in the latter part of the 2000s,
with the construction by CNPC of a one billion cubic meter per year CBM processing facility in the
Qinshui basin with the intent to inject its own and third-party CBM into the nearby first West to
East pipeline.
The NEA's Twelfth Five-year Plan for Development of CBM/CMM calls for CMM to be used primarily
as a local fuel, with the number of residential users to approximately double to about 3.3 million
households between 2010 and 2015, and power generation capacity to quadruple to 2850 MW as
overall CMM utilization rises by about 5.5 billion m3. The Plan also calls for CMM power generation
capacity to quadruple to 2,850 MW between 2010 and 2015, and reiterates that, while the power
should be consumed by the mines themselves when possible, the policies regarding off-take by the
grid should be implemented. Given the limited ability of the mines to absorb all of the power, the
fulfillment of the Twelfth Five-year Plan targets will depend on more rigorous adherence by the
grid to the off-take policies (NEA, 2011).
The focus on local consumption of CMM poses challenges, as many of the coal mines recovering
CMM have exhausted the possibilities for burning the CMM to generate power for their own use, or
supplying CMM to customers in the immediate vicinity of the mines. Additionally, given the rapid
construction of electricity generation capacity in China since 2003, including many projects still
outstanding there is a distinct possibility that power generation capacity will outstrip demand in
many parts of the country through 2015-2017.
Only a few local governments such as Jincheng, a municipality of approximately two million people
in the Qinshui basin area, have mobilized to invest in region-wide CMM distribution infrastructure.
Jincheng has advantages that other localities do not necessarily share, including the ability to mix
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higher methane-content CBM with its CMM, and a supportive provincial government, which has
granted CMM producers an additional 0.3 yuan per cubic meter rebate for CMM sales for civil and
industrial use on top of the 0.2 yuan offered by the national government. Despite the booming
demand for natural gas, municipalities such as Chongqing have not found it cost-effective to
construct the medium-distance pipelines necessary to transport unprocessed CMM from large
producers such as Songzao into the city proper in view of the gathering pipeline investment, and
processing costs.
The government's Twelfth Five-year Plan for CBM and CMM addresses the barriers to the further
popularization of CMM in general terms, acknowledging the unfavorable economics of many CMM
utilization projects, the difficulties winning power grid company acceptance of the existing
regulations requiring them to accept CMM-generated power at premium prices, and the need for
stronger government incentives to promote CMM utilization. Follow-through on removal of these
barriers will be vital to enforcing the power dispatch and CMM pricing policies and achieve the
power generation targets.
As with CBM, the purification and liquefaction of CMM offers a potential solution to the market
barrier problems. Technologies to remove impurities of CMM at low temperature have been proven
outside of China, and are under development in China itself; no extra step is required to liquefy
once purification has taken place. While it would most likely not be economic to sell the product to
the petroleum pipeline companies given the domestic gas pipeline transmission pricing structure,
transportation by tanker truck would allow the CMM plants to sell directly to near or distant
distribution companies. In general, the economics of purified and liquefied CMM should be
attractive under conditions where overall supply continues to be tight, and imported gas is a
significant component of the overall natural gas sales base.
While many coal mining companies have considered the LNG option for utilization of their CMM,
most have hesitated to move ahead in view of the high up-front cost relative to other options such
as small distributed power plants, and the lack of reference CMM to LNG units in China. As of mid-
2012, only small demonstration facilities constructed by Chinese purification technology
developers were in operation.
The number of mines with degasification systems in China has more than tripled since 2006;
however, still relatively few of China's underground mines have installed degasification systems.
Even where degasification systems have been installed, they have encountered challenging geologic
conditions for which degasification technologies commonly used in China are often unsuitable
(Huang 2005; Huang, 2013a). Even where there are drainage systems in place, there are still a
number of challenges to effectively recovering and using the methane from mine drainage systems.
These barriers include small project size, fluctuating methane production, the high capital cost of
utilization projects, and limited infrastructure.
Currently, with China's underdeveloped natural gas market, many do not have access to natural gas,
limiting the potential market for CMM. Of the estimated 664 million people living in Chinese cities,
suburbs, and towns, only 145 million had access to natural gas atyear-end 2010. Entire provinces,
such as Guizhou, Yunnan, Guangxi, and Ningxia offered virtually no gas to their urban residents, and
even highly-developed provinces such as Guangdong and Jiangsu only offered gas to 12 and 22
percent of their respective city and town dwellers. As for CMM, most of the mines in China are
located in remote mountain areas, where the terrain makes it difficult to construct long-distance
pipelines to deliver drained CMM to cities. The first West-East Natural Gas Pipeline, between
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Xinjiang and Shanghai, began operating in October 2004, and has a capacity of 17 billion m3 of
natural gas, which is supplied to 10 provinces across China's Eastern and Western regions.
However, only a few coal mining areas are close enough to the pipeline to have the possibility of
accessing it for delivery of CMM. The second West-East Pipeline commenced operation and
connects Xinjiang to Guangdong with a capacity of 30 billion m3.
The price structure in China has historically favored use of CMM over natural gas, with the
consumer price of CMM for civil and industrial consumption set far lower than that of natural gas
(GMI, 2005). In April 2007, the Ministry of Finance provided a subsidy of 0.2 Yuan/m3 for CMM
utilization; the local finance departments are allowed discretion to increase their own subsidies
based on this standard (Huang 2007; Guizhou, 2008; Huang, 2012). The government also provides a
0.25 yuan/kilowatt-hour subsidy for CBM/CMM-fueled power generation, which is the same
subsidy offered for biomass power generation. Since 2007, the central government has awarded
subsidies of 1.8 billion yuan to support CBM/CMM development, which accounted for 9.2 billion m3
(Huang, 2012).
Large-scale development of shale gas could lower the cost structure of the national gas industry as
it has in the United States, also working against the interests of CMM producers. Given the time that
will be required to develop shale gas expertise, this is likely to be a long-term rather than a
medium-term issue.
Many organizations in China and abroad have financially sponsored the research and development
of CMM projects (GMI, 2005). They include the China Coalbed Methane Clearinghouse of CCII,
National Development and Reform Commission (NDRC), State Administration of Coal Mine Safety
(SAWS), U.S. Trade and Development Agency, World Bank, Asian Development Bank (ADB), Global
Environment Fund, Clean Development Mechanism, and Japan Development Fund.
A detailed discussion of China's market for CMM may be found in the United States Environmental
Protection Agency document China's Energy Markets: Anhui, Chongqing, Henan, Inner Mongolia, and
Guizhou Provinces, at http://epa.gov/cmop/docs/2012ChinaEnergyMarketpdf.
7.3.2 Regulatory Information
In China, recovery and utilization of CMM can only be exercised by coal enterprises with legal
mining licenses. CMM projects require approval from the NDRC at the county, provincial, and
central government level, depending on the size and type of project. CMM power generation
projects that are connected to the power grid must be approved by the investment administration
of the provincial government. CMM projects generating power used only by the mining company
must be recorded by the investment administration of the local government The investment
administration of provincial governments shall report both approved and recorded projects to the
investment administration of the State Council (NDRC, 2007).
A CBM or CMM pipeline project with the capacity to transport more than 500 million m3 a year or
crossing provincial boarders shall be approved by the investment administration of the State
Council. A CBM or CMM pipeline project with capacity to transport less than 500 million m3 a year
shall be approved by the investment administration of the provincial government (GOSC, 2006).
China has established a number of financial incentives to encourage CMM projects. Developers are
exempt from the prospecting and licensing fees on CBM development, and no royalties are levied on
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CBM through 2020. Value added tax (VAT) collected from coal mines recovering and utilizing
CBM/CMM is returned to the coal mining companies, and no income tax is paid by enterprises
developing technologies for CMM recovery and utilization. Coal mine owners or developers
investing capital in CMM projects through loans or self-equity financing can claim 40 percent of the
capital value to offset income taxes (Huang 2012; IEA, 2009).
These policies have the potential to encourage CMM project development; however, it is notable
that in order to obtain the aforementioned subsidies and tax exemptions, a developer must request
them at the appropriate level as well as follow up on a regular basis.
Additionally, China's Central Government provides 3 billion CNY for coal mine safety projects each
year, most of which is used for mine gas recovery projects. Coal mines can collect 15-20 CNY per
ton from coal sales to be applied to mine safety projects (Huang and Wu, 2010).
All exploration and mining activities must be approved by the Ministry of Land and Resources
(MLR) or with provincial land and resources bureaus (LRBs) to obtain exploration or mining rights.
Large coal mines in excess of 100 million metric tons of reserves must obtain licenses through the
MLR; however, smaller mines may obtain permission from provincial LRBs as a result of
government restructuring in the late 1970s. Oil and gas activity must be registered through the
MLR as the central government did not transfer management power to local levels as it did in the
coal industry. China's Mineral Resources Law was passed in 1986 and did not list CBM
independently as a mineral resource until it was amended in 1996, clarifying that CBM is one of
China's 34 mineral resources, amongst other issues.
The rights to exploration and development of CMM or CBM projects in China have been modified to
be more inclusive. Initially, the China United Coalbed Methane Corporation (CUCBM) had the
monopoly rights to CMM or CBM exploration, development, and production in cooperation with
foreign firms. If a commercial CBM field was found, CUCBM and the foreign party would jointly
establish an organization and conduct development and production. However, on September 24,
2007, the State Council modified the relevant regulations, "Regulations of the People's Republic of
China on Exploitation of On-shore Petroleum Resources in Cooperation with Foreign Countries," to
effectively eliminate the CUCBM monopoly. The law now includes the option for "other companies
designated by the State Council" to join with foreign businesses in exploiting CMM resources
(Huang 2007). Alternatively, if a CMM development project is to be realized by foreign grants or
free technical assistance (i.e., if the projects are non-profit and non-commercial in nature), it is not
necessary to involve CUCBM (CBMC, 2004).
Exploration and mining of CBM is registered in the same manner as conventional oil and gas, and
since 1998 three centrally-controlled state-owned enterprises (SOEs), CUCBM, CNPC, and China
Petroleum and Chemical Corporation registered for exploration rights of approximately 65,000 m2
of CBM blocks, comprising more than half of the total CBM blocks, while other SOEs such as China
Petro-Chemical Corporation (SinoPec) registered for smaller shares (Lin, 2011).
All CMM projects must conform to relevant environmental and safety regulations before operating.
Projects should focus on waste water drainage, atmospheric pollution, and noise pollution. Energy
use during the projects should be in accordance with the "Energy Conservation Law of the People's
Republic of China" and the energy-saving regulations and measures of the state and local
governments. The State Administration of Work Safety (SAWS) monitors worker safety in China.
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Laws and regulations such as the "Coal Mine Safety Regulation" should be followed when
developing CMM exploitation and utilization projects.
China's Ministry of Environmental Protection issued an Emission Standard of CBM/CMM in 2008
for new coal mines and drainage systems. The standard requires operators of CMM drainage
systems with greater than 30 percent methane concentration to use or flare the gas. As of 2012,
anecdotal evidence indicated this policy was creating a perverse incentive in some areas to
maintain gas concentrations below 30 percent by dilution, ignoring best practices and safety
standards (USEPA, 2012b).
For a detailed discussion of ownership and policy issues related to CBM and CMM in China and
worldwide, see the United States Environmental Protection Agency document Legal and Regulatory
Status of CMM Ownership in Key Countries: Considerations for Decision Makers, at
http://www.epa.gOv/cmop/docs/CMM-Ownership-Policy-White-Paper-Tuly2014.pdf.
7.4 Profiles of Individual Mines
Feasibility studies for CMM projects at a few Chinese mines, profiles of some individual mines in
China, and descriptions of CMM project opportunities are available on the following web sites:
¦ Global Methane Initiative (GMI): http: //www.globalmethane.org
¦ U.S. EPA: http: //epa.gov/cmop/international/china.html
¦ China Coal Information Institute (CCII): http: //www.nios.com.cn/cbmproiect.html
7.5 References
Carbon Market Watch (2013): China's Pilot Emissions Trading Systems (Newsletter #3), Carbon Market
Watch, 30 May 2013. http://carbonmarketwatch.org/chinas-pilot-emissions-trading-systems/
CCBMC (2004): Investment Guide for China CMM/CBM, China Coalbed Methane Clearinghouse, 2004.
http://epa.gov/cmop / docs / guildline3.doc
CCII (2010): Abandoned Mine Methane Project Advice Centre (AMMPAC), China Coal Information Institute,
Beijing, China, 22 May 2010. http://www.nios.com.en/c/index en/cleancoal/iimcat/3283.html
CCII (2011): Progress of China Coalbed Methane, presented at the GMI Coal Subcommittee Meeting, China
Coal Information Institute, 29 June 2011.
https://www.globalmethane.org/documents/events coal 20110620 china.pdf
China Coal Resource (2010): CNPC coalbed methane project in Shanxi sets production goals for 2020, China
Coal Resource, 28 April 2010. http://en.sxcoal.com/NewsDetail.aspx?catelD=174&id=30504
CNPC (2013): Unconventional Oil & Gas Resources, China National Petroleum Corp., 2013.
http://www.cnpc.com.cn/en/umconventional/common index.shtml
CQEIG (2009): Chongqing Energy cooperation with the Hong Kong and China Gas Company building the
world's largest gas liquefaction project, Chongqing Energy Investment Group, 4 December 2009.
http: //www.cqenergv.com/nyxw/6010.htm
Creedy et al. (2010): Reduction of Greenhouse Gas Emissions from Abandoned Coal Mines in China, D.P.
Creedy, K. Garner and P.W. Sage, prepared for the Foreign and Commonwealth Office Climate Change
Challenge Fund, 22 May 2010.
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EIA (2009): EIA Country Analysis Brief: China - Coal. U.S. Energy Information Administration, Washington,
DC, July 2009.
EIA (2014a): China Country Analysis Brief, U.S. Energy Information Administration, Washington, DC, updated
14 February 2014. http://www.eia.gov/countries/cab.cfm?fips=CH
EIA (2014b): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed April 2014. http: / /www.eia.gov/cfapps /ipdhproiect/IEDIndex3.cfm
Environomist (2014): China Carbon Market Research Report 2014, Environomist Ltd.
http://www.southpolecarhon.com/puhlic/140227 Environomist China-ETS ResearchReportpdf
GOSC (2006): On Accelerating CBM (CMM) Drainage and Utilization, Guo Fa Ban, No. 47, General Office of
State Council, 15 June 2006.
GMI (2005): Coal Mine Methane Subcommittee China Country Update, Global Methane Initiative, April 2005.
https://www.globalmethane.org/documents/events coal 20050427 china profile.pdf
GMI (2012): United States Country Update, presented at the 15th Coal Subcommittee Meeting, Global Methane
Initiative, 16 May 2012. https://www.glohalmethane.org/documents/events coal 120516 us.pdf
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed April
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
Guizhou (2008): CMM Recovery and Utilization Initiative, The Insider, Winter Issue, Guizhou Province, China,
January 2008. http://www.gzcmm.org/Newsletter/Winter 2007 English.pdf
Guoquan (2010): Information provided via personal communication with Guoquan Zhao, China Coal
Information Institute, July 2010.
Huang (2005): Potential of Developing Coal Mine Methane CDM Projects, Huang Shengchu, President, China
Coal Information Institute & National Institute for Occupational Safety, 21-23 October 2005.
http://cdm.ccchina.gov.cn/UpFile/File410.PDF
Huang (2007): Progress and Project Opportunities of the CMM Development and Utilization in China,
presented at the Methane to Markets Partnership Expo, Huang Shengchu, Beijing, China, 30 October -1
November 2007. https://www.glohalmethane.org/expo-docs/china07/postexpo/coal china.pdf
Huang (2008): Development and Utilization of Coal Mine Methane in China, presented at the 9th International
Symposium on CBM/CMM and Carbon Trading in China, Huang Shengchu, Beijing, China, 4 December
2008.
Huang (2010): Great Potential for CBM/CMM Recovery and Utilization and Preferential Policies, presented at
the Methane to Markets Partnership Expo, Huang Shengchu, New Delhi, India, 3 March 2010.
https://www.globalmethane.org/expo-docs/indialO/postexpo/coal shengchu.pdf
Huang (2012): Preferential Policy and International Action of CBM/CMM Development in China, presented at
the Coal Mine Methane Abatement Seminar, Huang Shengchu, China Coal Information Institute, Australia,
4-5 September 2012. https://www.globalmethane.org/documents/events coal 120904 qinggang.pdf
Huang (2013a): Perspectives and Challenges of CBM/CMM Industry in China, presented at the 13th
International Symposium on CBM/CMM and Shale Gas in China, Huang Shengchu, Beijing, China, 24-25
October 2013.
Huang (2013b): Current Situations of CBM/CMM Recovery and Utilization & methane emission reduction in
China, presented at the 2013 GMI Expo, Huang Shengchu, Vancouver, Canada, 12-15 March 2013.
https://www.glohalmethane.org/expo-docs/canadal3/coal 02 Huang UPDATED.pdf
Huang (2014): Coal Sector Updates in China, presented at the 20th Session of the GMI Coal Subcommittee,
Huang Shengchu, Geneva, Switzerland, 22 October 2014.
https://www.globalmethane.org/documents/Coal-Subcommittee-Qct-2014-China.pdf
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Huang and Wu (2010): Current Status and Policy from Works of Methane Emission Reduction in China,
presented at the Methane to Markets Partnership Expo, Huang Shengchu and Wu Jianmin, New Delhi,
India, 3 March 2010. https://www.globalmethane.org/expo-docs/indialO/postexpo/china huang.pdf
Huang and Liu (2012): Updates on China's Activities, presented at the GMI Coal Subcommittee Meeting
Webinar, Huang Shengchu and Liu Wenge, 16 May 2012.
https://www.glohalmethane.org/documents/events coal 120516 china.pdf
IEA (2009): Coal Mine Methane in China: A Budding Asset with the Potential to Bloom, International Energy
Agency, Paris, France, February 2009.
http://www.iea.org/puhlications/freepuhlications/puhlication/china cmm reportpdf
Lin (2011): China's Evolving Energy Governance: A Case Study of Mining Rights Disputes, Energy Governance
Case Study #14, Lin Yanmei, Centre on Asia and Globalization, Lee Kuan Yew School of Public Policy,
National University of Singapore, December 2011.
Liu (2007): Case Study on CMM/CBM projects in China, presented at CMM Development in the Asia-Pacific
Region: Perspectives and Potential, Liu Wenge, China Coal Information Institute, Brisbane, Australia, 4-5
October 2006.
Mattus (2012): MEGTEC VAM Processing, presented at the GMI Coal Subcommittee Meeting, Richard Mattus,
Sydney, Australia, 5 September 2012.
https://www.globalmethane.org/documents/events coal 120904 mattus.pdf
Merrill (2007): CBM - Another green solution (Industry Overview), David Yip and Joseph Jacobelli, Merrill
Lynch, 18 June 2007. http: II www.ml. com / media /79662 .pdf
NEA (2011): Development and Utilization of CMB and CMM During the Twelfth Five -Year Plan (Chinese),
National Energy Administration, December 2011. http: //www.nea.gov.cn/131337364 31n.pdf
NEA (2014): Notice on the coal industry in 2014 working for the elimination of backward production capacity
(Chinese), No. 135, National Energy Administration, 27 March 2014.
http://zfxxgk.nea.gov.cn/auto85/201404/t20140404 1784.htm
NDRC (2007): A Notice on Using CBM (CMM) for Power Generation, No.721, Fagai Nengyuan, National
Development and Reform Commission, 2 April 2007.
Sun (2014): Information provided by Sun Biao, Shanxi Jincheng Anthracite Mining Group Co., Ltd., April 2014.
UNEP (2014): CDM Pipeline Spreadsheet, United Nations Environment Programme, Risoe Centre, 1 April
2014. http://cdmpipeline.org/
UNFCCC (2008): Coalmine Methane Utilization Project PDD, Version 2.5, Zhengzhou Coal Industry (Group)
Co., Ltd., United Nations Framework Convention on Climate Change, completed 8 August 2008.
http://cdm.unfccc.int/UserManagement/FileStorage/7G3RM20P7D5LIVYKC8XB06WHlNI094
UNFCCC (2014): Ratification Status - China, United Nations Framework Convention on Climate Change,
accessed September 2014. http: //maindh.unfccc.int/puhlic/country.pl?country=CN
USEPA (1996): Reducing Methane Emissions from Coal Mines in China: The Potential for Coalbed Methane
Development, U.S. Environmental Protection Agency, Coalbed Methane Outreach Program, 1996.
http://www.epa.gov/cmop/docs/intOQ4.pdf
USEPA (2006): Power Plant to be Largest Run on Coal Mine Methane, Coalbed Methane Notes, U.S.
Environmental Protection Agency, Coalbed Methane Outreach Program, 18 May 2006.
http://yosemite.epa.gOv/opa/admpress.nsf/4d84d5d9a719de8c85257018005467c2/8ec89e33e48a863
fB52571720063e8d7!QpenDocument
USEPA (2012a): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
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USEPA (2012b): China's Energy Markets: Anhui, Chongqing, Henan, Inner Mongolia, and Guizhou Provinces,
U.S. Environmental Protection Agency, December 2012.
http://epa.gov/cmop/docs/2012ChinaEnergyMarket.pdf
Zhang et al. (2004): Potential for Development of CMM Projects in China, Zhang Binchuan, Huang Shengchu,
Hu Yuhong, Liu Wenge, and LiuXin, China Coal Information Institute, 2004.
http://cdm.ccchina.gov.cn/english/UpFile/File6.D0C
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8 Colombia
8.1 Summary of Coal Industry
8.1.1 Role of Coal in Colombia
Coal accounted for eight percent of Colombia's energy consumption in 2007 and one-fourth of total
exports in terms of revenue in 2009 (EIA, 2010a). As the world's tenth largest producer and fourth
largest exporter of coal (World Coal, 2012; Reuters, 2014), Colombia provides 6.9 percent of the
world's coal exports (EIA, 2010b). It exports 97 percent of its domestically produced coal, primarily
to the United States, the European Union, and Latin America (EIA, 2010a).
Colombia had 6,746 million tonnes (Mmt) of proven recoverable coal reserves in 2013, consisting
mainly of high-quality bituminous coal and a small amount of metallurgical coal (Table 8-1). The
country has the second largest coal reserves in South America, behind Brazil, with most of those
reserves concentrated in the Guajira peninsula in the north (on the country's Caribbean coast) and
the Andean foothills (EIA, 2010a). Its reserves of high-quality bituminous coal are the largest in
Latin America (BP, 2014).
Table 8-1. Colombia's Coal Reserves and Production - 2013
Anthracite &
Sub-bituminous &
Total
Global
Indicator
Bituminous
Lignite
(million
Rank
(million tonnes)
(million tonnes)
tonnes)
(# and %)
Estimated Proved Coal
Reserves (2013]
6,746.0
0.0
67469.0
11 (0.8%]
Annual Coal Production
(2013]
85.5
0.0
85.5
10 (1.4%)
Source: BP (2014]
Coal production for export occurs mainly in the northern states of Guajira (Cerrejon deposit), Cesar,
and Cordoba. There are widespread small and medium-size coal producers in Norte de Santander
(metallurgical coal), Cordoba, Santander, Antioquia, Cundinamarca, Boyaca, Valle del Cauca, Cauca,
Borde Llanero, and Llanura Amazonica (MB, 2005). Figures 8-1 and 8-2 illustrate the locations of
coal deposits and mines in Colombia.
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Figure 8-1. Map of Colombian Minerals
Source: ANDI (2010)
Figure 8-2. Map of Colombian Coal Mines
CARIBBEAN SEA
Fluvial Port
Sea Port
4- International Airport
Fluvial way
-H-* Railway
Road
Cartagena
Santa
Drummond
(El Descanso Project)
Gal way Guajira
8.200 Acres
Galway Cesar
6.980 Acres
Coalcorp
(La Francia I & II Open Pits)
Drummond
(El Boqueron Open Pit)
-Lj.
Gal way's Galea Area
333.500 Acres
Puerto
Bolivar
Cerrejon and Caypa
Open Pits
(4.5 Billion T)
Source: Galway (2007a)
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8.1.2 Stakeholders
Table 8-2 lists potential stakeholders in Colombia's coal mine methane (CMM) industry.
Table 8-2. Key Stakeholders in Colombia's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
Equipment Manufacturers
Developers
Engineering, Consultancy,
and Related Services
Natural Gas Transmission
& Distribution Companies;
Power Companies
Natural Gas Production
and Transport
Government Groups
Prodeco (owned by Xstrata]
Carbones de La Jagua (owned by Glencore]
Cerrejon Coal Company (joint venture of Anglo-American,
BHP, and Xstrata]
Anglo American (AA]
BHP Billiton (BHB)
Glencore Xstrata
Vale SA
Carbones del Cerrejon LLC
C.I. Prodeco S.A.
CCX
MPX
Carbones de La Jagua S.A.
SATOR
Minas PazdelRio
CoalCorp
CERX
Drummond Ltd.
Acerias Paz del Rio, S.A.
New Age Exploration (NAE]
Wood Group Power Solutions, Inc. (part of the Gas
Turbine Services Division of John Wood Group PLC
GE Transportation Systems - Electric drive systems
(loaders and haulage]
Goulds Pumps - Slurry and process pumps (pumps,
compressors, valves and actuators]
Grindex - Submersible drainage, sludge and slurry pumps
(pumps, compressors, valves and actuators]
Hansen Transmissions - Gear units and power
transmission products (power supply, engines,
transmission and drives]
Voith Turbo GmbH & Co. KG - Start-up components
(power supply, engines, transmission and drives]
See http: //www.epa.gov/coalbed/networkcontacts.html
See http: //www.epa.gov/coalbed/networkcontacts.html
Project hosts
Methane treatment and
utilization equipment
Andina Electrica
Chevron
Ecopetrol
Ministry of Mines and Energy
Project opportunity
identification and
planning
Technical assistance
Pipeline sales for power
generation
Regulation and
policymaking
Sources: MT (2007]; World Coal (2012]; BP (2014]
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8.1.3 Status of Coal and the Coal Mining Industry
Colombia produced 85.5 Mmt of coal in 2013, while only consuming 4.9 Mmt Colombian coal
production is exclusively carried out by private companies and has increased about 78 percent in
the past decade (Mining, 2014). Colombia's mining minister Carlos Rodado said coal output will
reach 100 Mmt by 2015 and 144 Mmt in 2020 (Sourcewatch, 2012a).
Tables 8-3 and 8-4 list available specifics on Colombia's coal mining companies as of 2010.
The largest coal producer in Colombia is the Carbones del Cerrejon consortium, composed of Anglo-
American, BHP Billiton, andXstrata. The consortium operates the Cerrejon Zona Norte (CZN)
project, the largest coal mine in Latin America and among the largest open-pit coal mines in the
world. CZN is an integrated system of mine, railroad, and a Caribbean coast export terminal (EIA,
2014).
The open pit mine produces 33 Mmt per year (2013) and plans to increase production up to 50
Mmt per year are being considered, owing to the $1 billion investment by Carbones del Cerrejon
(MT, 2007). The country's second largest coal mine, La Loma, is a mine-railway-port project
operated by Drummond, which produced 25 Mmt in 2011 (Drummond, 2014). In 2008, Colombia
gave Drummond permission to open the El Descanso Mine, which is expected to produce up to 25
Mmt by 2015 (Sourcewatch, 2012b).
Also in 2008, Galway began exploration drilling in the Carboluis project in San Luis Coal basin
located in Santander—an area with some 300 Mmtofcoal (Galway, 2007b) — butthe company has
put that project on hold while it looks for equity partners (Union, 2010).
Colombia's coal is relatively clean-burning, with a sulfur content of less than one percent.
Table 8-3. Major Colombian Coal Producing Companies\Regions
Mine
Production in 2010
(million tonnes)
Cerrejon Coal Company (2013]
33
Drummond (2013]
25
Prodeco
10.2
Otros
3.8
Boyaca
2.7
Cundinamarca
2.1
Norte de Santander
2.2
Source: ANH (2014]
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Table 8-4. Major Colombian Coal Mines
Mine
Type
Location
Owner
Production
(million
tonnes per
year)
Mineable
Reserves
(million
tonnes)
Cerrejon Zona
Norte
surface
La Guajira
Cerrejon Coal Company
28.4 (2010]
1,600
Carbones del
Cerrejon
surface
La Guajira
Cerrejon Coal Company
3.7 (2010]
-
EI Cerrejon
Corte
surface
La Guajira
Cerrejon Coal Company
5.6 (2010]
-
Mina Pribbenow
/La Loma
surface
Cesar
Drummond
18.1 (2010]
485
El Descanso
surface
Cesar
Drummond
3 (2010]
960
El Hatillo
surface
Cesar
Vale S.A.
1.8 (2008]
500
Calenturitas
surface
Cesar
Glencore/Prodeco
5.2 (2010]]
La Jagua
surface
Cesar
Glencore/Prodeco
8.5 (2003]
4.4 (2009]
260
La Jagua
underground
Cesar
Glencore/Prodeco
0.9 (1994]
-
GALCA
exploratory
Cesar
Galway/Prodeco
exploratory
60-200
La Francia
surface
Cesar
Goldman Sachs (from
CoalCorp Mining]
1.5
Caypa
surface
Cesar
Carbones Colombianos del
Cerrejon/CoalCorp Mining
0.175 (2007]
8.8
Rio de Oro
Norte de
Santander
Geominas
60-320
Paz del Rio
Boyaca
Acerias Paz del Rio S.A.
2.6 (2010]
Puerto
Libertador
surface
Cordoba
SATOR-
0.1 (2010]
-
Sources: Jahnig (2007]; USGS (2008]; ANDI (2010]; Mining Weekly (2008]; Mining Weekly (2010]; MB (2005]; ANH
(2014]
8.2 Overview of CMM Emissions and Development
Potential
8.2.1 CMM Emissions from Operating Mines
A pilot project to measure methane emissions is underway at the La Loma/Pribbenow Mine,
operated by U.S.-based Drummond Company Inc., one of the largest coal producers in Colombia,
and located near La Loma in Cesar Department; the mine has estimated reserves in excess of
534 Mmt of high-Btu, low-ash and low-sulfur coal. There have been no published results although
the project was confirmed by a general engineer at Drummond Inc., USA. Drummond estimates that
there are 62.2 billion cubic meters (2.2 trillion cubic feet) of coal bed methane (CBM) in its mines
and it has signed a contract with Ecopetrol to extract CBM from the La Loma and El Descanso mines
(EIA, 2014).
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Table 8-5 provides Colombia's total CMM emissions.
Table 8-5. Colombia's CMM Emissions (million cubic meters)
Emission Category
2000
2005
2010
2015
(projected)
Total CH4 Emitted
(= Total liberated -
231.1
357.1
511.2
651.3
recovered & used]
Source: USEPA (2012]
The current potential for CMM projects in Colombia is limited to pre-mine drainage as most coal is
surface mined; however, as mines target deeper seams, there should be significant potential for
CMM projects.
8.2.2 CMM Emissions from Abandoned Coal Mines
No data on CMM from abandoned mines are available for Colombia at this time.
8.2.3 CBM from Virgin Coal Seams
Colombia has included CBM in its tender for oil and gas exploration and production contracts
beginning in 2014. Drummond and Cerrejon have both announced thatthey will develop a CBM gas
project in Colombia's La Guajira department. The project will be developed in Cerrejon's mining
area where Drummond holds the right to produce methane gas. The companies are expected to
soon reach an agreement (SeeNews, 2014).
8.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Colombia signed and ratified the UNFCCC and Kyoto Protocol, as indicated in Table 8-6. As a Non-
Annex I Party to the Kyoto Protocol, Colombia has no national emissions targets and is eligible to
host mitigation projects under the Clean Development Mechanism. Therefore, Colombia is eligible
to secure project revenues from the sale of greenhouse gas (GHG) emission reduction credits.
Table 8-6. Colombia's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC*
June 13,1992
March 22,1995
Kyoto Protocol**
—
November 30,2001
Source: UNFCCC (2014]
In 2012, the Colombian government launched the Colombian Low Carbon Development Strategy
(CLCDS). While recognizing that Colombia's carbon emissions are low relative to developed
countries, without mitigation actions they could increase significantly based on the country's
projected economic growth. The strategy states that Colombia should consider international
financial incentives to promote sustainable growth and prepare the economy for a "future carbon-
<
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conscious global economy." The CLCDS is a medium and long-term development program led by
the Ministry of Environment and Sustainable Development (MADS), the Department of National
Planning (DNP), and the Industry Energy, Mining, Transport, Housing Waste, and Agriculture
ministries of Colombia. The goal of CLCDS is to strengthen Colombia's economic and social
development while concurrently meeting global requirements of efficiency, competitiveness and
environmental performance.
The strategy of CLCDS is to:
¦ Identify and assess different actions that would reduce greenhouse gas emissions and
support sectoral growth,
¦ Develop Mitigation Action Plans for each Colombian productive sector, and
¦ Create and promote tools for their implementation.
In 2014, Fundacion Natura, a Colombian environmental charity, announced that it would launch a
carbon trading platform in 2015 to individuals and companies seeking to offset carbon emissions.
The platform is being developed by the Bolsa Mercantil de Colombia (BMC), a commodities
exchange used by physical producers and consumers of farm produce (FNC, 2014).
8.3.1 Market and Infrastructure Factors
The International Finance Corporation (IFC) has financed a project to increase production of coal in
Colombia and to help privatize the coal sector. Several large international corporations are involved
in coal mining in Colombia such as the Drummond Company, Anglo American, BHP Billiton, and
Glencore (MB, 2005).
Colombia has an open, emerging market economy, and it is known that the Colombian mining
authorities are supportive of CMM development initiatives. The most significant challenge to
CMM/CBM production in Colombia is the ability for this unconventional gas to compete with
conventional natural gas that is produced in offshore fields. Conventional natural gas is transported
to Bogota and other cities via a pipeline and sold for about $0.50/Mmcf (million cubic feet);
whereas CBM/CMM will require a wellhead price of around $1.50/Mmcf to become marginally
profitable. Voluntary carbon trading schemes, such as the one initiated by Fundacion Natura
Colombia, could encourage investment in the CMM/CBM industry.
8.3.2 Regulatory Information
The key governmental body involved in the energy sector in Colombia is the Ministry of Mines and
Energy, which is responsible for formulating and adopting policies directed towards the sustainable
use of the country's mining and energy resources in order to contribute to the country's economic
and social development. This is done by establishing policies that regulate:
¦ The exploration and extraction of hydrocarbons,
¦ The exploration, extraction and export of minerals,
¦ The production, expansion, distribution and supply of energy services, and
¦ The distribution and consumption of fuel gas.
On 25 March 2014, the Ministry of Mines and Energy adopted Resolution 90325, which allows
mining companies to utilize the methane gas released during mining operations to provide energy
A
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for the mine. A draft of the implementation plan was scheduled for release at the end of November
2014.
8.4 Profiles of Individual Mines
No profiles are available for Colombia at this time.
8.5 References
ANH (2014): Ministry of Mines and Energy, National Mining Agency, 2014.
http://www.simco.gov.co/english/Home/Statistics/Production/tabid/395/language/en-
US/Default.aspx
ANDI (2010): Colombia Mining Outlook, Asociacion Nacional De Empresarios De Colombia, April 2010.
BP (2014): BP Statistical Review of World Energy, BP, June 2014.
Drummond (2014): Coal Operations - Colombia, Drummond Company Inc., 2014.
http://www.drummondco.com/operations/coal/Colombia.aspx
EIA (2010a): Country Analysis Briefs - Colombia, U.S. Energy Information Administration, Washington, DC,
March 2010.
EIA (2010b): International Energy Statistics - Total Coal Exports, U.S. Energy Information Administration,
Washington, DC, accessed June 2010.
http://tonto.eia.doe.gov/cfapps/ipdbproiect/IEDIndex3.cfm?tid=l&pid=l&aid=4
EIA (2014): Country Analysis Briefs - Colombia, U.S. Energy Information Administration, Washington, DC,
January 2014. http: //www.eia.gov/countries/analysisbriefs/Colombia/colombia.pdf
FNC (2014): Fundacion Natura Colombia, 2014. http://www.natura.org.co/carbonocero/banco-
carbonocero.html
Galway (2007a): Galway Resources Announces A New Colombian Exploration Initiative, Galway Resources,
18 December 2007.
Galway (2007b): Carboluis, Galway Resources, 2007.
Jahnig (2007): Coal Deposits of Colombia, Freiberg University of Mining and Technology, Andrea Jahnig, 2007.
http://www.geo.tu-freiberg.de/oberseminar/os07 08/andrea i%E4hnig.pdf
MB (2005): Coal Mining in Colombia, MBendi Information Services, January 2005.
http: //www.mbendi.com/indy/ ming/coal/sa/cb/p0005.htm
Mining (2014): Colombia's coal output down 4% in 2013 due to strikes, rebel attacks, 10 February 2014.
http://www.mining.com/colombias-coal-output-down-4-in-2013-due-to-strikes-rebel-attacks-89082/
Mining Weekly (2008): Vale Buys Colombia Coal Assets, MiningWeekly.com, 24 December 2008.
http://www.miningweekly.com/article/vale-buys-colombia-coal-assets-20Q8-12-24
Mining Weekly (2010): Glencore to Buy Back Colombia Coal Mine from Xstrata, MiningWeekly.com, 5 March
2010. http://www.miningweekly.com/article/glencore-to-buy-back-colombia-coal-mine-from-xstrata-
2010-03-05
MT (2007): El Cerrejon Norte Coal Mine, Colombia, Mining Technology, website accessed July 1,2010.
http://www.mining-technologv.com/proiects/cerreion
Reuters (2014): Colombia's 2013 Coal Output Slips 4 Percent in Rough 2013, 7 February 2014.
http://www.reuters.com/article/2014/02/08/coal-colombia-production-idUSL2N0LC234201402Q8
A
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SeeNews (2014): Drummond, Cerrejon to produce coalbed methane in Colombia, 21 February 2014.
http://energy.seenews.com/news/drummond-cerreion-to-produce-coalbed-methane-in-colombia-
report-406137
Sourcewatch (2012a): Colombia and Coal, 14 December 2012.
http://www.sourcewatch.org/index.php/Colombia and coal
Sourcewatch (2012b): El Descanso mine, 8 September 2012.
http://www.sourcewatch.org/index.php/El Descanso mine
UNFCCC (2014): Ratification Status - Colombia, United Nations Framework Convention on Climate Change,
accessed September 2 014. http: //maindb.unfccc.int/public/country.pl?country=CO
Union (2010): Colombia - Renewing the Search for Eldorado, Union Securities, 30 April 2010.
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/Downloads/EPAactivities/Appendices Global NonC02 Projections
Dec2012.pdf
USGS (2008): Minerals Yearbook - Colombia, U.S. Geological Survey, 2008.
http: //minerals.usgs.gov/minerals / pubs / country/ sa.html#co
World Coal (2012): Coal Still Reigns, International Mining, pp 21-58, World Coal Association, August 2012.
CMM Country Profiles 89
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9 Czech Republic
9.1 Summary of Coal Industry
9.1.1 Role of Coal in the Czech Republic
The Czech Republic domestically provided for 1.06 Quadrillion Btu of its total energy consumption
of 1.572 Quadrillion Btu in 2012 (EIA, 2014). Coal comprises 40.8 percent of the country's
indigenous energy supplies (IEA, 2013). The Czech Republic ranks 27th globally in coal production,
producing 54.97 million tonnes (Mmt) of coal in 2012. Its total recoverable coal reserves are
estimated at approximately 1.05 billion tonnes (see Table 9-1).
Table 9-1. The Czech Republic's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
181
871
1,052
27 (0.118%]
Annual Coal Production (2012]
11.44
43.53
54.97
16 (0.70%]
Source: EIA (2014]
Hard coal occurs mainly in the eastern Silesian region, with the Ostrava-Karvina coalfields (known
as "OKR") in the Upper Silesian Coal Basin being the most important black coal field in the country.
Brown coal (lignite) is found mostly in the Northern Bohemian Brown Coal Basin (Euracoal, 2014).
Other coal basins include the Lower Silesian coal basin (Zacler coal field) and the East Bohemian
Coal Field (Kladno district) (Schwochow, 1997). The Republic is an exporter of coking coal to
Slovakia, Austria, Hungaiy, and Poland mainly for steel production (IEA, 2010). See Figure 9-1 for
locations of coal deposits.
A
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Figure 9-1. Coal Basins of the Czech Republic
o Leipzig
GERMANY
LubinL
, Wroclaw Breslau
WEST
BOHEMIAN
COAL FIELD
KIadjto4p
^ P"ha'
Vrchlab:
EAST*
BOHEMIAN
COAL FIELD
LOWER SILESIAN
\COAL BASIN
POLAND h
H Hardcoal field, deposit
t\ I Probable hardcoal area
50 100 Miles
30 100 km
?Plzen
Ceske
CZECH
REPUBLIC
m Ceske
§ Trebore
O Krakow
-yUPPER SILESIAN
. BASIN
Area ol
OBrno Fig. 55
Ostravfr-rnUPPER SILE
*e [M COAL BA!
J ore
Area of . .. •
SLOVAKIA Kosic
Trna /
/ UKR
'Munchcn
Vienna © ^ Bratislava
AUSTRIA
HUNGARY
¦ Rnrlfmrsr
9.1.2
Source: (Schwochow, 1997)
Stakeholders
Table 9-2 lists potential coal mine methane (CMM) development stakeholders in the Czech
Republic.
Table 9-2. Key Stakeholders in the Czech Republic's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies
¦ Ostravsko-Karvinske Doly (OKD)
¦ Severoceske Doly a.s.(SD)
¦ Severni Energeticka (formerly Litvinovska uhelna
a.s.[LUAS|)
« Vrsanska uhelna, a.s. (VUAS)
« Sokolovska Uhelna a.s. (SU)
Project hosts
Energy Companies
¦ Green Gas DPB
CMM project
¦ Energie - stavebni a banska a.s.
identification and
¦ Unigeo a.s.
investment
¦ CEZ Group
¦ Czech Power Company
Engineering, Consultancy,
¦ RWE Energo
Technical assistance
and Related Services
¦ See also
http://www.epa.20v/coalbed/networkcontacts.html
Developers
¦ Essar Global
Project opportunity
¦ See also
identification and
http://www.epa.20v/coalbed/networkcontacts.html
planning
Natural Gas Transmission
¦ RWE GasNet (distribution)
Gas storage and trade
& Distribution Companies
¦ RWE TransGas (transmission)
Gas transmission
¦ Moravske Naftove Doly
Gas production and
storage
Regulatory Agencies and
« Ministry of the Environment
Regulation, licensing.
Government Groups
« Ministry for Regional Development
« Ministry of Industry and Trade
« Energy Regulatory Office
permitting
Sources: IEA (2010); Euracoal (2014)
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9.1.3 Status of Coal and the Coal Mining Industry
The coal industry is important to the Czech Republic's economy and coal will likely remain a key
critical energy source through 2030 (Green Gas DPB, 2012). Table 9-3 characterizes the Czech
Republic's coal mining industry as of 2008, stating production tonnage for each mine type.
Table 9-3. The Czech Republic's Coal Mines and Coal Production (2008)
Production
Type of Mine
(million tonnes)
Number of Mines
Underground (active] mines - total
13.4
6
Surface (active] mines - total
47.0
6
Source: IEA (2010]
The country extracts all bituminous coal through underground mining using the longwall method,
primarily in the Upper Silesian Basin (USGS, 1994), specifically OKR (see Figure 9-1 on previous
page). Lignite comprises less than 1 percent of the total coal produced, most of which (90 percent)
is extracted through surface mining.
The Czech Republic's accession to the European Union has driven several structural reforms for the
country's energy industry, beginning in 1999. As of 2013, the hard coal and brown coal sectors have
been completely privatized, comprising five companies (Euracoal, 2014). Ostravsko-Karvinske Doly
(OKD) is the last remaining hard coal mining company, which operates 4 underground mines—
Karvina, CSM, Darkov, and Paskov—producing 12.8 Mmt annually (IEA, 2010).
The remaining companies mine lignite (IEA, 2010 [unless noted]):
¦ Czech Coal Group—comprised of Severn! Energeticka (formerly Litvinovska uhelna, a.s.
[LUAS]) and Vrsanska uhelna, a.s. (VUAS)—operates 2 opencast or surface mines that
produced 15 Mmt in 2008.
¦ Severoceske Doly (SD) operates 2 opencast or surface mines—Doly Nastup Tusimice and
Doly Bilina producing 22.8 Mmt of brown coal in 2012, increasing SD's share of brown coal
production to nearly 50 percent (Euracoal, 2014).
¦ Sokolovska Uhelna (SU) operates 2 opencast or surface mines, the Druzba and Jin mines. In
2012, its outputwas 6.7 Mmt (Euracoal, 2014).
Despite a healthy coal mining industry, the country reduced its coal consumption by more than a
third from 1993 to 2012 (EIA, 2014).
9.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database identifies one CMM
project in place at an active underground mine in the Upper Silesian Basin. The methane is injected
into a gas pipeline for delivery, using 77 million m3 of CMM and 32 million m3 of abandoned mine
methane—avoiding a total of approximately 1.56 million metric tons of carbon dioxide equivalent
(MMTC02E) of emissions (GMI, 2014).
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9.2.1 CMM Emissions from Operating Mines
Methane emissions in the Czech Republic totaled 351.5 million cubic meters (m3) in 2000, are
expected to decrease to 294.1 million m3 by 2015, and then anticipated to further decrease to 282.2
million m3 by 2030 (see Table 9-4).
Table 9-4. The Czech Republic's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
351.5
325.6
306.7
294.1
Source: USEPA(2012)
Green Gas DPB has been a major player in CMM development in the Czech Republic since thel990s.
The company operates mining leases for gas extraction at all closed mine locations in the OKR
mining district The company also purchases superfluous volumes of mine gas from active mines
that are incapable of utilizing for their own needs. As the holder of appropriate licenses, Green Gas
DPB is also engaged in survey, extraction, distribution and the sale of mine gas (Green Gas DPB,
2014a).
Recognizing the importance and value of CMM, starting in 2004, Green Gas DPB expanded its CMM
utilization projects and began installing combined heat and power (CHP) units at active and
abandoned mines. The pilot project used gas from closed strata in the Vrbice coalmine and from the
Paskov operational coalmine in the Chlebovice region of the Czech Republic and a total of 28
TEDOM CHP units were in operation by 2008, producing 320 terrawatt hours annually (PowerGen,
2009). For example, in 2008, Green Gas DPB installed two CHP units at the Lazy mine where gas-
powered engines use mine gas drained from the gas drainage station, which helps ensure the coal
miners' safety. Additional projects include CSA mine, with the first CHP unit installed in 2009 and a
second in 2011. Electricity from many of the CHP projects is delivered into local distribution
networks and heat is delivered into boiler rooms for mine heating purposes (Green Gas DPB,
2014b).
Other vested companies include a British company, Marine & Mercantile Securities, and Energie -
stavebni a banska a.s., entered into a joint venture as Eurogas a.s., to explore existing wells and drill
new ones in OKR coalfields between Ostrava's abandoned mines and the Polish border centered
around Cesky Tesin and in the south below Frydlandt Eurogas a.s. is currently researching
alternative energy sources, including CMM and coal bed methane (CBM) with the experts from the
VSB - Technical University of Ostrava, Institute of Geonics AV CR, and others in academia (Energie -
stavebni a banska a.s., 2014).
9.2.2 CMM Emissions from Abandoned Coal Mines
Green Gas DPB utilizes abandoned mine methane from four production areas in the OKR region
with 10 abandoned shafts and 4 wells producing 25 million m3 of methane annually (Green Gas
DPB, 2007).
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9.2.3 CBM from Virgin Coal Seams
The Czech lignite mines offer no potential for production of CBM from virgin seams or CMM from
existing mines (BERR/DTI, 2004).
In 2004, a British study of CBM potential in the Czech Republic reported on the gas in virgin coal
seams in OKR coalfields between 1991 and 1998. Twenty surface boreholes were drilled and
hydrofracturing was carried out to stimulate gas flow. The survey concluded that the commercial
potential for CBM was not viable and further development plans were tabled (BERR/DTI, 2004).
The Czech Ministry for Regional Development and TransGas funded coal seam gas explorations
conducted by four companies—Green Gas DPB, Energie stavebni a banska a.s. (via Eurogas, a.s.),
GPO, and Unigeo Ostrava -that ultimately received licenses for gas exploration in the OKR
coalfields. Figure 9-2 shows the regions of these gas recovery projects (Schwochow, 1997).
Figure 9-2. Mining Areas & Coal Seam Gas Concessions in the OKR Coalfield
9.3 Opportunities and Challenges to Greater CMM Recovery
and Use
The Czech Republic, under the Kyoto Protocol, is committed to an emissions reduction of 8 percent
below 1990 levels (UNFCCC, 2006). Its environmental policies are in accord with those stated in
Methane iniSe CMM Country Profiles 94
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CZECH REPUBLIC
"An Environment for Europe," by the United Nation's Economic Commission for Europe, which
limits mining activities that are hazardous to human health and environment and promotes
efficient use of non-renewable natural resources. The Czech Republic is an Annex I party to the
UNFCCC (see Table 9-5). Many registered Joint Implementation projects have been submitted to the
Czech Ministry of Environment, but none involve CMM and the Republic has not implemented any
Clean Development Mechanism projects (UNEP, 2014).
Table 9-5. The Czech Republic's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 18,1993
October 7,1993
Kyoto Protocol
November 23,1998
November 15,2001
Source: UNFCCC (2014]
The Ministry of the Environment is responsible for the implementation of UNFCCC and relevant EU
legislation in the Czech Republic. The "National Programme to Abate the Climate Change Impacts in
the Czech Republic" (the National Programme) presents the country's climate protection strategy
and contains GHG emission reduction goals as well as mitigation and adaptation measures. The
National Programme was developed in accordance with EU requirements and was first approved
by the Czech government in March 2004. Based on new scientific information and climate
negotiations (within the EU and atUNFCCC/Kyoto Protocol Conferences of Parties), the National
Programme was reviewed in 2007, and the Czech Government approved preparation of a new
Climate Protection policy in April 2008. A similar task regarding the preparation of an Adaptation
Strategy was adopted by the Czech Government in November 2009.
The Ministry of the Environment, together with other relevant ministries, is currently revising
these strategic documents to include mitigation measures within the climate protection policy, and
an adaptation strategy will include estimates of negative impacts, adaptation measures, legal and
economic analyses.
9.3.1 Market and Infrastructure Factors
The Czech Republic faces a number of barriers to achieving greater CMM recovery. First, the
continuing trend of declining coal production (i.e., down approximately 30 percent since 1993) in
the Republic is detrimental to the growth of CMM development Second, unusual topography in the
coalfields hinders CBM recovery projects. Still, because of its large coal deposits, the Czech Republic
ranks high globally in its potential for CMM development.
The Czech Republic's electricity price structure favors generation from mine gas fired power plants.
The Republic's legislation provides for a "green bonus" for AMM and a "surcharge" for use of CMM
in electricity generation (Green Gas DPB, 2007).
New technologies for CMM recovery are available and being implemented, but not broadly. No
significant R&D projects were found in place to enhance the current CMM recovery technologies.
Green Gas DPB works with OKD to sell methane from active mines in the OKR district through long-
term agreements, and the company is the only entity awarded a state license for exploration and
extraction of methane from closed mines (Green Gas DPB, 2012). Over a 5-year timeframe, Green
Gas DPB mitigated 5.7 Mmt of carbon dioxide equivalent from the mines in which it operates.
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9.3.2 Regulatory Information
The Czech coal industry is no longer subsidized. Companies that are no longer operating active coal
mines receive subsidies only to pay for rehabilitation of the environment at mine sites, technical
liquidation of the mines, and healthcare for former workers (IEA, 2010).
In the 1990s, the Czech government placed restrictions on the extent and impact that coal mining
could have on surrounding regions. These restrictions limit the expansion of some coal mines and
new coal mine development. In June of 2010, the new coalition government announced that the
restrictions would remain for at least four years (Prague Post, 2010).
Starting on January 1, 2005, the Czech natural gas industry began its liberalization (EC, 2007).
Vertical unbundling was also accomplished during this period. Producers, distributors, and natural
gas storage companies were separated and regulations enforced to prevent possible conflicts of
interests of regulated utilities and to improve service costs, transparency, and competition
(Mejstrik, 2004).
Although Czech Republic relies on domestic coal for most of its energy needs, it also imports
substantial amounts of gas. This makes domestic generation of CMM and CBM an attractive
proposition. Holders of CBM production licenses pay a fixed annual fee per unit area and a variable
royalty (about 5 percent) based on a percentage of production. However, the gas prices are set
centrally by the Energy Regulatory Office, which is hindering the development of the CMM market
(Pilcher, 2003).
9.4 Profiles of Individual Mines
Information on individual hard coal mines—including Karvina, CSM, Darkov, and Paskov Mines—
can be found at the OKD website fhttp://www.okd.cz/en/coal-mining/how-coal-is-mined-in-okd/).
and information on both hard and brown/lignite mines can be found in Table 2 of the USGS 2012
Minerals Yearbook - Czech Republic [Advance Release]
(http://minerals.usgs.gov/minerals/pubs/country/2012/myb3-2012-ez.pdf).
9.5 References
BERR/DTI (2004): Assessment of Cleaner Coal Technology Market Opportunities in Central and Eastern
Europe, Department of Business and Regulatory Reform, Project Report R270, DTI/Pub URN 04/1852,
2004.
EC (2007): Communication from the Commission to the Council and the European Parliament - Prospects for
the internal gas and electricity market, European Commission, 1 October 2007.
http: //ec.europa.eu/energy/energy policy/doc/10 internal market country reviews en.pdf
EIA (2014): International Energy Statistics. U.S. Energy Information Administration, Washington, DC,
accessed September 2014. http: //www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
Energie - stavebnf a banska a.s. (2014): Subsidiary Companies - Eurogas, a.s., website accessed September
2014. http://www.energie-as.cz/en/subsidiary-companies/eurogas-a-s.ep/
Euracoal (2014): Czech Republic Profile, European Association for Coal and Lignite, Brussels, Belgium,
accessed September 2014. http://www.euracoal.be/pages/layoutlsp.php?idpage=70
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalinethane.org/coal-inines/cmin/index.aspx
, ,
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CZECH REPUBLIC
Green Gas DPB (2007): Case Study: Green Gas DPB, Czech Republic - Integrated, large scale Mine Gas
Management, presented by Green Gas DBP at the Methane to Markets Partnership Expo, Beijing, China,
30 October-1 November 2007. https://www.globalmethane.org/expo-
docs/china07/postexpo/coal mader.pdf
Green Gas DPB (2012): 'Turning a problem into profit," CBM Review, Green Gas International, March 2012.
http://www.greengas.net/media/uploaded/CBM-Review Turning a problem into profitpdf
Green Gas DPB (2014a): About Us, website accessed September 2014. http: //www.dpb.cz/about-us/
Green Gas DPB (2014b): Projects (selected within Czech Republic), Green Gas International, website accessed
September 2014. http://www.greengas.net/proiects.html
IEA (2010): Energy Policies of IEA Countries - Czech Republic 2010 Review, International Energy Agency,
Paris, France, 2010.
http://www.iea.org/publications/freepublications/publication/CzechRep2010 free.pdf
IEA (2013): Share of Total Primary Energy Supply in 2011 - Czech Republic, International Energy Agency,
Paris, France, 2013. http://www.iea.org/stats/WebGraphs/CZECH4.pdf
Mejstrik (2004): Regulation and Deregulation of Regulation and Deregulation of Utilities in EU and CR:
Utilities in EU and CR: Expectations and Facts, Michal Mejstrik, EEIP a.s., 26 May 2004.
Pilcher (2003): Recent Trends in Recovery and Use of Coalmine Methane, Raymond C. Pilcher, Raven Ridge
Resources Incorporated, 2003. http://www.coalinfo.net.cn/coalbed/meeting/2203/papers/coal-
mining/ C M05 6.p df
PowerGen (2009): Coalmine methane projects in the Czech Republic waste gas used to fuel operations,
Richard Choleva, PowerGen Worldwide, 2009.
http://www.powergenworldwide.com/index/display/articledisplay/3S7197/articles/cogeneration-
and-on-site-power-production/volume-10 /issue-1 /features /coalmine-methane-proiects-in-the-czech-
republic-waste-gas-used-to-fuel-operations.html.
Prague Post (2010): Mining limits will remain, Stephan Delbos, The Prague Post, 16 June 2010.
http://www.praguepost.cz/business/4759-mining-limits-will-remain.html
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
UNEP (2014): CDM/JI Pipeline Analysis and Database, United Nations Environment Programme Danish
Technical University Partnership, accessed July 2014. http: IIcdmpipeline.org/index.htm
UNFCCC (2006): Czech Republic's Initial Report under the Kyoto Protocol, United Nations Framework
Convention on Climate Change, Annex I Party National Reports, October 2006.
http://unfccc.int/files/national reports/initial reports under the kvoto protocol/application/pdf/initia
1 report aau unfccc cze.pdf
UNFCCC (2014): Ratification Status - Czech Republic, United Nations Framework Convention on Climate
Change, website accessed September 2014. http://maindb.unfccc.int/public/country.pl?countrv=CZ
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (1994): U.S. Geological Survey - Mineral Information, 1994.
http://minerals.usgs.gOv/minerals/puhs/country/1994/9410094.pdf
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10.1 Summary of Coal Industry
10.1.1 Role of Coal in Ecuador
Ecuador is neither a consumer nor a producer of coal. Ecuador has maintained its position as Latin
America's fifth largest producer of oil and is one of the top three exporters of oil in the region. Oil is
the keystone to the country's economy and represents a sizeable portion of all export earnings
(EIA, 2014a).
There are estimated reserves of 24 million tonnes of recoverable lignite and sub-bituminous coal,
ranking Ecuador 68th worldwide in total coal reserves (EIA, 2014b).
Table 10-1. Ecuador's Coal Reserves and Production
Anthracite &
Sub-
Indicator
Bituminous
bituminous &
Total
Global Rank
(million
tonnes)
Lignite
(million tonnes)
(million tonnes)
(# and %)
Estimated Proved Coal Reserves 0 24 24 68 (0.003%]
(2011]
Annual Coal Production (2012] 0 0 0 Notapplicable
Source: EIA (2014b]
'<
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ECUADOR
Figure 10-1 shows the location of Ecuador's coal reserves.
Figure 10-1.
Coal Reserves
.Quito
ECUADOR
Coal Deposit
\ # Macas
Location of Ecuador's
Source: Adapted from Biewick et al. (1995]
10.1.2 Stakeholders
Table 10-2 identifies potential stakeholders in Ecuadorian coal mine methane (CMM) development
Table 10-2. Key Stakeholders in Ecuador's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
Equipment Manufacturers
Developers
Carbones del Cerrejon Ltd
BHP Billiton, Newmont
Rio Tinto
Aurelian Resources, Inc.
Breaker Technology, Inc. (BTI]
Kluane International Drilling, Inc. (KID]
See http: //www.epa.gov/coalbed/networkcontacts.html
Engineering, Consultancy, Cardno ENTRIX
and Related Services
Natural Gas Transmission
& Distribution Companies
Regulatory Agencies and
Government Groups
MPC Construcciones e Ingenieria
See http: //www.epa.gov/coalbed/networkcontacts.html
Petroecuador
Ministry of the Environment
Inter-Institutional Committee on Climate Change
Ministry of Non-Renewable Natural Resources
Coal operators in
neighboring countries/
mining operators in
Ecuador
Provide equipment to
other mining industries
in Ecuador
Project opportunity
identification and
planning
Consultant to other
mining industries
Pipeline sales
Regulation, permitting,
licensing
<
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Table 10-2. Key Stakeholders in Ecuador's CMM Industry
Stakeholder Category
Stakeholder
Role
Professional Associations
ARPEL - Regional Association of Oil, Gas and Biofuels Sector
Companies in Latin America and the Caribbean
Project network
10.1.3 Status of Coal and the Coal Mining Industry
Ecuador's mineral industry includes mining of gold, silver, copper, and steel. Crude petroleum and
petroleum refinery products are extracted as well. However, no coal exploration is known and all
coal reserves remain unutilized (USGS, 2008).
10.2 Overview of CMM Emissions and Development
Potential
10.2.1 CMM Emissions from Operating Mines
There are no operating coal mines in Ecuador.
10.2.2 CMM Emissions from Abandoned Coal Mines
Ecuador has no abandoned coal mines.
10.2.3 CBM from Virgin Coal Seams
There is no commercial coal bed methane development at this time in Ecuador. Ecuador, however,
has a fledging natural gas industry. Reserves are relatively small, but the Amistad field in the Gulf of
Guayaquil produces 26 million cubic feet (0.7 million cubic meters) a day to produce electricity at a
nearby power plant. With little natural gas pipeline infrastructure, all other gas is flared in oil
operations (EIA, 2014a).
10.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Table 10-3 summarizes Ecuador's climate change mitigation commitment As a Non-Annex I Party
to the Kyoto Protocol, Ecuador has no national emissions targets and is eligible to host mitigation
projects under the Clean Development Mechanism (CDM).
Table 10-3. Ecuador's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
Kyoto Protocol
June 9,1992
January 15,1999
February 23,1993
January 13,2000
Source: UNFCCC (2014]
In the context of the Kyoto Protocol, Ecuador has proposed two objectives regarding CDM:
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Definition and implementation of the CDM Project Validation Process at the national level.
Promotion and implementation of national capacity (public and private) to prepare CDM projects
and to generate significant Certified Emission Reduction Units (UNFCCC, 2000).
While there are several biomass energy, landfill gas, and other methane avoidance CDM projects
underway in Ecuador, there are none related to coalbed/mine methane. Ecuador's climate change
position will be conducive to development of CMM projects, should they arise from future
utilization of coal reserves.
Ecuador developed a National Strategy on Climate Change (2012-2025) in 2012. It is available here
(in Spanish): http://www.redisas.org/pdfs/ENCC.pdf
10.3.1 Market and Infrastructure Factors
Currently, the market for methane in Ecuador is fairly limited as there is weak domestic demand
and support infrastructure for natural gas (EIA, 2014a). However, Ecuador joined the Global
Methane Initiative (formerly the Methane to Markets Partnership) and its Steering Committee in
2005, and explores methane capture opportunities in its oil and agriculture industries.
Methane emissions, typically from the flaring of natural gas during oil drilling currently make up 15
percent of the country's annual greenhouse gas emissions. To date, there are no records of projects
underway (M2M, 2005; EIA, 2014a).
10.3.2 Regulatory Information
As there are no existing CMM projects (i.e., Ecuador is neither a coal producer nor consumer), a
legal framework regulating them does not exist The oil and natural gas industries are regulated by
the Ministry of Non-Renewable Natural Resources, Hydrocarbons National Directorate. Full Spanish
text of Ecuador's hydrocarbon regulations can be downloaded from the Natural Resource
Governance Institute website at
http://www.resourcegovernance.org/sites/default/files/Ley%20de%20Hidrocarburos.pdf.
10.4 Profiles of Individual Mines
There are no coal mines in Ecuador.
10.5 References
Biewick et al. (1995): Biewick, Laura R. H. and Weaver, Jean N., The Digital Coal Map of South America in
ARC/INFO Format: U.S. Geological Survey Open-File Report 95-235, adapted by Raven Ridge Resources,
Denver, Colorado, 1995.
EIA (2014a): Country Analysis Brief - Ecuador, U.S. Energy Information Administration, Washington, DC, last
updated: January 2014. http://www.eia.gov/countries/cab.cfm?fips=EC
EIA (2014b): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed June 2014. http: //www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
M2M (2005): "Methane International: Methane to Markets Partnership Quarterly Update," Methane to
Markets, November 2005. https://www.globalinethane.org/documents/newsevents mi3.pdf
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UNFCCC (2000): National Communication Republic of Ecuador, United Nations Framework Convention on
Climate Change, November 2000. http: //unfccc.int/resource/docs/natc/ecuncl.pdf
UNFCCC (2014): Ratification Status - Ecuador, United Nations Framework Convention on Climate Change,
accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=EC
USGS (2008): 2008 Minerals Yearbook: Ecuador [Advance Release], United States Geologic Survey, 2008.
http://minerals.usgs.gOv/minerals/puhs/country/2008/myh3-2008-ec.pdf
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11 Finland
11.1 Summary of Coal Industry
11.1.1 Role of Coal in Finland
Finland is not a producer of coal and imports all of its coal for domestic energy consumption.
Approximately 75 percent of coal consumption is used for maintaining the electricity and heating
sectors. It should be noted that annual domestic coal consumption varies due to the hydrological
condition of Finland (IEA, 2007). Finland has no reported coal reserves nor does the country
produce (i.e., extract) coal (Table 11-1).
Table 11-1. Finland's Coal Reserves and Production
Anthracite &
Sub-
Indicator
Bituminous
bituminous &
Total
Global Rank
(million
tonnes)
Lignite
(million tonnes)
(million tonnes)
(# and %)
Estimated Proved Coal Reserves 0 0 0 N/A(0%]
(2011]
Annual Coal Production (2012] 0 0 0 N/A(0%]
Source: EIA (2014]
A
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FINLAND
Figure 11-1. Location of Finland's Coal Reserves
Barerrts Sea
A Port Tampere
#1aunw
/ Lahti
-jUiiS>kaupunk> •
i fe&L-Jurku Loviisa "a"lin'
'5t&' v--^V Espoo .
^ HELSINKI
ALAND '
ISLANDS
Baltic
Soa -
Source: CIA World Factbook (2014]
11.1.2 Stakeholders
Since no coal reserves and/or production exist, there are currently no coal mine methane (CMM)
stakeholders in Finland.
11.1.3 Status of Coal and the Coal Mining Industry
Finland's mineral industry includes (but is not limited to) the mining of gold, nickel, cobalt, copper,
zinc, diamonds, phosphate rock, wollastonite, and talc (USGS, 2013). Finland does not presently
have any identified coal reserves; therefore, no coal mining occurs in Finland.
11.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
CMM recovery projects for Finland, in operation or development (GMI, 2014).
11.2.1 CMM Emissions from Operating Mines
There are no operating coal mines in Finland.
11.2.2 CMM Emissions from Abandoned Coal Mines
Finland has no abandoned coal mines.
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11.2.3 CBM from Virgin Coal Seams
There are no commercial coal bed methane development projects in Finland at this time.
11.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Table 11-2 summarizes Finland's climate change mitigation commitment. Finland is an Annex I
Party to the Kyoto Protocol. Finland has an emissions reduction target of 6 percent below the 1990
levels for 2008-2012.
Table 11-2. Finland's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 4,1992
May 3,1994
Kyoto Protocol
April 29,1998
May 31,2002
Source: UNFCCC (2014]
Finland's National Strategy for Adaptation to Climate Change was adopted in 2005 as an
independent element of the broader National Energy and Climate Strategy which was outlined in
2005, finalized in 2008, and subsequently updated in 2013. None of these documents address CMM
(EEA, 2014).
11.3.1 Market and Infrastructure Factors
Finland joined the Global Methane Initiative (formerly the Methane to Markets Partnership) in
2008 and is working with stakeholders to recover and utilize methane produced by Finland's 33
landfills as well as its wastewater treatment facilities. Finland is also providing funding support for
other international projects in countries such as Honduras and Nicaragua (USEPA, 2008). Finland
currently sits on the GMI Agriculture, Municipal Solid Waste, and Municipal Wastewater
Subcommittees.
11.3.2 Regulatory Information
The Mining Act of1965 previously provided the legal framework for mining operations in Finland.
In late 2008, a working group was formed by the Finnish governmentto revise the outdated Act
The new Mining Act entered into force in July 2011 and supersedes the previous 1965 Act The new
Act includes provisions concerning the rights and obligations of parties engaged in ore prospecting,
mining and gold panning—both during operations and as termination measures are taken (e.g.,
aftercare). While securing the preconditions for mining and ore prospecting more effectively than
before, the new Act takes account of environmental issues, citizens' and landowners' rights, and
municipalities' opportunities to influence decision-making as well as reconciles various public and
private (i.e., competing) interests (MEE, 2011).
11.4 Profiles of Individual Mines
There are no coal mines in Finland.
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11.5 References
CIA (2014): CIA World Factbook, accessed July 2014. https://www.cia.gov/library/publications/the-world-
factbook/geos / fi.html
EEA (2014): European Climate Adaptation Platform: Finland, European Environment Agency, accessed July
2014. http://climate-adapt.eea.europa.eu/countries/finland
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http: //www.eia.gov/cfapps/ipdhproiect/IEDIndex3.cfm
IEA (2007): Energy Policies of IEA Countries - Finland 2007 Review, International Energy Agency, Paris,
France, 2007. http://www.iea.org/publications/freepublications/publication/finland2007.pdf
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.glohalmethane.org/coal-mines/cmm/index.aspx
MEE (2011): Ministry of Employment and the Economy, 9 June 2011.
http://www.tem.fi/en/current issues/press releases/press release archive/year 2011 /new mining act
to enter into force on 1 iuly.103119.news
UNFCCC (2014): Ratification Status - Finland, United Nations Framework Convention on Climate Change,
accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=FI
USEPA (2008): Finland Joins Methane to Markets Partnership to Curb Greenhouse Gas Emissions, U.S.
Environmental Protection Agency, 2008.
http://yosemite.epa.gOv/opa/admpress.nsf/a883dc3da7094f978S2S72a0006Sd7d8/S6878f6829e34hh
88525748f00573e84!QpenDocument
USGS (2013): 2011 Minerals Yearbook - Finland [Advance Release], United States Geological Survey, July
2013. http: //minerals.usgs.gOv/minerals/pubs/country/2011/myb3-2011-fi.pdf
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12 France
12.1 Summary of Coal Industry
12.1.1 Role of Coal in France
Coal has become less important in France's energy supply, constituting only 4 percent of the
nation's total energy consumption in 2011 (IEA, 2013). Nuclear power has replaced most of
France's coal-fired power plants. France consumed 17.3 million tonnes (Mmt) of coal in 2012 (EIA,
2014).
France has negligible coal reserves (EIA, 2014) and the country's coal production has virtually
ceased, having closed its last coal mine in April 2004 (BBC, 2004). The countiy's total coal
production was 6.2 Mmt in 1999, but reduced to only 0.16 Mmt in 2004; the lastyear coal was
mined.
Table 12-1. France's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous &
Lignite
(million tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
0
0
0
Not applicable
(2011]
Annual Coal Production (2012]
0
0
0
Not applicable
Source: EIA (2014]
12.1.2 Stakeholders
Table 12-2 lists key potential stakeholders in French coal mine methane (CMM) development
Table 12-2. Key Stakeholders in France's CMM Industry
Stakeholder Category Stakeholder Role
Mining companies ¦ Charbonnages De France Project host
¦ European Gas Limited (EGL]
¦ Future Corporation Australia
¦ PanTerra Geoconsultants
¦ Compagnie Nationale a Portefeuille S.A.
¦ Transcor Astra Group
Natural Gas Transmission ¦ Gaz De France Gas distribution
& Distribution Companies
Developers ¦ See http: //www.epa.gov/coalbed/networkcontacts.html Project opportunity
identification and
planning
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Table 12-2. Key Stakeholders in France's CMM Industry
Stakeholder Category
Stakeholder
Role
Engineering, Consultancy,
and Related Services
Government Groups
¦ See http://www.epa.gov/coalbed/networkcontacts.html
¦ Ministiy of the Economy, Industry and the Digital Sector
¦ Ministiy of Ecology, Sustainable Development and Energy
¦ Commission of Regulation of the Energy (CRE]
Technical assistance
Regulatory
12.1.3 Status of Coal and the Coal Mining Industry
There were three main coal-producing areas in France: the Nord-Pas de Calais, the Lorraine basin,
and the Central Massif basins. As of now, France does not produce any coal. The country is left with
many abandoned coal mines, however, since the coal mining industry in France dates back
hundreds of years.
The steady decline in the country's coal sector over the past decades is attributable to cheaper
imports replacing the domestic sources, its shift to nuclear power, and its concern for the
environment The state-owned coal monopoly, Charbonnages de France, closed its last production
facility in April 2004.
12.2 Overview of CMM Emissions and Development
Potential
12.2.1 CMM Emissions from Operating Mines
Over the last century, there have been a number of CMM projects in France utilizing gob gas from
active and abandoned mines for power generation and heating applications. However, these
projects at active mines closed as the coal mining sector declined overall.
Before domestic production stopped, the majority of the CMM activity to date focused on the coal
seams of the Nord-Pas de Calais basin. In 2000, methane emissions totaled 166.0 million cubic
meters (m3) but in the years since, there have been no recorded emissions (USEPA, 2012).
12.2.2 CMM Emissions from Abandoned Coal Mines
In France, several CMM use projects are reported to be operating at abandoned mines. The Global
Methane Initiative (GMI) International CMM Projects Database currently identifies three methane
recovery and utilization projects at abandoned mines in France. Two projects utilize the recovered
methane for industrial use and the third one for pipeline injection (GMI, 2014). Their level of
methane emission mitigation is not reported. Updates on future CMM projects in France can be
found at https://www.globalmethane.org/coal-mines/cmm/index.aspx.
Among the projects at abandoned mines, Gazonor is a venture of European Gas Limited (EGL)
acquired from Charbonnages de France. Several mines are sources for extraction, including Divion,
Avion, and Desiree. EGL is permitted for 579 km2 and further permits are under application for an
additional 1500 km2. Since CMM extraction began in 1979, a total of 2,189 million m3 have been
extracted as of 2008 with an approximate methane content of 54 percent. Annual production for
the last five years has averaged 72.1 million m3. As part of a restructuring announced in May 2011,
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EGL has entered into a Production Sharing Agreement (PSA) in relation to two large production
permits covering 766 km2 in Northern France. The PSA is between EGL and Gazonor, EGL's former
operating subsidiary, which is now owned by Transcor France (EGL, 2011],
EGL is also operating several wells at Lons le Saunier in eastern France, producing about 83.7
million m3 annually. At Lorraine, EGL estimates that 1,104 million m3 of methane is available. The
permit covers 988 km2, but actual production had not begun as of 2008. The Gardanne project in
L'Arc Base, northeast of Marseille, is estimated to hold up to 20 seams with up to 2,800 million m3
of gas resource. However, further efforts to advance EGL's mine methane projects in France have
been hampered by bureaucratic posturing (Reuters, 2013}.
SNET, a subsidiary of Charbonnages de France, operates two power production facilities that utilize
co-fired CMM—Hournaing and Emile Huchet Groupe V—comprised of three units with a design
capacity of 253 MWe and six units with a design capacity of 1086 MWe, respectively (GEO, 2014),
In an inventory of coal bed methane (CBM) in the Lorraine Basin, the gas in place was assessed at
11.8 billion m3 in the Saint Avoid area and at 16.3 billion m3 in the Alsting area (EGL, 2005). No data
quantifying CMM recovery from virgin coal seams are currently available.
12.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Figure 12-1. CMM Projects in France
Source: EGL (2010)
12.2.3 CBM from Virgin Coal Seams
France signed and ratified the UNFCCC and Kyoto Protocol, as indicated in Table 12-3.
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Table 12-3. France's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 13,1992
March 25,1994
Kyoto Protocol
April 29,1998
May 31,2002
Source: UNFCCC (2014]
France has put forth various climate strategies since 1995. These initial climate actions were
followed by the National Programme for Combating Climate Change in 2000, which was followed by
the country's National Strategy for Sustainable Development published in 2004 and updated in
2006 (Ecologic Institute/eclareon, 2013). The policy for combating climate change was
strengthened in late 2007, and eventually named the Climate Plan: 2004-2012 as France's action
plan for meeting its Kyoto commitments.
In advance of its hosting the 2015 Conference of Parties (COP) in Paris, France proposed three
climate policy goals, which included: defining an agreement applicable to all, adopting legally
binding text, and aiming for an ambitious goal to keep global temperature increase below 2°C
(Euractive, 2013).
12.3.1 Market and Infrastructure Factors
There are few companies involved in potential CBM project development in France. Schlumberger,
a technology and project management company, offers CBM consulting services as well as its
ECLIPSE CBM model, which examines CBM potential of a particular mining site (Schlumberger,
2010). Total S.A., the French petroleum giant, has expanded its portfolio to include CBM assets. In
2010, Total pursued its growth into unconventional gas by acquiring a stake in Australia's
Gladstone LNG project, the very first CBM liquefaction project in the world (Total, 2014).
12.3.2 Regulatory Information
France actively encourages its CMM development industry by including mine methane as
recoverable energy in renewable tariffs; including it with landfill and sewage methane in
renewables targets; treating it as a secure energy resource; and promoting CMM technology as
climate change technology in world markets (ACMMO, 2007).
In France, CMM is covered under the Electricity Act 2000, which was modified to include
recoverable energy from mine methane, landfills, biomass, and sewage digesters. The feed-in tariff
with premium prices for renewable electricity generated from these sources has provided strong
incentive to the methane mitigation industry and a large number of new projects are already under
way (CRE, 2010; ACMMO, 2007; EREC, 2009).
12.4 Profiles of Individual Mines
Data profiling gassy mines in France are unavailable. The last active coal mine in France closed in
2004 (BBC, 2004).
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12.5 References
ACMMO (2007): "UK Mine Methane Facts and Figures," The United Kingdom's Association of Coal Mine
Methane Operators, website accessed June 2010.
BBC (2004): "France Closes its Last Coal Mine" www.news.bbc.co.uk, 23 April 2004.
http://news.hhc.co.Uk/l /hi/world/europe/3651881.stm
CRE (2010): "Guidelines and Laws," Commission of Regulation ofthe Energy (CRE), Paris, France, 2010.
Ecologic Institute /eclareon (2013): Assessment of climate change policies in the context of the European
Semester- Country Report: France, Ecologic Institute /eclareon, June 2013.
http://ec.europa.eu/clima/policies/g-gas/progress/docs/fr 2013 en.pdf
EGL (2005): European Gas Limited and Controlled Entities: Half-Year Financial Report, European Gas Limited,
31 December 2005.
http://glohaldocuments.morningstar.com/documentlihrary/document/da83dha49a9f0976.msdoc/origi
nal
EGL (2010): European Gas Limited, website accessed June 2010.
EGL (2011): "Entry into Production Sharing Agreement," European Gas Limited press release, 27 May 2011.
http://www.asx.com.au/asxpdf/20110530/pdf/41yxnnm6bvptv3.pdf
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http: //www.eia.gov/cfapps/ipdhproiect/IEDIndex3.cfm
EREC (2009): Renewable Energy Policy Review - France, European Renewable Energy Council, Brussels,
Belgium, 2009.
http://www.erec.org/fileadmin/erec docs/Proicet Documents/RES2020/FRANCE RES Policy Review 0
9 Final.pdf
Euractive (2013): "France spells out ambitions for 2015 climate conference in Paris," Efficacite et
Transparence des Acteurs Europeens, 11 April 2013. http://www.euractiv.com/climate-change/french-
socialists-want-climate-c-news-531463
IEA (2013): Share of total primary energy supply in 2011 - France, International Energy Agency, Paris,
France, 2013. http: //www.iea.org/stats/WebGraphs/FRANCE4.pdf
GEO (2014): Current List of Coal Power Plants - France, Global Energy Observatory, accessed July 2014.
http://globalenergyobservatory.org/list.php?db=PowerPlants&type=Coal
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.glohalmethane.org/coal-mines/cmm/index.aspx
Reuters (2013): "Politics hamper bid to unlock French coal mine gas riches, Reuters, 18 February 2013.
http://www.reuters.com/article/2013/02/18/us-france-gas-mines-idUSBRE91H0M32013Q218
Schlumberger (2010): ECLIPSE Coalbed Methane Program, website accessed June 2010.
http://www.slb.com/services/software/reseng/eclipse options/cbm.aspx
Total (2014): Strengthening Positions in Unconventional Gas, Total, website accessed July 2014.
http://www.total.com/en/energies-expertise/oil-gas/exploration-production/strategic-
sectors/unconventional-gas/total-world-class-plaver/strengthening-positions-unconventional-
gas?%FFbw=kludgel%FF
UNFCCC (2014): Ratification Status - France, United Nations Framework Convention on Climate Change,
accessed November 2014. http: //maindb.unfccc.int/public/country.pl?countrv=FR
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
A
Methane irrigative CMM Country Profiles 111
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13 Georgia
13.1 Summary of Coal Industry
13.1.1 Role of Coal in Georgia
Coal deposits were discovered in Georgia in the first half of the 19th century, although until the
1930s geological exploration of these deposits was sporadic. Rapid development of the coal
deposits in Georgia began after World War II, with produced coal being supplied to the Rustavi iron
and steel works. Seven coal deposits have been discovered in Georgia, but only three of them are of
commercial importance: the Tkibuli-Shaori and Tkvarcheli bituminous coal deposits and the
Akhaltsikhe brown coal deposit (Figure 13-1}. Most of the republic's coal reserves are concentrated
in these deposits and the Tkibuli-Shaori deposit accounts for more than 75 percent of Georgia's coal
reserves, followed by Akhaltsikhe and then Tkvarcheli (UNFCCC, 2009).
Figure 13-1. Georgia's Main Coal Fields
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Table 13-1. Georgia's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-bituminous
& Lignite
(million tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011*] (2013**]
331.1**
75.7**
406.8**
49 (0.0032%]*
Annual Coal Production (2012]
0.254
0
0.254
56 (0.022%]
Sources: *EIA (2013a]; **SAQ (2013]
13.1.2 Stakeholders
Potential stakeholders in Georgia's coal mine methane (CMM) industry are listed in Table 13-2.
Table 13-2. Key Stakeholders in Georgia's CMM Industry
Stakeholder
Category
Stakeholder
Role
Coal Producing
Enterprise
¦ Georgian International Energy Corporation (GIEC]
Project host
State Partnership Fund
Developer
¦ Georgian International Energy Corporation (GIEC]
Project opportunity
¦ See http://www.epa.gov/coalbed/networkcontacts.html
identification and planning
Engineering or
Consultancy
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
Services
Universities and
¦ National Academy of Sciences of Georgia
Research Centers
¦ Georgia National Science Foundation
¦ Tbilisi State University
¦ Ministry of Education and Science - Mining Institute
Technical assistance
Other
¦ KazTransGaz-Tbilisi
¦ OPIC
Government Groups
¦ Ministry of Energy
¦ Ministiy of Environmental Protection and Natural Resources
Licensing and permitting
13.1.3 Status of Coal and the Coal Mining industry
Coal mining in Georgia is made difficult by the depth of the coal seams, the locations of deposits in
mountainous areas and, in some areas, the relatively high methane content (14+ cubic meters [m3]
per tonne) of the coal. Insufficient financing of mines in the late 1990s to early 2000s (as State
subsidies dried up because of the country's economic crisis), a lack of markets, and costly
extraction, led to minimal production at that time. The Georgian government has prioritized the
revitalization of the coal mining sector, in the hope of providing much needed jobs and some
economic resurgence in the Tkibuli-Shaori and Akhaltsikhe regions (UNFCCC, 2009).
The only underground mine currently producing coal in Georgia is the Mindeli mine in the Tkibuli-
Shaori coalfield. The mine, operated by Saknakhshiri LLC, resumed coal extraction in 2008 after a
15-year break. In partnership with the Georgian International Energy Corporation (GIEC), the
mine's flooded tunnels have been pumped dry and restored, shaft development projects have taken
place, mine buildings have been refurbished, and the mine railway line has been repaired. The total
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cost for the redevelopment of the mine came to more than $10.8 million (GEL20 million) (GIEC,
2010).
Coal from the project currently supplies cement factories in Kaspi and Rustavi, but Saknakhshiri
LLC plans to increase current coal production to accommodate two thermal power plants with
generation capacities of 160MW and 300MW, which are to be constructed by GIEC. To meet the coal
demand, Saknakhshiri intends to improve coal extraction in current shafts to 0.850 to 0.9 million
tonnes (Mmt) per year and construct a new mineshaft to accommodate an additional 2-3 Mmt per
year (Figure 13-2). The coal improvement project is under technical review and a feasibility study
is underway for the establishment of reserves to support a new mineshaft (SAQ, 2013).
Saknakhshiri also holds a license for coal extraction from the Vale coalfield near Akhaltsikhe, in
southern Georgia, estimated to have coal reserves of more than 75 Mmt available for open cast
mining.
Figure 13-2. Georgia Coal Production (thousand tonnes)
TO
i/i
3
O
£ o
15
o
u
300
250
200
150
100
50
0
254
152
140
! 6 8 8 5 9 14 12
<£> <$?> 00<° 0°^ o? qP'
Sources: UNFCCC (1999]; EIA (2013a]
An operating open-cast mine is located at Tvarcheli, in the breakaway republic of Abkhazia.
Produced coal from this mine is used to supply iron and steel works in Rustavi.
13.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently has no record
of any active CMM projects in Georgia (GMI, 2014). One feasibility study, sponsored by the U.S.
Trade and Development Association (USTDA), was carried out on the possible development of a
CMM drainage and utilization project in the Tkibuli-Shaori coal field.
13.2.1 CMM Emissions from Operating Mines
Limited data is available on Georgia's CMM emissions. Table 13-3 shows data available from
Georgia's Second Communication to the United Nations Framework Convention on Climate Change
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(UNFCCC). 18.79 million m3 of CMM are estimated to have been emitted in 1990, at which time coal
production was 956,000 tonnes per year.
Table 13-3. Georgia's CMM Emissions (million cubic meters)
Emission Category 2000
2005*
2010*
2015*
(projected)
Underground coal mines - 0.139
ventilation emissions
Underground coal mines - 0
drained emissions
Total liberated 0.139
(= sum of all above]
Recovered & Used 0
Total emitted 0.139
(= Total liberated -
recovered & used]
0.235
0.246
0.280
Source: UNFCCC (2009], *USEPA (2012]*
Coal production operations at the Mindeli mine are being ramped up after being idle for almost 20
years. Production is expected to exceed 200,000 tonnes per year in the near future and when
longwall operations are active it is planned to produce 1 Mmt of coal per year. At that time, CMM
emissions would be expected to reach their 1990 levels. CMM is not currently drained from the
mine, either by in-seam boreholes or via gob drainage. Methane is diluted in ventilation air and
carried to the surface where it is emitted to the atmosphere. A March 2010 explosion, which killed
four miners and was attributed to a build-up of methane, illustrates the need for improved methane
drainage at the mine (Georgian Times, 2010).
13.2.2 CMM Emissions from Abandoned Coal Mines
There are a few abandoned mines in the Tkibuli-Shaori coalfield, but there are currently no
methane recovery projects operating or planned in Georgia.
13.2.3 CBM from Virgin Coal Seams
Georgia does not currently produce CBM from virgin coal seams. A USTDA feasibility study
evaluated the possible development of a CMM project at the Tkibuli-Shaori and potential CBM
extraction from the coalfield. The coal in this area is found in nine distinct layers that vary in
thickness from 1 to 10 m, at depths of 500 - 1,500 m. Total coal thickness ranges from 20 to 50 m
and in some places exceeds 75 m. Gas contents range from 6-20 m3 per tonne and gas-in-place for
the field is estimated to be 11.5 billion m3 (ARI, 2009). The feasibility of CBM drilling is also been
studied in the Vale coalfield in southern Georgia. Possible reserves for this area have not yet been
estimated.
13.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Georgia ratified the United Nations Framework Convention on Climate Change (UNFCC) in 1994
(Table 13-4) as a non-Annex I Party and since then has been actively engaged in the fulfillment of
its obligations under the Convention. The government supports the implementation of any projects
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and programs that will lead to the reduction of greenhouse gas (GHG) emissions, facilitate the
drawing of additional environmentally sound investments and transfer the country to a sustainable
development pathway (MEP, 2009).
Table 13-4. Georgia's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
NA
July 29.1994
Kyoto Protocol
NA
June 16,1999
Source: UNFCCC (2014]
13.3.1 Market and Infrastructure Factors
Georgia currently operates with a severe energy deficit, producing less than six percent of its
domestic fuel requirements from its own resources (USTDA, 2008). 98 percent of Georgia's oil and
natural gas supplies are imported. In 2010, Georgia produced 51.4 thousand tons of oil and 11.1
million m3 of natural gas. Georgia's proven oil and gas resources are modest, according to the
Energy Charter Secretariat (EnCharter, 2012). The country's 15 oilfields have confirmed reserves of
about 8.3 million tons but larger oil reserves are assumed to exist. The oil potential of the Black Sea
shelf is estimated at 70 million to 1.3 billion barrels. (Energy Charter, 2012). Other indigenous
energy supplies are limited primarily to hydropower and traditional biomass for residential heating
(Energy Charter, 2012; EIA, 2013b).
The majority of oil and natural gas has historically come from Russia since Georgia is an important
transit country. To reduce dependency on Russia, Georgia began turning to the Caspian fields for
natural gas supply after 2000, and the South Caucasus Pipeline began delivering natural gas to
Georgia in 2007. Total capacity on the pipeline is 8 billion m3 per year (EIA, 2013b).
The Georgian government is looking to further diversify its energy base and is encouraging the
continued redevelopment of the coal industry, along with potential development of thermal power
stations near coalfields. Georgia also has sizeable hydropower capacity, which is a growing
component of its energy supplies. The Ministry of Energy has announced plans to rehabilitate older
hydropower plants, and build new ones to increase generation capacity (EIA, 2013b).
Utilization options for produced methane include on-site electricity generation or direct use by
local residents, a policy in line with the government's recent push to supply gas to rural areas. But
CMM will have to compete with hydroelectric power and other renewable energy resources such as
geothermal energy (currently used for district heating) and wind power.
13.3.2 Regulatory Information
Georgia does not have any specific laws or regulations pertaining to CMM extraction. Potential
issues concerning ownership of drained methane from coal mines or coal areas may arise due to the
fact that the government has awarded conventional oil and gas licenses that overlap with coal
mining areas.
13.4 Profile of Individual Mines
Coalfield data for the Mindeli and Dzidziguri mines is presented in Table 13-5, with a general profile
of the Tkibuli-Shaori coal field shown in Table 13-6.
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Table 13-5. Tkibuli-Shaori Coal Properties
Coal Property
Mine
Ash content
(%)
Moisture Content
(%)
Sulfur
(%)
Volatile Material
(%)
Heat Capacity
(calories)
Mindeli
37-43
14.0
1.0-1.5
39.5-42.2
4,200-4,600
Dzidziguri
29-35
14.5
1.0-1.5
40-42.8
4,100-4,500
Source: ARI (2009]
Table 13-6. Tkibuli-Shaori Coal Field Profile
Tkibuli-Shaori Field - Mindeli and Dzidziguri Mines
Mine Status
Active
Operator/Owner
Saknakhshiri LLC
Mine Area
47 km2
Coal Field
Tkibuli-Shaori
Mining Method
Room and pillar / Longwall
Location
50 kms NE of Kutaisi, Imereti
region
Reserves (coking coal)
330 Mt
2006 VAM volume
0.139 million m3
No. of seams mined
9
2006 Drained CH4 volume
0
Depth of seams
500-1,500 m
2006 Utilized CH4 volume
0
Annual coal production
500,000 + tonnes
Utilization method
None
capacity
13.5 References
ARI (2009): CMM and CBM development in the Tkibuli-Shaori Region, Georgia, prepared for
GIG/Saknakhshiri and U.S. Trade and Development Agency by Advanced Resources International, Inc.,
2009.
EIA (2013a): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed June 2014. http: //www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
EIA (2013b): Country Analysis Notes, U.S. Energy Information Administration, Washington, DC, September
2013. http: //www.eia.gov/countries/country-data.cfm?fips=GG
EnCharter (2012): Georgia: In-Depth Review of Energy Efficiency Policies and Programmes, Energy Charter
Secretariat, Brussels, Belgium, 2012.
http://www.encharter.org/fileadmin/user upload/Publications/Georgia EE 2012 ENG.pdf
Georgian Times (2010): March 4 is day of mourning in Georgia, The Georgian Times webpage, 4 March 2010.
GIEC (2007): Georgia Energy Projects, presented by Turnava, N., Georgian International Energy Corporation
at the Institut Europeen des Hautes Etudes Internationales - Club de Nice, 2007.
GIEC (2008): Saknakhshiri resumes coal extraction after 15-year break, News Release - Georgian
International Energy Corporation website, 5 August 2008.
GIEC (2010): News Release - Georgian International Energy Corporation website, accessed July 2010.
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed in July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
SAQ (2013): Corporate Overview of 2012, Saqnakhshiri (GIG Group) Ltd., Tkibuli, Georgia, 2013.
http://www.gig.ge/rn/u/ck/files/Presentations/SAKNAKHSHIRI 2012 full%20overview.pdf
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UN (2004). Map of Georgia, United Nations Cartographic Department website, 2004.
http://www.un.org/Depts/Cartographic/map/profile/georgia.pdf
UNFCCC (1999): Georgia's Initial National Communication to the United Nations Framework Convention on
Climate Change, Tbilisi, 1999. http: //unfccc.int/resource/docs/natc/geoncl.pdf
UNFCCC (2009): Georgia's Second National Communication to the United Nations Framework Convention on
Climate Change, Tbilisi, 2009. http: //unfccc.int/resource/docs/natc/geonc2.pdf
UNFCCC (2014): Ratification Status - Georgia, United Nations Framework Convention on Climate Change,
website accessed September 2014. http://maindh.unfccc.int/puhlic/country.pl?country=GE
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990 - 2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USTDA (2008): USTDA Director Walther travels to Georgia, United States Trade and Development Agency
Press Releases, 25 August 2 008.
http://www.ustda.gOv/news/pressreleases/2008/EuropeEurasia/Georgia/WaltherGeorgiaOverview 08
2508.asp
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14 Germany
14.1 Summary of Coal Industry
14.1.1 Role of Coal in Germany
Germany was the world's eighth largest producer of coal in 2012 and is the world's largest
producer of brown coal (lignite), accounting for an estimated 18 percent of global output in 2012
(EIA, 2014a). Coal is Germany's most important indigenous energy resource, accounting for almost
45 percent of the country's total primary energy production in 2012. Brown coal accounted for over
25 percent of German electric power generation in 2012 and hard coal accounted for just over 19
percent (Mathews, 2013). Nearly all coal production serves the power and industrial sectors (EIA,
2014b). Although total coal production in Germany has been steadily declining to a low of 182
million tonnes in 2010, brown coal production has started to increase in recentyears (EIA, 2014a).
Brown coal-fueled electricity production in Germany reached its highest level since 1990 in 2013
(Wagstyl, 2014). Germany's coal consumption has increased after Japan's Fukushima reactor
accident occurred in March 2011, as Germany has increasingly relied on coal as a substitute for
nuclear power (EIA, 2014b). Table 14-1 summarizes Germany's coal reserves and production.
Table 14-1. Germany's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
48
40,500
40,548
6 (4.6%]
Annual Coal Production (2012]
11.6
185.4
197.0
8 (2.5%]
Source: EIA (2014a]
Germany is a net coal importer, importing more than 45 thousand tonnes of hard coal in 2013 from
Russia (11.8 thousand tonnes), the United States (11.5 thousand tonnes), Colombia (8.1 thousand
tonnes), European Union (EU) countries, Australia, Poland, South Africa, and small quantities from
other countries (Statistik der Kohlenwirtschaft e.V., 2014a).
Germany's current hard coal production is from three underground mines—Prosper-Haniel,
Auguste Victoria and Ibbenbueren—located in North-Rhine-Westphalia in western Germany
(Euracoal, 2013; Euracoal, 2014), while all brown coal production is from surface mines in basins
across the country (Figure 14-1).
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Figure 14-1. Germany's Coal Fields
Hard Coal Fields
^ ^ Osnabruck
Ibbenburen
Stilllegungen in 2012
Saarrevier: 30.06.
BW West: 31.12.
Ruhrrevier
Kamp-
Lintfort
Dinslaken
* 1
Bottrop
Duisburg
Essen
Recklinghausen
Heme Dortmund
Hamm
Saarrevier
Ensdorf
&
~ Saar-
, brucken
Stand: Januar2013
X Bergwerke
1 Prosper-Haniel
2 Auguste Victoria
3 Ibbenburen
Braunkohlenforderung in Mio. t
Stromerzeugung in TWh
Kraftwerkskapazitat
LagerstattenvorrSte - genehmigte und
erschlossene Tagebaue
Geologische Vorrate
Source: Statistik der Kohlenwirtschaft e.V. (2013)
14.1.2 Stakeholders
Table 14-2 lists potential stakeholders in coal mine methane (CMM] development in Germany.
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Table 14-2. Key Stakeholders in Germany's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
¦ RAG Deutsche Steinkohle AG
Operator of hard coal
mines
Equipment Manufacturers
¦ GE Jenbacher, Deutz Power Systems GmbH & Co. KG
Power generation
¦ ETW-Energietechnik GmbH
equipment supplier
¦ Pro2-Anlagentechnik GmbH
Power plant engineering
¦ G.A.S. Energietechnik GmbH
and construction
¦ LAMBDA-Gesellschaft fur Gastechnik mbH
¦ Lennetal Industrie Service
Developers
¦ Minegas GmbH und Mingas Power GmbH
Project opportunity
¦ A-TEC Anlagentechnik GmbH
identification and
¦ Evonik New Energies GmbH
planning
¦ Stadtwerke Heme AG
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Engineering, Consultancy,
¦ Deutsche Montan Technologie GmbH
Testing, consulting.
and Related Services
¦ ATEMIS GmbH
¦ Umwelttechnik Bojahr
¦ See http://www.epa.gov/coalbed/networkcontacts.html
engineering
Universities, Research
¦ Fraunhofer UMSICHT
Examining, developing.
Establishments
¦ RWTH Aachen
and optimizing technical
¦ Deutsche Montan Technologie GmbH
processes in the areas of
environmental, safety,
process, and energy
technology
Regulatory Agencies
¦ State Ministry for the Environment
Project identification and
¦ Nature Conservation and Reactor Safety
assessment support
Government Groups
¦ Bezirksregierung Arnsberg / Abt. 8 Bergbau und Energie
Mining authority
Professional Associations
¦ IVG e.V.
Establishes project
¦ Landesinitiative Zukunftsenergien NRW
network, advises
members on technical,
economic, and legal issues
Other
¦ KfW Banking Group
Investment finance.
¦ Emissions-Trader ET
emissions trading
¦ Emissions-Trader ET
¦ Future Camp
Drilling contractors
¦ Daldrup & Sohne AG
¦ Anger's Sohne
Coal Mining Foundation
¦ RAG-Stiftung
14.1.3 Status of Coal and the Coal Mining Industry
Germany has experienced a recent increase in brown coal production after a post-reunification
downturn, in response to an increased demand from power plants and interim power
arrangements stemming from Germany's Energiewende. Energiewende is a term coined in the
1980s meaning "energy transition" referring to the country-wide energy infrastructure transition
commenced in 2011 when the German parliament voted to abolish nuclear power following Japan's
Fukushima disaster. Germany is replacing nuclear energy with renewables and new combined-
cycle gas turbines; however, in the interim, power arrangements have involved marginally more
coal being burned. Brown coal increased by a full percentage point of German electric power
generation in 2012 and hard coal rose 0.6 percentage points (Euracoal, 2014; Mathews, 2013).
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There has been a downsizing of the hard coal sector due to incremental reduction of subsidies
which are scheduled to fully expire in 2018 (Morris, 2014). In 1991, Germany operated 26 hard coal
mines and employed 122,871 miners, while in 2013, only 3 mines were in operation and 12,500
miners employed (Euracoal, 2014).
Table 14-3 provides recent statistics on German coal mines.
Table 14-3. Germany's Coal Mining Statistics 2013
Type of Mine
Production
Number of
(million tonnes)
Mines
Underground (active] mines - total
7.5
3
Surface (active] mines - total
182.6
14
Sources: Statistik der Kohlenwirtschaft e.V. (2014a]; Statistik der Kohlenwirtschaft e.V. (2014b]
14.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies 43
CMM projects operating in Germany (GMI, 2014). Thirty-seven are located at abandoned mines,
nine are at active, underground mines, and two are undetermined. The methane from 30 projects is
being used for power generation, while the remaining 13 projects use the methane for combined
heat and power (GMI, 2014).
14.2.1 CMM Emissions from Operating Mines
Table 14-4 quantifies Germany's recent methane emissions from coal mining. The data in this table
may vary from the EPA data presented in the Executive Summary due to differences in inventory
methodology and rounding of digits.
Table 14-4. Germany's CMM Emissions (million cubic meters)
Type of Mine
2000
2005
2010
2015
(projected)*
Underground mine
646.65
374.14
180.27
Post-underground mine
28.45
21.09
10.92
Surface mine
2.71
2.88
2.74
Abandoned Mines
189.76
4.22
1.05
Total liberated (= sum of all above)
867.57
402.33
194.99
247.0
Source: UNFCCC (2014a]; USEPA (2012]
14.2.2 CMM Emissions from Abandoned Coal Mines
There are substantial abandoned mine methane (AMM) recovery and utilization activities
underway in Germany, with 37 individual projects reportedly in operation. These projects are
power generation and combined heat and power projects and together account for more than 113
<
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MW of electricity. German AMM projects mitigate more than 400 million cubic meters (m3) of
methane emissions annually (GMI, 2014).
14.2.3 CBM from Virgin Coal Seams
There are no CBM recovery efforts from virgin coal seams in Germany at present The absence is
attributable to high exploration and production costs, and unsuitable available technology.
However, with German energy demand and energy prices on the rise, the Technical University of
Aachen (RWTH Aachen) is currently reevaluating German CBM potential. Apre-feasibility study
was carried out by FUMINCO GmbH and RWTH Aachen in 2007 and 2008, examining the technical
feasibility of CBM production by drilling deep wells in the Ruhr and Miinsterland area. The pre-
feasibility study was the first step in a three phase project, which was financed by the government
of North Rhine-Westphalia, Minegas GmbH and Mingas-Power GmbH. The second phase of the
project was an economic study of CBM production and the third phase, a risk assessment, has yet to
commence (FUMINCO GmbH, 2014). These efforts are primarily motivated by advances in drilling
and simulation technologies. Germany has potential in-place CBM resources of 3 trillion m3, of
which 2 million m3 is concentrated in the mining fields in the Ruhr area alone. Prospects for CBM
recovery are thus poised to develop (Mosle et al, 2009).
14.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Germany has ratified the Kyoto Protocol. Under Europe 2020, the EU's growth strategy, the EU has
a greenhouse gas (GHG) emission reduction target of a 20 percent reduction compared to 1990 by
2020. Germany has set its own national target of a 14 percent reduction compared to 2005 by 2020.
The national target on GHG emissions (-14 percent) covers emission sources not already included
in the European exchange system of emission quotas (EU Emissions Trading Scheme) and uses
2005 as reference year. The EU target (-20 percent) covers all emissions sources and use 1990 as
reference year (EC, 2013a). Germany has also set a national energy efficiency targetto reduce
primary energy consumption by 20 percent compared to the 2008 level by 2020 (EC, 2013b). Table
14-5 summarizes Germany's commitment to international climate change mitigation agreements.
Ratifying the Kyoto Protocol has made Germany eligible to benefit from the growing world market
for carbon emission reduction credits.
Table 14-5. Germany's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 12,1992
December 9,1993
Kyoto Protocol
April 29,1998
May 31,2002
Source: UNFCCC (2014b]
Germany has purchased credits from 207 Clean Development Mechanism (CDM) projects, including
from two CMM projects in China. Germany has purchased credits from 27 Joint Implementation (JI)
projects and hosted 11 JI projects, three of which are CMM projects including the Methane Capture,
Power and Heat Generation from Coal Mine Gas in the Concession HER-TEUTO and Methane
Capture, Power and Heat Generation from Coal Mine Gas in the Concession HER-Wan-Thai in North
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Rhineland and Mine gas flaring at shaft Nordschacht in Saarland. Table 14-6 shows the breakdown
by project type and domestic versus non-domestic project hosting.
Table 14-6. Germany's CDM and Jl Activity
Project Types
CDM
Projects
JI Projects
(non-domestic)
JI Projects
(domestic)
Biomass Energy
26
3
Cement
1
Coal Mine Methane
2
3
Energy Efficiency
17
6
Energy Distribution
2
2
Fossil Fuel Switching
2
1
Geothermal
1
HFCs
1
Hydro
70
Landfill Gas
17
1
Methane Avoidance (Waste Water,
Composting]
20
Nitric Acid Destruction
4
8
8
Solar
12
6
Wind
32
Source: UNEP (2014a]; UNEP (2014b]
14.3.1 Market and Infrastructure Factors
The GHG emissions targets set by the EU as well as the 2011 decision by the German government to
phase out nuclear power present an improved market for new energy streams in Germany
particularly from renewable sources. The Renewable Energy Sources Act of 2004 (EEG) established
CMM and AMM as renewable energy sources in Germany (Langefield and Agasty, 2013;
Schloenbach and Schluter, 2005).
Potential CMM end uses in Germany include both mono- and co-firing boiler systems, combined
heat power generation from gas and diesel engines and gas turbines, and secondary fuel sources
including methanol, liquid gas, and substitution of natural gas. A 110-km long CMM network in the
Saar District currently supplies CMM to a steel plant, the local chemical industry, a coking plant,
electrical power plants, and central heating installations (Dinkelbach and Mader, 2003).
14.3.2 Regulatory Information
The legal framework for the economic utilization of mine gas in Germany is set by the Federal Law
on Mining and the EEG. Exploration, extraction, and processing of mine gas are administered by the
Federal Mining Authority. CMM ownership rights are transferred to a coal mining company for the
duration of a coal mining license, after which the capture and utilization of CMM requires a gas
license for the subsequent 30-year period (USEPA, 2011). The Federal Mining Authority considers
an application for license after the applicant has submitted a utilization program which clearly
demonstrates that "planned activities are sufficient and within an acceptable time frame for the
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type, scope and purpose of the methane extraction." A license can be refused or withdrawn if found
to be inadequate with respect to legislatively fixed factors, including the availability of sufficient
funds, feasibility of a proposed extraction technology within a given timeframe and public interests
(World Bank, 2007).
According to the guidelines defined in the EEG, CMM is a renewable energy source from which
electrical power production is supported by federal legislation (Schloenbach and Schluter, 2005).
Germany's primary policy incentive for CMM recovery and use projects is through a feed-in tariff
for CMM used to generate power under the Renewable Energy Sources Act of 2004 (RESA). The
RESA requires electric grid system operators to connect plants generating electricity from mine gas
to their systems, bear the costs of the grid upgrade, and guarantee priority purchase and
transmission of all electricity from such plants. RESA provides a guaranteed fixed payback tariff for
20 years through feed-in tariffs or fees paid for electricity produced from mine gas (USEPA, 2011;
IEA, 2009).
CMM operators have the authority to sell the carbon credits generated by the project and have the
added incentive of paying no local taxes or royalties on CMM projects. Taxes for gas extraction are
waived in Germany as long as gas is removed for safety reasons (Backhaus, 2013). Since CMM is
included in the RESA category, all CMM projects receive priority attention at all stages of the project
development (IEA, 2009).
14.4 Profiles of Individual Mines
There are three main hard coal fields in Germany, the Ruhr, Ibbenburen, and Saar; however, mines
are only operating in the Ruhr and Ibbenburen Coalfield as listed in Table 14-7. There are four
brown coal districts.
Table 14-7. Germany's Mine Overview
Coalfield/District
Mine
Ruhr Coalfield (Hard]
¦ August Victoria
¦ Prosper-Haniel
Ibbenburen Coalfield (Hard]
¦ Ibbenburen
Rheinland District (Brown]
¦ Garzweiler
¦ Hambach
¦ Inden
Helmstedt District (Brown]
¦ Schoningen
¦ Restkohle Werkstatten
Lausitz District (Brown]
¦ Cottbus-Nord
¦ Janschwalde
¦ Welzow-Sud
¦ Nochten
¦ Reichwalde
Mitteldeutschland District (Brown]
¦ Profen
¦ Profen gesamt
¦ Schleenhain
¦ Amsdorf
Source: Statistik der Kohlenwirtschaft e.V. (2014a]; Statistik der
Kohlenwirtschaft e.V. (2014b]
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14.5 References
Backhaus (2013): Renewables and coal mine methane in German Legislation Recommendations for Ukraine,
Clemens Backhaus, presented at GMI Seminar: Coal Mine Methane Recovery and Utilization Moving
Forward, Kyiv, Ukraine, 10 December 2013.
https://www.glohalmethane.org/documents/Backhaus CMM-Utilisation Germany eng.pdf
Dinkelbach and Mader (2003): Capture and Use of Methane from Operating and Abandoned Mines in
Germany, Lutger Dinkelbach and Roland Mader, presented at the 3rd International Methane & Nitrous
Oxide Mitigation Conference, Beijing, China, 17-21 November 2003.
http://www.coalinfo.net.cn/coalbed/meeting/2203/papers/coal-mining/CM007.pdf
EIA (2014a): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed April 2014. http: //www.eia.gov/cfapps /ipdhproiect/IEDIndex3.cfm
EIA (2014b): Germany Country Analysis Note, U.S. Energy Information Administration, Washington, DC, April
2014. http://www.eia.gov/countries/country-data.cfm?fips=GM&trk=m
Euracoal (2013): Euracoal Market Report 2/2013, European Association for Coal and Lignite, September
2013.
http://www.euracoal.com/componenten/download.php?filedata=1381742827.pdf&filename=EURACOA
L%20Market%20Report%202-2013.pdf&mimetype=application/pdf
Euracoal (2014): Euracoal Market Report 1/2014, European Association for Coal and Lignite, May 2014.
http://www.euracoal.be/componenten/download.php?filedata=1401266763.pdf&filename=Euracoal%2
0Market%20Report%201-14.pdf&mimetype=application/pdf
EC (2013a): Europe 2020 in Germany, European Commission, 2013.
http: / / ec.europa.eu/europe2 02 0 / europe-2 02 O-in-your-country / deutschland/progress-towards-2 020-
tar gets/index en.htm
EC (2013b): Europe 2020 Targets: climate change and energy, European Commission, 2013.
http://ec.europa.eu/europe2020/pdf/themes/16 energy and ghg.pdf
FUMINCO GmbH (2014): CBM Miinsterland, FUMINCO GmbH, 2014.
http://www.fuminco.com/index.php?option=com content&view=article&id=86&Itemid=114&lang=en
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
IEA (2009): Coal Mine Methane in Russia, International Energy Agency, Paris, France, 2009.
http://www.iea.org/publications/freepublications/publication/name-3872-en.html
Langefeld and Agasty (2013): Production of Coal Bed Methane in Germany, Oliver Langefeld and Amit Agasty,
presented at the 3rd Sino-German Conference "Underground Storage of CO2 and Energy," Goslar,
Germany, 21-23 May 2013.
Morris (2014): A bad bank for German hard coal, Craig Morris, Energy Transition (Energiewende) Blog, 28
February 2014. http://energytransition.de/2014/02/bad-bank-for-german-coal/
Mosle et al (2009): Coal Bed Methane Production in the Miinsterland Basin, Germany - Past and the Future, B.
Mosle, P. Kukla, H. Stollhofe, and A. PreufSe (3) Geophysical Research Abstract, 2009.
http://meetingorgani7er.copernicus.org/EGU2009/EGU2009-4267.pdf
Schloenbach and Schluter (2005): Gob Gas Drainage, Schloenbach, M. and R. Schluter, presented at the 2005
International Workshop on CMM/VAM Recovery and Utilization, Chengu, Sichuan Province, China, 6-7
April 2005.
Statistik der Kohlenwirtschaft e.V. (2013): Coal Mining and Energy in the Federal Republic of Germany
(German), November 2013. http://www.kohlenstatistik.de/files/silherhuch 2012.pdf
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Statistik der Kohlenwirtschaft e.V. (2014a): Hard Coal Statistics (German), Statistik der Kohlenwirtschaft e.V.,
April 2014. http: //www.kohlenstatistik.de/18-0-Steinkohle.html
Statistik der Kohlenwirtschaft e.V. (2014b): Brown Coal Statistics (German), Statistik der Kohlenwirtschaft
e.V., March 2014. http: //www.kohlenstatistik.de/19-0-Braunkohle.html
UNEP (2014a): CDM Pipeline Spreadsheet, United Nations Environment Programme Risoe Centre, 1 April
2014. http://cdmpipeline.org/
UNEP (2014b): JI Pipeline Spreadsheet, United Nations Environment Programme Risoe Centre, 1 April 2014.
http:// cdmpipeline.org/
UNFCCC (2014a): Germany National Inventory Submission, Annex I Party GHG Inventory Submissions, United
Nations Framework Convention on Climate Change, 15 April 2014.
http: / /unfccc.int/national reports /annex i ghg inventories/national inventories submissions/items/81
08.php
UNFCCC (2014b): Ratification Status - Germany, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=DE
USEPA (2011): Financial and Regulatory Incentives for U.S. Coal Mine Methane Recovery Projects, U.S.
Environmental Protection Agency, August 2011. http: IIwww.epa.gov/cmop /docs /cmm-financial-
regulatory-incentives.pdf
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
Wagstyl (2014): German coal use at highest level since 1990, Stefan Wagstyl, Financial Times (online), 7
January 2014. http://www.ft.com/intl/cms/s/0/e6470600-77bf-lle3-807e-
00144feabdc0.html#axzz36oWR0ull
World Bank (2007): A Strategy for Coalbed Methane (CBM) and Coal Mine Methane (CMM) Development and
Utilization in China, Energy Sector Management Assistance Program, Formal Report 326/07, World Bank,
Washington, DC, 2007.
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15 Hungary
15.1 Summary of Coal Industry
15.1.1 Role of Coal in Hungary
Hungary uses three categories to classify its coal - hard coal (bituminous), brown coal, and lignite.
Brown coal and lignite account for approximately 80 percent of the country's total coal reserves,
making these the most significant indigenous energy sources (Euracoal, 2014)--used mainly in its
thermal electric power plants. These plants cannot use higher quality coal and therefore, rely on the
supplies of lower-quality domestic coal.
Hungarians are making efforts to convert from coal to cleaner burning fuels such as natural gas or
oil. Overall production of lignite (including brown coal) declined nearly 29 percent from 2002 to
2012 (EIA, 2014). Brown coal production declined more sharply and bituminous production has
ceased due to declining reserves (Steblez, 2005). Table 15-1 summarizes Hungary's coal reserves
and recent production.
Table 15-1. Hungary's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million
tonnes)
Sub-
bituminous &
Lignite
(million tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
13.0
1,647.0
1,660.0
23 (0.19%]
(2011]
Annual Coal Production (2012]
0
9.29
9.29
27 (0.12%]
Source: EIA (2014]
Hungary's principal bituminous coal basin is the Mecsek Basin in the Mecsek Mountains of Baranya
Province (Figure 15-1). Other coalfields include the sub-bituminous/lignite coalfields of Ajka,
Borsad, Matra, Nograd, Oroszlany, Tatabanya, and Varpolata.
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Figure 15-1. Hungary's Coal Basin Fields
Lignite Hard coal
Source: Euracoal (2014)
15.1.2 Stakeholders
As indicated in Table 15-2, Magyar Olaj es Gaz (MOL), the state oil and gas monopoly, is a
prospective stakeholder in the development of Hungary's coal mine methane (CMM) industry.
Table 15-2. Key Stakeholders in Hungary's CMM Industry
Stakeholder Category
Stakeholder
Role
Natural Gas Transmission &
¦ Magyar Olaj es Gaz (MOL)
Pipeline sales
Distribution Companies
Energy Companies/Power
¦ MVM Group (Magyar Villamos Muvek Zrt.)
CMM project identification
Generators
¦ MATRA (Matrai Eromu Zrt.)
and investment
¦ See
Project opportunity
Developers
httD://www.epa.ffov/coalbed/networkcontacts.html
identification and planning
Engineering, Consultancy,
¦ See
Technical assistance
and Related Services
http://www.epa.sov/coalbed/networkcontacts.html
Government Groups
¦ Energy Centre Hungary
Development of energy
¦ Ministry for National Economy
policy, project
¦ Ministry for Environment and Water
implementation, regulatory
¦ Hungarian Energy and Public Utility Regulatory
Authority
¦ Hungarian Office for Mining and Geology
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15.1.3 Status of Coal and the Coal Mining Industry
The coal mining industry in Hungary is privatized. No information was found quantifying the
proportion of underground mines considered gassy.
15.2 Overview of CMM Emissions, Projects, and Potential
There are significant recoverable gas reserves from coal beds in Hungary (see Table 15-3).
Table 15-3. Hungary's Largest Recoverable CMM/CBM Resources
Location
Amount
(million cubic
meters)
Algyo
12,700
Hajduszoboszlo
1,500
Pusztafoldvar
1,700
Ulles
2,800
Szank
700
Szeghalom
800
Nagykoru
2,600
Mezosas
3,300
Kisujszallas
800
Lovaszi
200
Total
27,100
Source: Foldessy (2006]
15.2.1 CMM Emissions from Operating Mines
Methane emissions in Hungary totaled 21.7 million cubic meters (m3) in 2000, but are projected to
decrease significantly to 1.4 million m3 by 2015, and then remain stable through 2030 (see Table
15-4).
Table 15-4. Hungary's CMM Emissions (million cubic meters)
2015
(projected)
Emissions
2000
2005
2010
Total CH4 Emitted 21.7 1.4 1.4 1.4
Source: USEPA(2012)
15.2.2 CMM Emissions from Abandoned Coal Mines
No information on methane emissions from abandoned mines in Hungary was found.
15.2.3 CBM from Virgin Coal Seams
Overall coalbed methane (CBM) resources in the country are estimated at 152-159 billion m3, of
which 142 billion m3 are in the Mecsek Coal Basin. The Mecsek region is thus the target area for
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CBM development. The potential of CBM was examined in Hungary in 2006 (Molnar, nd). Various
factors such as coal rank, gas content, natural fracturing history of gas emissions, proximity to
guaranteed markets, and the relative dryness of coal and deep mines identify the Mecsek basin as a
site for potential CBM development (Schwochow, 1997).The gas in the seams is approximately 95
percent pure, 70-90 percent of which is solid solution and sorbed, and contains 0.8 percent carbon
dioxide (Foldessy, 2006).
Four drillhole tests were done between 1994 and 1995, all of which experienced fracturing by fluid
carbon dioxide and failed. New projects, proposed by the University of Miskolc, would use steam
gas extraction through medium radius drilling to access methane stores.
15.3 Opportunities and Challenges to Greater CMM Recovery
and Use
As expressed in Table 15-5, Hungary ratified both the UNFCCC and the Kyoto Protocol, under which
it has committed to a reduction of 6 percent of emissions from the base period 1985-1987
(UNFCCC, 2005). Hungary is an Annex 1 country and is eligible to host Joint Implementation (JI)
projects. While there are several landfill-related and forest biomass JI projects in Hungary, there are
none related to coalbed/mine methane (UNEP, 2014).
Table 15-5. Hungary's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 13,1992
February 24,1994
Kyoto Protocol
—
August 21,2000
Source: UNFCCC (2014]
Hungary's Climate Change Act 2007—based on UNFCCC implementation and its Kyoto Protocol—
created a framework for building the country's ability to adapt to climate change. The Act
prescribed the preparation of a national climate change strategy for Hungary and in 2008, a
National Climate Change Strategy (NCCS) was accepted by the Parliament (EU, nd). The NCCS
contained chapters on both climate change mitigation and adaptation, and identified key objectives
and actions to be implemented for 2008-2025. The Act also required the Hungarian Government
adopt National Climate Change Programmes (NCCPs) every two years. The first NCCP was approved
for 2009 and reviewed in 2011.
The first revision of the NCCS (the "Strategy") mandated by the Climate Change Act 2007 was
anticipated to take place before the end of 2013. The revised version would extend the strategy's
timeframe to 2030, with a 2050 outlook (EU, nd). As part of the revised NCCS, Hungaiy also intends
to prepare a national adaptation strategic framework. At the time of publication, current status of
the revised strategy was unknown.
15.3.1 Market and Infrastructure Factors
In the 1990s, the Hungarian government privatized the coal industry, dividing the existing coal
mines into supposedly profitable and unprofitable groups. The profitable ones were contracted to
power plants and have been supported by government subsidies to varying degrees in the form of
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price guarantees, subsidies for fuel switching, and government responsibility for most existing
liabilities. The introduction of EU regulations and requirements has not changed the landscape for
these factors significantly, so continued support for standard fuel sources and systems will likely
continue to impede investment in alternatives like CMM (Perger, 2009).
15.3.2 Regulatory Information
No regulatory information regarding development or sales of CMM in Hungary was found.
15.4 Profiles of Individual Mines
Markushegyi Banyauzem, Oroszlany Coal Basin, Oroszlany
General Information
Depth of shafts
250 m
Mining capacity
4,167 tonnes/day
General Geologic Information
Coal seam gas content range
2-3 m3/tonne
Faults
Yes
Total methane resource
0.3-0.5 billion m3 (coal seams]
Geologic and Mining Conditions
Rank of coal
Sub-bituminous
Depth of mining
250 m
Ash content
Coal in place, run of mine - 30.8 percent
Sulfur content
3.3 percent
Gas content
2-3 m3/tonne coal
Mining method
Longwall
Roof control method
Caving
Source: Molnar (nd]
15.5 References
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http: IIwww.eia.gov/cfapps /ipdbproi ect/1ED Index3.cfm
Euracoal (2014): Country Profile - Hungary, European Association for Coal and Lignite, website accessed
September 2014. http://www.euracoal.be/pages/layoutlsp.php?idpage=74
EU (nd): European Climate Adaptation Platform - Hungary, European Union/European Environment Agency,
web page not dated, http://climate-adapt.eea.europa.eu/countries/hungarv
Foldessy (2006): "Coalbed methane and CO2 sequestration potential of the Mecsek Mts. Coalfields, S-
Hungary," Janos Foldessy, University of Miskolc, Hungary, Institute of Mineralogy and Geography, 2006.
http://foldl.ftt.uni-miskolc.hu/pdf/060330.pdf
Molnar (nd): Mr. Laszlo Molnar of Energy Centre Hungary, not dated.
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Perger (2009): The Role of Coal in the Hungarian Electricity Sector with Special Attention to the Use of
Lignite, Perger, Andras, Energia Klub, November 2009.
http://www.energiaklub.hu/dl /kiadvanvok/lignite hungarv.pdf
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
Steblez (2005): Steblez, Walter G., "The Mineral Industries of Central Europe (Czech Republic, Hungary,
Poland, and Slovakia)," U.S. Geological Survey Minerals Yearbook - 2005.
UNEP (2014): CDM/JI Pipeline Analysis and Database, United Nations Environment Programme Danish
Technical University Partnership, accessed July 2014. http: IIcdmpipeline.org/index.htm
UNFCCC (2005): Annex I Party GHG Inventory Submissions 2005, United Nations Framework Convention on
Climate Change, 2005.
http: / /unfccc.int/national reports /annex i ghg inventories/national inventories submissions/items/2 7
61.php
UNFCCC (2014): Ratification Status - Hungary, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/countrv.pl?countrv=HU
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990 - 2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
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16 India
16.1 Summary of Coal Industry
16.1.1 Role of Coal in India
In 2011, coal represented 41 percent of India's total primary energy supply (EIA, 2013a). The
International Energy Agency (IEA) reported that in 2011, 71 percent of the coal produced and
imported was used for electric power generation (IEA, 2014). About 57 percent of the installed
power capacity, as of 2011, is generated from coal-fired plants. Steel, cement, fertilizer, chemical,
paper, and industrial plants are also major coal users, while coal has largely been phased out from
the rail transport sector. India's total primary coal production was 589 million tonnes (Mmt) in
2012. Even with high domestic production, India imported 12.7 percent (86 Mmt) of its total
primary coal consumption of 675 Mmt (EIA, 2013b). According to the Ministiy of Coal's (MOC)
2012 projections, coking coal would represent one-third of the total imports.
The Geological Survey of India estimates the countiy to possess 293 billion tonnes of total coal
resources (MOC, 2012). Of this total resource, BP estimates proved recoverable reserves of 66.8
billion tonnes (BP, 2012). Table 16-1 provides statistics on India's coal reserves and production.
Table 16-1. India's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous &
Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
61,840
4,960
66,800
5 (7.0%]
(2011]
Annual Coal Production (2012]
545.8
43.4
589.3
3 (7.47%]
Source: EIA (2013b]
India's coal demand has grown by more than 7 percent per year over the past decade and
production shortfalls have driven the increase of imported coal by more than 13 percent per year
since 2001 (EIA, 2013a). Despite this increased consumption, the expanding demand for power has
reduced the fraction of energy consumption provided by coal from approximately 68 percent in
2002, to 41 percentin 2011 (EIA, 2013a).
The coal-bearing formations of India occur in two geological horizons, the Lower Gondwana
(Permian) and the Tertiary sediments (Eocene-Oligocene) of northeastern India, Rajasthan, Gujarat,
Jammu, and Kashmir (Chand, 2001). Coal resources are found in 17 major coalfields in India (GSI,
2010). Reserves in these coal fields are provided in Table 16-2. Figure 16-1 shows the location of
major coal deposits in India.
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Table 16-2. Coal Distribution in India's Major Coalfields (million tonnes)
State Coal Field Resource Proved Reserves
Orissa
Talcher
43858.76
14240.08
West Bengal
Raniganj
23730.81
11638.27
Orissa
lb-river
22448.49
7266.58
Jharkhand
Jharia
19430.06
15077.57
Chattisgarh
Mand-raigarh
22177.64
3880.67
Andhra Pradesh
Godavari Valley
22016.24
9256.51
Jharkhand
N. Karanpura
17073.24
9499.42
Jharkhand
Raj ma ha 1
14338.00
2655.52
Madhya Pradesh
Singrauli
12416.51
4795.00
Chattisgarh
Korba
11704.83
4980.58
Jharkhand
E. Bokaro
8083.29
3351.87
Jharkhand
S. Karanpura
6150.11
2620.41
Maharashtra
Wardha Valley
6044.24
3297.19
Jharkhand
W. Bokaro
5012.49
3629.03
Chattisgarh
Hasdo-arand
4993.70
1369.84
West Bengal
Birbhum
5992.76
0
Madhya Pradesh
Sohagpur
6128.74
1643.20
Note: Where coalfields overlap state borders, the state with the dominant share of resources is shown.
Source: GSI (2010]
Hard coals (anthracite and bituminous) account for approximately 92 percent of the country's
proved reserves (EIA, 2013b). The principal deposits of hard coal are in the eastern half of the
country ranging from Andhra Pradesh, bordering the Indian Ocean, to Arunachal Pradesh in the
extreme northeast. The States of Jharkhand, Orissa, West Bengal, and Chattisgarh, together account
for about 70 percent of reserves (EIA, 2014). The Damodar Valley basins include the significant
Jharia and Raniganj coalfields in the east and the Bokaro, Ramgarh, and North and South Karanpura
fields in the west.
The high-rank coal seams in deeper coalfields represent a significant target for coal mine methane
(CMM) and coal bed methane (CBM) development. In some of the coalfields of the Damodar Valley,
there can be up to 25 coal seams, and even in excess of 40 in some areas, with a cumulative
thickness of over 100 meters (M2M Profile - India, 2005).
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Figure 16-1. India's Coal Fields
JAMMU & KASHMIR
HARYANA
ASSAM
UTTAR PRADESH
RAJASTHAN
BIHAR
-WEST \
BENGAL !
^Calcutta
MADHYA PRADESH
GUJARAT
Haldia
Paradip
ORISSA
MAHARASHTRA
iBombay
Hyderabad
ANDHRA
PRADESH
KARNATAKA
'Madras
Neyveli
(lignite)
TAMIL
i NADU
HIMACHAL
"Vf"
<' \ PRADESH ..
/PUNJAB V J
j— r /
©
®
0
©
©
©
©
Major Coalfields
Raniganj
Jharia
East Bokaro and West Bokaro
Singrauli
Pench-Kanhan. Tawa Valley
Talcher
Chanda-Wardha
Godavari Valley
500km
_J
Source: Walker (2000]
16.1.2 Stakeholders
Table 16-3 identifies potential stakeholders in Indian CMM development
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Table 16-3. Key Stakeholders in India's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies
¦ Coal India, Ltd. (CIL] and its eight regional subsidiaries
¦ Project hosts
¦ Electrosteel Casting Ltd
Engineering, Consultancy
¦ See http://www.epa.gov/coalbed/networkcontacts.html
¦ Technical
and Related Services
assistance
Developers
¦ Reliance Industries
¦ Project developers
¦ Deep Industries
¦ Great Eastern Energy
¦ Reliance ADA
¦ Essar Oil Ltd.
¦ Oil and Natural Gas Corporation (ONGC]
Universities, Research
¦ Central Institute of Mining and Fuel Research
¦ Technical
Establishments
¦ Central Mine Planning and Design Institute
assistance
¦ Indian School of Mines
¦ IIT Madras
Government Groups
¦ Ministiy of Petroleum and Natural Gas (For CBM only]
¦ Oversight of
¦ Directorate General of Hydrocarbons
resources.
¦ Ministiy of Coal (For CBM/CMM]
licensing
16.1.3 Status of Coal and the Coal Mining Industry
In 2000, 27 percent of coal production in India came from underground mines and by 2012 that
number was estimated to decline to fewer than 10 percent (MOC, 2012). Deep mines continue to be
developed, but more surface mines are also being developed due to the country's vast resource of
shallow, low-rank coal deposits. Table 16-4 summarizes the available statistics on coal production
by mine type.
Table 16-4. India's Hard Coal Production by Mine Type
Type of mine
Production
(million tonnes)
Number of mines
(as of 31 March 2008)
Underground (active] mines
51.832
337
Surface (active] mines
488.108
186
Mixed
-
36
Total Active Mines
539.94
559
Source: MOC (2012]
There is a 3-tier classification system for underground mines in India based on the amount of
methane emissions, as shown in Table 16-5.
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Table 16-5. India's Classification System and Estimates of Mine Gassiness
Class
Specific Emissions
(volume of flammable gas/
tonne of coal produced)
Number of Mines
(as of 2007)
Degree I
>0.01 and < 1 m3
222
Degree II
> 1 and < 10 m3
102
Degree III
> 10 m3
18
Source: M2M (2008]
India's coal production faces multiple challenges, including low productivity, distribution problems,
and an increased loss of domestic market share to higher-quality, less-expensive imports. India's
government embarked on a series of economic reforms in the 1990s, including relaxation of
restrictions on foreign ownership and privatization of some industrial enterprises. In 2004, some of
these economic reforms were curtailed and continued at a slower pace. In April 2004, 470 of India's
576 mines were under the control of Coal India, Ltd. (CIL), a state-owned entity. Private mines, or
investments in mines owned by Indian companies, are allowed only if "captive" to a power plant ol-
factory (MOC, 2004); that is, the captive coal is used for power generation, steel, or cement. Private
companies were allocated 60 blocks for exploration and mining in 2006-2007. Further coal-sector
liberalization has been attempted, in the form of the Coal Mines Nationalisation Amendment Bill,
introduced in 2000, but under pressure from labor unions the bill has stalled and is still under
consideration a decade later (MOC, 2010b).
At the end of 2009, a total of 208 coal blocks with reserves of 49 billion tonnes had been allocated
for exploration and mining to eligible companies. The government is in the process of amending the
Mines and Mineral (Development and Regulation) Act of 1957 to introduce an auction system of
competitive bidding on future allocations of coal blocks. This is intended to be a more transparent
system of awarding a decreasing number of available coal blocks to an increasing number of
applicant companies (MOC, 2010a).
16.2 Overview of CMM Emissions and Development
Potential
India's carbon emissions increased by 61 percent between 1990 and 2001, a rate surpassed only by
China. In 2005, annual emissions were 1,181.4 tonnes carbon dioxide equivalent (mtC02e) and as of
2011, emissions had risen to 1,725.8 mtC02e (EIA, 2013b). Large increases in emissions from the
electricity, cement and waste sectors, along with rises in the transport and residential sectors, have
made India the world's fifth largest emitter after China, the U.S., Europe and Russia. More than a
third of India's emissions come from low efficiency coal fired power plants. High capital costs for
replacing existing plants, a scarcity of capital, and the long lead time required to introduce
advanced coal technologies point to the likelihood that most of India's highly polluting coal-fired
power plants will remain in operation for the next couple of decades (EIA, 2004b). In 2010,
methane emissions from coal mining were calculated at 18.88 mtC02e (USEPA, 2012).
16.2.1 CMM Emissions from Operating Mines
Table 16-6 summarizes India's CMM emissions.
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Table 16-6. India's CMM Emissions (million cubic meters)
Emission Source
2000
2005
2010
2015
(projected)
CMM emissions
(no utilization]*
1,007
1,077
1,275
1,397
*Actual emissions reductions are unknown.
Source: USEPA (2012]
While there is some drainage of CMM, there are currently no commercial projects for its recovery or
use in India. A USD 14.9 million project of the United Nations Development Programme (UNDP), the
Global Environmental Facility (GEF), and the Indian Ministry of Coal called "Coalbed Methane
Recovery & Commercial Utilisation" demonstrated the feasibility of utilizing methane gas recovered
before, during and after coal extraction. The lack of commercial CMM projects in India is in part due
to the lack of a legal or regulatory framework governing CMM production. Although the Ministry of
Coal and the Ministry of Petroleum have been discussing a comprehensive CMM policy in recent
years, a resolution to the issue does not appear imminent.
In 2008, the U.S. EPA and the U.S. Trade and Development Association assisted in the establishment
of the CMM/CBM Clearinghouse located at the Central Mine Planning and Design Institute's
(CMPDI) campus in Ranchi (www.cmmclearinghouse.cmpdi.co.in). The Clearinghouse seeks to
promote the deployment of CMM recovery and end-use technologies in India to reduce methane
emissions.
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies 21
potential CMM recovery projects in India. However, the majority of these are at the "initial idea"
stage and most of them have since been dropped due to the inability to receive a concession to
develop the project Through GMI, U.S. EPA awarded a grant to the Central Institute of Mining and
Fuel Research to conduct a feasibility study on CMM recovery and utilization in the Jharia, Bokaro,
and Raniganj coalfields. The project provided data on CMM/VAM/AMM emissions in key gassy coal
regions of India. VAM data was collected from 10 working mines. More recently, EPA's CM0P
program funded a pre-feasibility study for pre-mine drainage at the Sawang Mine located in the
Bokaro coalfield. The study will examine the economics of utilizing long in-seam boreholes to drain
gas from the deeper, un-mined portions of the mine.
16.2.2 CMM Emissions from Abandoned Coal Mines
About 5 percent of abandoned mines in India are considered gassy, assuming the same percentage
as active mines reported in the First National Communication to the United Nations Framework
Convention on Climate Change (UNFCCC). No additional information is available on abandoned
mine methane (AMM) in India at this time, although several studies are proposed to gain more
information on AMM emissions volumes in India's major coalfields (GMI Projects Database, 2010).
16.2.3 CBM from Virgin Coal Seams
Estimates of India's CBM potential vary. The Directorate General of Hydrocarbons estimates that
deposits in 44 major coal and lignite fields in 12 states of India, covering an area of 35,330 km2,
contain 3.4 trillion cubic meters (m3) of CBM depending on the rank of the coal, depth of burial, and
geotectonic settings of the basins as estimated by CMPDI.
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In the Jharia Coalfield, the gas content is estimated to be between 7.3 and 23.8 m3 per tonne of coal
within the depth range of 150 to 1200 m. Analysis indicates every 100-m increase in depth is
generally associated with a 1.3 m3 increase of methane content (M2M Profile - India, 2005).
In 1997, the government formed a CBM policy that established the Ministry of Petroleum and
Natural Gas as the CBM administrative agency and offered several incentives (see section 16.3.1).
In May 2001, the Indian government for the first time offered blocks for exploration and production
of CBM through an international bidding process. Reliance Industries, Essar Oil Ltd., and Oil and
Natural Gas Corporation (ONGC) won the bids for the blocks. The government launched a second
round of bidding on nine CBM blocks in May 2003, and eight blocks were awarded to Reliance and
ONGC. The Directorate General of Hydrocarbons offered an additional 10 CBM blocks during a third
round of open international competitive bidding that closed in June 2006. Contracts for this third
round of bidding were signed in November 2006. These 26 prospective CBM blocks in the first
three rounds of bidding cover an area of around 13,590 km2 and are estimated to contain 1.45
trillion m3 of CBM resources (Table 16-7). Expected total production from these blocks is estimated
at 39.7 million m3 per day attheir peak production level (DGH, 2010).
More than 200 exploratory (test) and nearly 300 production wells have been drilled in the awarded
blocks. Commercial production began in the Raniganj (South) CBM block in July 2007, followed by
commercial production from the Raniganj East Block. Current gas production from these three
blocks is 0.6 million m3 per day and by 2015 production is projected to increase to 1.0 million m3
per day. The fourth round of bidding on 10 new CBM blocks took place in the fall of 2009. The
blocks cover an area of approximately 5000 km2 and are spread over seven states. During the
fourth round of bidding 26 bids were received for eight of the blocks on offer while 2 of the blocks
located in the Wardha Coalfield of Maharashtra received no bids. Essar Oil Limited, Arrow Energy
and Great Eastern Energy Corporation Ltd. were the successful bidders (DGH, 2010).
Table 16-7. CBM Project Blocks Offered for Lease
Bidding Round
for CBM Blocks
Blocks
Offered
Area
(km2)
CBM
Resource
(Bern)
Expected
Production
(MMcmd)
First
5
1,930
235
9
Nomination Basis
3
643
163
5
Second
8
5,234
427
10.5
Third
10
5,784
624
15.2
Fourth
10
5,000
NA
NA
Total
36
18,591
1,449+
39.7+
Source: DGH (2010]
Table 16-8 contains a list of some of the CBM activity by private companies currently taking place in
India.
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Table 16-8. CBM Projects Proposed or in Development
Company
Coalfield
Status
Notes
Great Eastern Energy
Corporation Ltd (GEECL]
Reliance Industries
Essar Oil Ltd.
Oil & Natural Gas Corp.
(ONGC]
BP, Deep Industries Arrow,
Geopetrol and more
Raniganj Approx. 100 wells on line and selling
about 0.3 MMcmd
Mannargudi Block awarded to GEECL in 4th bidding
Block round.
Sohagpur In development phase. Approx. 30
exploratory wells drilled. Plan to
commercialize the field starting 2015
Raniganj 150 CBM production wells drilled -
CBM production currently 0/2 MMcmd
Parbatpur, 8 exploratory wells drilled. Currently
Jharkhand producing 15,000 cubic meters of CBM
gas, but ONGC is looking to expand.
Various stages of CBM exploration
GIP estimated at 56.6
billion m3 (Bern]
Estimated GIP is 28 Bern
USTDA grant for technical
assistance on commercial
development of CBM
Project scope is 500 wells.
GIP is estimated to be 130
Bern with recoverable
reserves of 28 Bern
Holds 5 CBM blocks in
Jharkhand and 1 in
Raniganj - all in
exploration stage
Source: M2M Expo (2010]
16.3 Opportunities and Challenges to Greater CMM Recovery
and Use
India is a non-Annex 1 country under the UNFCCC and it is not obligated to reduce carbon and
greenhouse gas (GHG) emissions. In 2012, its second national communication provided emissions
estimates for 2000. The emissions are projected to continue to grow as the economy expands (EIA,
2004a). India accepted the Kyoto Protocol in 2002 (see Table 16-9). As a non-Annex 1 party, India
is eligible to receive financing for GHG mitigation projects such as CMM projects under the Clean
Development Mechanism. However, note that the Kyoto Protocol expired in 2012 and there is
currently no follow-on agreement
Table 16-9. India's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 10,1992
November 1,1993
Kyoto Protocol
—
August 26,2002 (Acceptance]
Sources: UNFCCC (2014]
16.3.1 Market and Infrastructure Factors
Gas demand is rising sharply in India, with consumption rising from 36 Bern in 2005 to 58 Bern in
2012 (EIA, 2013b). Gas production rates (29.9 Bern to 41.3 Bern over the same time frame) are
increasingly lagging consumption rates and the shortfall is made up with imported natural gas and
liquefied natural gas (LNG). 12.6 Bern of natural gas (dry) and 12.3 Bern of LNG were imported in
2009. In 2011, India became the world's sixth largest LNG importer, with 5.3 percent of global
A
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imports (EIA, 2013a; PFC Energy, 2012). No data is currently available for LNG imports as of 2012,
but dry gas imports increased to 16.9 Bern. Gas consumption has grown at an approximate annual
rate of 10 percent from 2001-2011 and the Indian Oil and Natural Gas Ministry projects
consumption to more than double over the next 5 years (EIA, 2013b).
Current prices for imported coal, gas and LNG make CMM and CBM an economically attractive
alternative energy source, provided the pipeline infrastructure is developed (Dube, 2010).
Investments in coal and gas transportation infrastructure, including gas gathering transportation
and distribution, are necessary to move CMM and CBM from coal fields to local and more distant
end-use markets. One such project is in development by GAIL (India) Limited, India's principal gas
transmission and marketing company, which is building a natural gas pipeline in north-east India
running through many of the major coal regions. End-use markets for CMM/CBM include rural
power generation, commercial power generation, and transportation fuels.
Limitations in cost and investment capital, however, remain significant barriers to technology
development, application, and CMM and CBM project development in India.
The following actions were identified as necessary in order to fully develop India's CBM/CMM
potential (M2M Workshop - India, 2005), and these are the areas thatthe CMM Clearinghouse
addresses:
¦ Delineation of prospective CBM/CMM blocks,
¦ Development of coal field-specific databases,
¦ Provision of technical and other training
¦ Promotion of CBM/CMM research and development,
¦ Transfer of CBM/CMM development technologies,
¦ Provision of substantive measures to encourage CBM/CMM development entrepreneurs
and maintain constant interaction with and among CBM/CMM developers, and
¦ Establishment of a clear policy regarding CMM development
16.3.2 Regulatory Information
A memorandum of understanding between the Ministry of Coal and Ministry of Petroleum &
Natural Gas governs the procedures for allotment of blocks for CBM exploration and exploitation.
CBM blocks are allocated after mutual consultations between the two ministries (Prasad, 2006).
The Ministry of Coal oversees coal resources while the Ministry of Petroleum and Natural Gas
oversees CBM resources.
India's heavy reliance on coal, much of it low-quality, is a major cause of the country's relatively
high carbon intensity level. However, environmental standards for limiting gas emissions from
surface or underground coal mining operations, as well as emissions from coal and gas combustion,
are largely lacking. Current guidelines governing CMM emissions apply only to methane
concentrations, and not on volume released. Other issues affecting CMM/CBM drainage and use
include clarifying gas ownership, expediting private participation and possible government
mandates for pre-mining degasification (Dube, 2010). A regulatory framework for CMM is under
formation by the Government of India (M2M, 2008).
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India has offered several incentives to attract foreign investment for CBM development. The Indian
government formed a CBM policy in 1997 that established the Ministry of Petroleum and Natural
Gas as the CBM administrative agency and offered following key benefits:
¦ No upfront payment
¦ No signature bonus
¦ No participating interest of the Government of India
¦ CBM development blocks allotted through a competitive bidding process
¦ A 7-year tax holiday beginning with the date of commercial CBM production
¦ Freedom to market in domestic market at market determined prices
¦ Imported equipment for CBM development exempted from customs duties
¦ Walkout option at the end of Phases I & II
Incentives also allow no limitation on cost recovery unincorporated joint ventures, accelerated
depreciation and securitization of interest India has implemented policy changes to encourage
foreign investment, including lowering or eliminating tariffs on capital goods, such as electric
power generation equipment (EIA, 2004a).
16.4 Profiles of Individual Mines
Moonidih Mine, Jharkhand
Mine Status
Active
Mine Owner
Bharat Coking Coal Limited
(BCCL]
Mining Method
Longwall
Parent Company
Coal India Limited (CIL]
Depth of seams
To 500 m
Location
Jharia Coalfield, Dhanbad
District
2008 Utilized CUt volume
Minimal usage by GEF
project
Musilia Unit, Ghusick Colliery, West Bengal
Mine Status
Active
Mine Owner
Eastern Coalfields Limited
(ECL)
Mining Method
Room-and-Pillar
Parent Company
Coal India Limited (CIL]
Depth of seams
50-65 m
Location
Burdwan District
No. of seams
2 (additional 4 to
2008 VAM volume
1.899 Mm3
be mined]
Jarangdih U/G Mine, East Bokaro Coalfield, Jharkhand
Mine Status
Active
Mine Owner
Central Coalfields Ltd
Mining Method
Bord & Pillar
Parent Company
Coal India Limited (CIL]
No. of seams
22
2011 CH4 Emissions
0.521Mm3
Mohuda Top U/G Mine, Jharia Coalfield, Jharkhand
Mine Status
Mining Method
Active
Bord &Pillar
Mine Owner Bharat Coking Coals Ltd
Parent Company Coal India Limited (CIL]
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Mohuda Top U/G Mine, Jharia Coalfield, Jharkhand
No. of seams
8
Location Dhanbad District
2011 CH4 Emissions 0.504 Mm3
Pootkee-Bulliary U/G Mine, Jharia Coalfield, Jharkhand
Mine Status
Active
Mine Owner
Bharat Coking Coals Ltd
Mining Method
Bord & Pillar
Parent Company
Coal India Limited (CIL]
No. of seams
18
Location
Dhanbad District
2011 CH4 Emissions
0.389 Mm3
Other mine profiles are located at
https://www.globalmethane.org/activities/indexact2.aspx?geoFocus=india§or=coal and
https://www.globalmethane.org/expo/posters.html.
16.5 References
BP (2013): Statistical Review of World Energy, Coal - Reserves Table, BP, London, United Kingdom, June
2013.
http://www.bp.com/content/dam/bp/pdf/statisticalreview/statistical review of world energy 2013.p
df
Chand (2001): Coalbed Methane: Policies / Regulation for Exploration in India, Chand, S.K., TERI Newswire,
July 2001.
DGH (2010): About DGH, Directorate General of Hydrocarbons, Ministry of Petroleum and Natural Gas, New
Delhi, India, accessed March 2010. http:IIwww.dghindia.org/Index.aspx
Dube (2010): Coal Mine Methane Projects and Opportunities in India, presented by Sanjay Dube, ICF, at
Methane to Markets Partnership Expo, New Delhi, India, March 2010.
https://www.globalmethane.org/expo-docs/indialO/postexpo/coal dube.pdf
EIA (2004a): Environmental Issues - India, U.S. Energy Information Administration, Washington, DC,
February 2004.
EIA (2004b): Country Analysis Brief- India, U.S. Energy Information Administration, Washington, DC,
October 2004.
EIA (2013a): Energy Profile - India, U.S. Energy Information Administration, Washington, DC, 18 March 2013.
http://www.eia.gov/countries/country-data.cfm?fips=IN&trk=m
EIA (2013b): Energy Statistics - India, U.S. Energy Information Administration, Washington, DC, 18 March
2013. http://www.eia.gov/cfapps/ipdhproiect/IRDIndex3.cfm
EIA (2014): Country Analysis Brief - India, U.S. Energy Information Administration, Washington, DC, June
2014. http://www.eia.gov/countries/country-data.cfm?fips=in
GSI (2010): Inventory of Geological Resource of Indian Coal, Geological Survey of India, Ministry of Mines,
Calcutta, India, 2010.
IEA (2014): Energy Statistics - Coal and Peat in India for 2011, International Energy Agency, Paris, France,
website accessed May 2014.
http://www.iea.org/statistics/statisticssearch/report/?country=INDIA&product=coalandpeat&year=20
11
1\
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GMI (2010): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed 2010.
https://www.globalmethane.org/coal-mines/cmm/index.aspx
M2M (2008): Strategies for promoting CMM project development in India, presented at Methane to Markets
Coal Subcommittee meeting in Cagliari, Italy, 29-30 April 2008.
https://www.globalmethane.org/documents/coal cap india.pdf
M2M Expo (2010): Coal proceedings, Methane to Markets Partnership Expo, New Delhi, India, March 2010.
https://www.globalmethane.org/tools-resources/coal techproceeds.aspx
M2M Profile - India (2005): India Profile, submitted to Methane to Markets International by the Government
of India, 2005. https: //www.globalmethane.org/documents/events coal 20050427 india profile.pdf
M2M Workshop - India (2005): Status Paper on India's CBM/CMM Development, presented at the Methane to
Markets Regional Workshop, Beijing, China, 2 December 2005.
https://www.globalmethane.org/documents/events coal 20060525 beiiing.pdf
MOC (2004): No. of Mines - Company Wise, Ministry of Coal, New Delhi, India, 31 March 2004.
http://www.coal.nic.in/abtmines.htm
MOC (2010a): Provisional Coal Statistics 2009-2010, Ministry of Coal, Government of India, Kolkata, India,
2010. http://www.coal.nic.in/Provisional09-10.pdf
MOC (2010b): Inventory of Geological Resources of Coal in India, Ministry of Coal, Government of India,
Kolkata, India, website accessed 5 May 2014. http: //www.coal.nic.in/reserve2.htm
MOC (2012): Coal Annual Report, Ministry of Coal, Government of India, Kolkata, India, 2012.
http: //www.coal.nic.in/annrepl 213.pdf
PFC Energy (2012): LNG Markets Study, PFC Energy, June 2012.
http://www.arcticgas.gov/sites/default/files/documents/lng-canada-12-6-pfc-energy-study-glohal-lng-
mktpdf
Prasad (2006): Personal communication with D.N. Prasad, Ministry of Coal, 16 May 2006.
UNFCCC (2014): Ratification Status - India, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindh.unfccc.int/puhlic/country.pl?country=IN
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990 - 2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
Walker (2000): Major coalfields of the world, CCC/32, IEA Coal Research, 131 pp., London, United Kingdom,
2000.
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17 Indonesia
17.1 Summary of Coal Industry
17.1.1 Role of Coal in Indonesia
Coal is a critically important export commodity for Indonesia. The country has 28 billion tonnes of
recoverable coal reserves (EIA, 2014a). Indonesia produced more than 440 million tonnes (Mmt) of
coal in 2012 (see Table 17-1). Coal production has increased dramatically over the past several
years, increasing by more than 250 percent since 2005 (EIA, 2014b). Continued growth in coal
production is attributable to growing international demand, as well as rising domestic electricity
consumption (EIA, 2014b). Indonesia is the world's largest exporter of coal by weight Exports are
primarily to India and China, but also to South Korea, Japan, and Taiwan (EIA, 2014b).
Coal provided for 48 percent of Indonesia's electricity generation capacity in 2012 (EIA, 2014b).
Power plants consume almost all, or 99 percent, of coal in Indonesia, and cement plants and
metallurgy consume the remainder (Sihite, 2012).
Table 17-1. Indonesia's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
0
28,017
28,017
10 (3.2%]
(2011]
Annual Coal Production (2012]
442.8
0
442.8
4 (5.6%]
Note: Numbers may not add due to rounding
Source: EIA (2014a]
Coal is found in 11 distinct basins on the four major portions of the archipelago that comprise
Indonesia (Figure 17-1). The province of Sumatra contains 49 percent of Indonesia's total coal
reserves and Kalimantan contains 47 percent, with the balance located in Riau, Jambi, and Bengkulu
as shown in Table 17-2. However, most production (90 percent) takes place in Kalimantan, which
has higher quality coal deposits (US Embassy, 2000; Gushka, 2013).
Table 17-2. Indonesia's Coal Reserves by Province (2011)
Resources
Province
Total
Reserves
Inferred
Indicated
Measured
Banten
5.75
4.86
2.72
18.80
0.00
West Java
0.00
0.00
0.00
0.00
0.00
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Table 17-2. Indonesia's Coal Reserves by Province (2011)
Province
Inferred
Resources
Indicated
Measured
Total
Reserves
Central Java
0.82
0.00
0.00
0.82
0.00
East Java
0.08
0.00
0.00
0.08
0.00
Nanggroe Aceh Darussalam
346.35
13.40
90.40
450.15
0.00
North Sumatra
7.00
0.00
19.97
26.97
0.00
Riau
168.05
626.38
948.05
1,755.27
645.67
West Sumatra
294.50
231.16
249.45
800.06
158.43
Bengkulu
17.86
104.08
71.21
208.30
19.02
Jambi
656.90
699.08
443.50
1,990.32
351.65
South Sumatra
14,508.95
14,808.82
10,026.59
59,254.35
13,625.22
Lampung
106.95
0.00
0.00
106.95
0.00
West Kalimantan
477.69
6.85
4.70
489.24
0.00
Central Kalimantan
1,838.50
808.28
704.89
3,549.25
577.42
South Kalimantan
3,833.53
3,344.05
3,481.66
10,659.24
3,778.04
East Kalimantan
13,276.66
6,282.62
8,004.19
40,665.00
8,861.90
South Sulawesi
48.81
129.22
53.09
231.12
0.12
Central Sulawesi
1.98
0.00
0.00
1.98
0.00
North Maluku
0.00
0.00
0.00
2.13
0.00
West Irian Jaya
32.82
0.00
0.00
126.41
0.00
Papua
2.16
0.00
0.00
2.16
0.00
TOTAL
35,625.36
27,058.79
24,100.42
120,338.60
28,017.46
Source: ESDM (2012]
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Figure 17-1. Indonesia's Coal Fields
Kutfti
basin
Barito
basin
South Sumatra
besin
Southwest
Bengkulu
basin
Jatibarang
basin
BRUNEI .
Y S I A Blr*'
Mn-dnnS
MALA
Duri
steamflaod
Pacific Ocean
i Singapore
/ \
/Pakanbaru
IRIAN
JAYA
Ujung Uli
PaiMiaiHit
Jakarta
- JAVA
North Tarakan
basin
Central Sumatra
basin
- papfin* * Artiv* rdtmno —^— SUlkv ilip tanl!
- Pr»pM-»d gn piptlim J, A A_ SuWwtioa r»n» R«t«lr«* pitta walicm
Indian Ocean
Source: Stevens etal. (2001)
17.1.2 Stakeholders
Coal mine operators in Indonesia include state-owned enterprises, private national companies, and
foreign mining companies (USGS, 2007). The major coal producers are listed in Table 17-3.
Table 17-3. Indonesia's Major Coal Producers
Operators
Annual Capacity (2012)
(million tonnes]
PT Kaltim Prima Coal (Bumi Resources)
36.0
PT Adaro Indonesia
35.0
PT Arutmin Indonesia (Bumi Resources)
20.0
PT Tambang Batubara Bukit Asam
19.0
PT Bayan Resources Tbk.
15.0
PT Indominco Mandiri (Banpu Indonesia)
14.8*
PT Berau Coal
13.0
PT Kideco Jaya Agung
12.0
United Tractors
6.5
Sources: USGS (2014]; *Indonesia-Investments (2014)
¦ 49k
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Other key stakeholders involved with the coal industry, the coal mine methane (CMM) and coal bed
methane (CBM) industries are listed in Table 17-4.
Table 17-4. Key Stakeholders in Indonesia's CMM Industry
Stakeholder Category
Stakeholder
Role
Developer
¦ British Petroleum
Project opportunity
¦ CBM Asia Development Corp.
identification and
¦ Dart Energy
planning
¦ Eni
¦ ExxonMobil
¦ Newton Energy Capital Ltd.
¦ Nu Energy
¦ Pertamina
¦ PT Energi Mega Persada Tbk.
¦ Santos
¦ Ephindo
¦ Total
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Engineering, Consultancy,
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
and Related Services
Government Groups
¦ Ministry of Energy and Mineral Resources (Kementerian
Energi Dan Sumber Daya]
¦ Directorate General of Mineral and Coal
¦ Directorate General of Oil and Gas (MIGAS]
¦ Special Task Force for Upstream Oil and Gas Business
Activities (SKK Migas]
Licensing
Source: CBM Asia (2013]
17.1.3 Status of Coal and the Coal Mining Industry
Since transitioning to a democracy beginning in the late 1990s, Indonesia's central government has
been ceding greater autonomy to regional coal administrators. The central government maintains
ownership of coal and associated methane gas, but mine permitting may be done at the central or
local government level, depending on whether the mine crosses provincial boundaries (Asia Law,
2009). The government formerly contracted directly with private companies for mine operations;
however, the 2009 Mining Law (Law No. 4 of 2009 on Mineral and Coal Mining) replaces the
previous "Contract of Work" system with a license-based permitting system that operates through a
tender process instead of the former direct application. Licenses are royalty-based, with rates
varying based on the size of the mining operation (Platts, 2014). Foreign companies may obtain
coal licenses in Indonesia; however, according to regulations enacted in 2010 and 2013, foreign
shareholders must progressively divest its shareholding to a minority stake over time, eventually
divesting a 51-percent share to Indonesian ownership by year 10 (Scott and Tan, 2014).
Most of Indonesia's coal production comes from surface mines; however, underground mining is on
the rise due to environmental concerns and has been identified as an investment opportunity by
the Ministry of Energy and Mineral Resources (Pamerindo Indonesia, 2014; Gushka, 2013).
Additionally, some mines such as the mine site of PT Gerbang Daya Mandiri located in Kutai
Kertanegara, East Kalimantan have started as surface mines and moved operations underground
(Karian etal, 2013).
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Coal production is expected to continue to rise in Indonesia to meet export and domestic electricity
demand. Indonesia has identified a number of objectives and investment opportunities to further
the growth of its coal industry. The 2009 Mining Law applied domestic market obligations which
require coal and mineral producing companies allocate a certain minimum percentage of total
production to the domestic market (Hogarth and Nawangsari, 2010). Due to value-added
requirements imposed by the 2009 Mining Law, all mineral ores are to be processed in Indonesia
before being exported; thus, Indonesia is encouraging investment in areas of gasification,
liquefaction, and coal blending and upgrading (Scott and Tan, 2014; Gushka, 2013). A number of
mine mouth power plant projects are underway, with plans for additional plants to meet domestic
electricity demand.
17.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
CMM recovery projects in Indonesia, in operation or development (GMI, 2014).
17.2.1 CMM Emissions from Operating Mines
With increased coal production, CMM emissions in Indonesia have increased as well. Table 17-5
summarizes Indonesia's CMM emissions.
Table 17-5. Indonesia's CMM Emissions (million cubic meters)
Emission Category
2000
2005
2010
2015
(projected)
Total CH4 emitted
71.1
158.4
282.6
309.6
Source: USEPA(2012)
17.2.2 CMM Emissions from Abandoned Coal Mines
No information about CMM from abandoned mines in Indonesia is available at this time.
17.2.3 CBM from Virgin Coal Seams
Indonesia's government promotes exploration of CBM and shale gas, alongside conventional crude
oil and natural gas projects. The Ministry of Energy and Mineral Resources estimates that the
country has CBM reserves of 12.8 trillion cubic meters based on preliminary studies (EIA, 2014b).
The Minister of Energy and Mineral Resources authorized the Directorate General of Oil and Gas
(MIGAS) to develop CBM in Indonesia (US Embassy, 2000) and in 2007, the Indonesian government
started awarding CBM blocks in the South and Central Sumatra basins on Sumatra Island and the
Kutei and Barito basins in East Kalimantan (see Figure 17-2).
The Sanga-Sanga CBM block in East Kalimantan was contracted to Virginia Indonesia Co., LLC
(VICO), a subsidiary of BP pic. and ENI S.p.A., in November 2009, and commercial CBM production
commenced in 2011 (CBM Asia, 2013; VICO, 2014). CBM from this block is used to generated
power, providing electricity for 2,500 homes in Borneo (SKK MIGAS, 2013).
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Singapore-based Dart Energy and Indonesian PT Energi Pasir Hitam began CBM exploration
activities in East Kalimantan in 2013, with the goal of supplying both power plants and the Bontang
liquefied natural gas (LNG) facility (CBM Asia, 2013).
As of 2013, 54 production sharing contracts (PSC) had been signed with the Indonesian
government for CBM production (Sirait, 2013). The government anticipates CBM production to
reach over 5 billion cubic meters/year by 2020 (EIA, 2014b).
Figure 17-2. Indonesia's CBM Basins
Table 17-6 summarizes Indonesia's CBM resources.
Table 17-6. Indonesia's CBM Resources
Province
Basin
Prospective Area
(km2)
CBM Resources
(trillion cubic meters)
South Sumatra
South Sumatra
7,350
5.18
South Kalimantan
Barito
6,330
2.88
East Kalimantan
Kutei
6,100
2.26
Riau
Central Sumatra
5,150
1.5
East Kalimantan
North Tarakan
2,734
0.5
East Kalimantan
Berau
780
0.24
Bengkulu
Bengkulu
772
0.10
South Kalimantan
Pasir/Asem
385
0.085
South Sulawesi
Sulawesi
500
0.060
West Java
Northwest Java
100
0.023
West Sumatra
Ombilin
47
0.014
TOTAL
30,248
12.8
Source: Stevens and Hadiyanto (2004) via CBM Asia (2012a]
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17.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Indonesia is a signatory to both the UNFCCC and the Kyoto Protocol. As a Non-Annex I Party to the
Kyoto Protocol, Indonesia has no national emissions targets and was eligible to host mitigation
projects under the Clean Development Mechanism (see Table 17-7).
Table 17-7. Indonesia's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 5,1992
August 23,1994
Kyoto Protocol
July 13,1998
December 3,2004
Source: UNFCCC (2014]
17.3.1 Market and Infrastructure Factors
Indonesia is home to more than 3,600 miles of natural gas transmission and distribution pipelines;
however, domestic distribution infrastructure is almost non-existent outside of Java and North
Sumatra. Indonesia's geography presents a challenge to resource development and makes the
switch to natural gas for domestic consumption more difficult; however, declining oil production
and strong economic growth in Indonesia have led to increased domestic consumption of natural
gas (EIA, 2014b). Roughly half of Indonesia's gas production was consumed domestically in 2012,
with the other half being exported as LNG or through two pipeline connections to Singapore and
Malaysia. Domestic consumption is expected to continue to rise as reliance on oil and diesel fall;
pipeline exports will reportedly cease when contracts expire in coming years (EIA, 2014b; CBM
Asia, 2012b). Indonesia's government has sought to meet increasing gas demand by increasing the
country's regasification capacity. Indonesia began processing domestic LNG at its first regasification
terminal, Nusantara, in West Java, which processes LNG supplied from Indonesia's Bontang and
Tangguh plants. Indonesia is in the process of building additional regasification facilities (CBM Asia,
2012b). Indonesia also plans to import LNG. In December 2013, Indonesia signed its first gas
import contract with a US firm starting in 2018 (EIA, 2014b).
17.3.2 Regulatory Information
Coal and gas resources are owned by the State. Private companies wishing to extract resources are
required to develop a PSC with Indonesia (Sirait, 2013). Production splits for oil and natural gas
directed 60 to 80 percent of profits to the government and the remainder to the contractor. In 2003,
production splits were adjusted to 65/35 for oil and 55/45 for gas (USGS, 2003). In 2007, the
government announced that it would offer a 45 percent production split for CBM developments in
order to encourage investors and support the need for unconventional gas supplies (CBM Asia,
2012b). As coal and mineral producers are required to meet domestic market obligations, so are
gas producers - 25 percent of natural gas produced from production-sharing contracts in Indonesia
must supply the domestic market (EIA, 2014b).
CBM contracts have the same terms as oil and gas contracts and are controlled by the Directorate
General of Oil and Gas (MIGAS) (Reuters, 2007). Regulation No. 36 of 2008 on Business Undertaking
of Coal Bed Methane is the current primary regulation for CBM development. Open areas are
offered by tender or direct offer if proposed by a business entity. Under the regulation, oil and gas
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contractors are given priority for CBM activities and are given a direct offer in areas where the oil
and gas contractor has fulfilled a three year commitment. Existing coal concessions are given
priority and coal contractors are given direct offers for CBM activities in areas where the coal
contractor has been exploiting coal for at least three years. In areas of overlapping concessions,
priority for CBM activities is given to the oil and gas operator (Sirait, 2013).
17.4 Profiles of Individual Mines
No mine profiles are available at this time for Indonesia.
17.5 References
Asia Law (2009): Indonesia's New Mining Law, Asia Law, March 2009.
http://www.asialawprofiles.com/Article/2121729/lndonesias-New-Mining-
Law.html? Print=tr ue&Single=tr ue
CBM Asia (2012a): CBM in Indonesia, CBM Asia Development Corp., 2012. http: //www.cbmasia.ca/CBM-In-
Indonesia
CBM Asia (2012b): Indonesia Gas Market, CBM Asia Development Corp., 2012.
http://www.cbmasia.ca/Indonesia-Gas-Market
CBM Asia (2013): Indonesian Coalbed Methane, CBM Asia, June 2013.
http://www.cbinasia.ca/uploads/file/CBMA PRESENTATION lune 2013.pdf
EIA (2014a): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed April 2014. http: //www.eia.gov/cfapps /ipdbproiect/IEDIndex3.cfm
EIA (2014b): Indonesia Country Analysis Brief, U.S. Energy Information Administration, Washington, DC, 5
March 2014. http://www.eia.gov/countries/cab.cfm?fips=ID
ESDM (2012): Handbook of Energy & Economic Statistics of Indonesia 2012, Center for Data and Information
on Energy and Mineral Resources, Ministry of Energy and Mineral Resources/Kementerian Energi Dan
Sumber Daya, 2012.
http://prokum.esdm.go.id/Publikasi/Handbook%20of%20Energy%20&%20Economic%20Statistics%2
0of%20Indonesia%20/Handbook%20of%20Energy%20&%20Economic%20Statistics%20ind%202012.
pdf
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.glohalmethane.org/coal-mines/cmm/index.aspx
Gushka (2013): The Low Rank Coal Policies in Indonesia, Gultom Gushka, presented at Clean Coal Day 2013
International Symposium "Change for Clean Coal Business & Sustainable Coal Supply - Japan Coal Energy
Center (JC0AL)," Tokyo, Japan, 5 September 2013.
http://www.icoal.or.ip/coaldb/shiryo/material/day2 session2 5.pdf
Hogarth and Nawangsari (2010): Indonesian Mining Law: New Domestic Market Obligation (DM0)
Regulation, Joel R. Hogarth and Ratih (Ipop) Nawangsari, O'Melveny & Myers LLP, 25 January 2010.
Indonesia-Investments (2014): Indo Tambangraya Megah, accessed July 2014. http: //www.indonesia-
investments.com/doing-business/indonesian-companies/indo-tambangraya-megah/item394
Karian et al. (2013): Surface Subsidence Analysis Due to Longwall Underground Coal Mining Method in PT
Gerbang Daya Mandiri, Tenggarong, East Kalimantan, Tri Karian, Timbul M. Habeahan, Budi Sulistiano,
and Suseno Kramidibrata, Journal of Novel Carbon Resources, Vol, pp 47-52, February 2013.
http://ncrs.cm.kyushu-u.ac.ip/assets/files/INCRS/INCRS Vol7 47-52.pdf
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Pamerindo Indonesia (2014): Events: Mining Indonesia 2015, Pamerindo Indonesia, accessed July 2014.
http://pamerindo.com/events/mining-indonesia-2015/
Platts (2014): Indonesia postpones coal royalty rise as miners resist due to low prices, Platts Manila, 20
March 2014. http: //www.platts.com/latest-news/coal/manila/indonesia-postpones-coal-royalty-rise-as-
miners-2 675542 6
Reuters (2007): "Indonesia Seeks Investors for Coal Bed Methane Sector," Reuters, 6 November 2007.
http://uk.reuters.eom/article/2007/ll/06/indonesia-energv-idUKIAK26450720071106
Scott and Tan (2014): Indonesian mining law for foreign investors - What's going on?, Chris Scott and Lian
YokTan, K&L Gates, 31 January 2014.
http://www.mondaq.com/x/289258/Mining/Indonesian+mining+law+for+foreign+investors+Whats+g
oing+on
Sihite (2012): Low Rank Coal Utilization in Indonesia, Thamrin Sihite, presented at Clean Coal Day of 2012
International Symposium, Tokyo, Japan, 4-5 September 2012.
http://www.icoal.or.ip/coaldh/shiryo/material/2012day2 session4 l.pdf
Sirait (2013): Indonesia Current Policy and Regulation, Darwin Sirait, presented at A Regional Workshop on
the Changing Global Gas Market and Conventional Gas, Jakarta, Indonesia, 7 May 2013.
http://www.doi.gov/intl/itap/upload/Session-03-03-Policy-2nd-day-RI-USA-Mr-Darwin-2013-ok.pdf
SKK MIGAS (2013): 2500 Houses to Enjoy Coalbed Methane Electricity, SKK MIGAS, March 2013.
http://www.skkmigas.go.id/en/2500-rumah-penduduk-menikmati-aliran-listrik-gas-batubara
Stevens et al. (2001): Indonesia's 337 TCF CBM Resource a Low Cost Alternative to Gas, LNG, Stevens, Scott
H., K. Sani, and S. Hardjosuwiryo, Oil & Gas Journal, 22 October 2001.
Stevens and Hadiyanto (2004): "Indonesia Coalbed Methane Indicators and Basin Evaluation," presented at
SPE Asia Pacific Oil and Gas Conference and Exhibit, Perth, Australia, SPE 88630, on behalf of Hadiyanto,
Indonesian Ministry of Energy and Mineral Resources, Directorate General of Geology and Mineral
Resources, 18-20 October 2004.
UNFCCC (2014): Ratification Status - Indonesia, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=ID
US Embassy (2000): Coal Report: Indonesia 2000, Embassy ofthe United States of America, Jakarta,
Indonesia, October 2000. http: //photos.state.gov/libraries/indonesia/39181/pdfs2 /coal2000report.pdf
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2003): The Mineral Industries of Indonesia and East Timor (Timor-Leste), Pui-Kwan Tse, United States
Geological Survey, 2003.http: //minerals.usgs.gov/minerals/pubs/country/2003 /idttmyb03.pdf
USGS (2007): "Geochemistry of Selected Coal Samples from Sumatra, Kalimantan, Sulawesi, and Papua,
Indonesia," H. Belkin and S. Tewalt, United States Geological Survey, 2007.
http: / /p ubs. us gs. go v /o f/2 0 07 /12 02 /
USGS (2014): 2012 Minerals Yearbook Indonesia [Advance Release], United States Geological Survey, Chin S.
Kuo, March 2014. http: //minerals.usgs.gov/minerals/pubs/country/2012 /myb3-2012-id.pdf
VICO (2014): Our Business, Virginia Indonesia Co., LLC, accessed July 2014. http: //www.vico.co.id/our-
business
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18 Italy
18.1 Summary of Coal Industry
18.1.1 Role of Coal in Italy
Italy is severely deficient in coal resources and relies almost entirely on imports for its coal supply.
Coal's contribution to total energy use in the country was about 8.7 percent in 2012, amounting to a
consumption of 23.6 million tonnes (Mmt) (EIA, 2014).
Italy produces about 0.08 Mmt of coal annually (see Table 18-1), sourced entirely from Miniera
Monte Sinni, Italy's only active underground coal mine, located in the Sulcis Basin in the south-west
of Sardinia Island (Figure 18-1). Estimates of Italy's sub-bituminous and lignite reserves are about
50 Mmt of mineable coal (out of a worldwide total of 900 Mmt) (EIA, 2014).
Table 18-1. Italy's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
Estimated Proved Coal Reserves
0
50
50
64 (0.006%)
(2011)
Annual Coal Production (2012)
0.080
0
0.080
58 (0.088%)
Source: EIA (2014)
Figure 18-1. The Only Underground Coal Mine in Italy
/y-ff jVl
Island of Sardinia
0
Sulcis basin
Source: IEA Clean Coal Center (2005)
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18.1.2 Stakeholders
Table 18-2 lists potential stakeholders in Italy's coal mine methane (CMM) industry. SOTACARBO, a
50-percent state-owned company has joined Carbosulcis in promoting methane recovery from the
Sulcis Basin. SOTACARBO partners with University of Caligari and the Istituto Italiano di Geofisica e
Vulcanologia (INGV).
Table 18-2. Key Stakeholders in Italy's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies and
SOTACARBO
Project hosts
CBM Developers
Kimberley Oil
Carbosulcis
European Gas Limited
Heritage Petroleum
Independent Resources pic
Vico Indonesia (Eni S.p.A. subsidiary]
Shell
Future Corporation Australia ltd
Developers
See http://www.epa.gov/coalbed/networkcontacts.html
Project opportunity
identification and planning
Engineering, Consultancy,
See http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
and Related Services
Universities, Research
The Istituto Italiano di Geofisica e Vulcanologia
Technical assistance
Establishments
University of Caligari
National Institute for Geophysics and Vulcanology
Government Groups
Ministry of Productive Activities - Directorate for Energy
Licensing, Monitoring and
and Mineral Resources
Control
Ministry of Environment, Environment, Land and Sea
Energy Authority (Autorita per l'Energia Elettrica e il Gas,
AEE]
18.1.3 Status of Coal and the Coal Mining Industry
Carbosulcis' Miniera Monte Sinni is currently the only operating coal mine in Italy and its
concession is owned by the Regional Government of Sardinia (M2M, 2005). Like other European
countries, however, coal production will be phased out per European Union (EU) directives. The
Santa Barbara mine in Tuscany, Italy's single source of lignite, closed in 2003 after production
declined sharply from 156 thousand tonnes in 1998 to an estimated 10 thousand tonnes in 2002.
The mine was previously operated by Enel (Ente Nazionale per l'energia Elettrica), the state-owned
electricity company (USGS, 2002; USGS, 2003).
Italy's EU membership has initiated privatization of the country's energy sector. Ente Nazionale
Idrocarburi (ENI), the state-held oil and gas giant, and Enel became joint-stock companies in 1992.
The state sill has a 30 percent stake in each company. Consequently, several new participants have
emerged in Italy's energy markets this past decade, and both companies have an international
presence (ENI, 2014; ENEL, 2013).
Italy is the fourth highest consumer of energy in Europe, with consumption at 7.5 quadrillion Btu in
2011 (EIA, 2014). Fueled by the rising demand for power, Italy has increased its dependence on
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coal for power generation over the past decade. But consumption has recently plateaued as natural
gas use has expanded, and Italy currently relies on coal for only 9 percent of its overall energy
needs (EIA, 2014). Planned coal mine and power plantprojects have been abandoned in some cases
due to political and administrative barriers (USGS, 2007).
18.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
projects in Italy in operation or under development (GMI, 2014). Updates on future CMM projects
in Italy can be found at https: //www.globalmethane.org/coal-mines/cmm/index.aspx.
18.2.1 CMM Emissions from Operating Mines
Methane emissions in Italy totaled 2.1 million cubic meters (m3) in 2000, but are projected to
decrease to 1.4 million m3 by 2015, and then remain stable through 2030 (see Table 18-3).
Table 18-3. Italy's Projected CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
2.1
1.4
1.4
1.4
Source: USEPA(2012)
18.2.2 CMM Emissions from Abandoned Coal Mines
There are no current CMM recovery projects in Italy.
18.2.3 CBM from Virgin Coal Seams
Key companies involved in coal bed methane (CBM) exploration in Italy include European Gas
Limited (formerly known as Kimberley Oil NL) and Heritage Petroleum. They have targeted the
Sulcis Basin as well as three areas in southern Tuscany. Nearby volcanic centers and geothermal
activity in these locations are believed to have created high concentrations of gas (Heritage
Petroleum, 2007).
The Sulcis Basin is estimated to have as much as 1,000 Mmt of sub-bituminous coal from the Eocene
age. Along with a 150-m thick coal sequence, substantial thicknesses of impure coal and
carbonaceous shale also exist, which have the capability to generate significant methane aside from
the coal seams. Although coal mining in the eastern region did not indicate much methane, the
geological conditions are different in the western region, suggesting significant gas reserves. The
Porduttivo formation in the west is overlain by the Oligocene-Miocene volcanic centers. Geothermal
activities from this condition would lead to strong maturation of coal seams and high
concentrations of gas (Heritage Petroleum, 2007).
Also, SOTACARBO has partnered with Carbosulcis and University of Caligari to promote CBM
production. Their main activities include sampling and analyzing Sulcis coal, finding new deeper
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coal seams, checking the use of CBM methods currently in place in the region, and updating
enhanced CBM technologies.
Meanwhile, European Gas Limited and Heritage Petroleum have been granted three research
permits in Tuscany (Figure 18-2). These permits cover 1,500 km2 of three basins containing
Miocene coal. Mining in this area was discontinued in 1959 due to a methane gas explosion that
killed 42 people. As with the Sulcis Basin, it is believed that geothermal activities and enhanced heat
flow in the area have created conditions for high levels of methane production (Heritage Petroleum,
2007; EGL, 2010).
Figure 18-2. European Gas Limited's Tuscany Projects
18.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Italy is an Annex I partner under the Kyoto Protocol (see Table 18-4) and has agreed to reduce its
carbon dioxide emissions by 2008-2012. However, it will do so as a collective target for all the EU
countries. Under EU commitment, Italy must reduce its emissions by 6.5 percent below the 1990
level. However, Italy is not on track, unlike other EU countries, to meet its pledge. During the 2009
UNFCCC Copenhagen Conference, the EU community, speaking through the European Commission,
pledged to reduce emissions 20 percent unconditionally by 2020. They further pledged a 30
percent cut by 2020 if an international accord was reached (EC, 2009).
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Table 18-4. Italy's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 5,1992
April 15,1994
Kyoto Protocol
April 29,1998
May 31,2002
Source: UNFCCC (2014]
In 2007, the Italian Ministry for the Environment and Territory produced the Environmental Action
Strategy for Sustainable Development in Italy, aimed at helping Italy comply with greenhouse gas
reduction targets under the Kyoto Protocol. However, this document has not been formally adopted
by the Italian government It also does not address energy-related greenhouse emissions, including
CMM (UN, 2007).
18.3.1 Market and Infrastructure Factors
Currently, Italy is pursuing several technical issues related to CMM recovery. Developing an
effective methane survey system and analysis models for recovery of CMM from the Sulcis Basin is
the top priority. Improving gas drainage, identifying CMM utility and measuring emissions at
surface mines are among other issues facing Italy. In general, Italy is not prepared for CMM projects
in terms of public attitude, R&D efforts, or private financing. The country will benefit by networking
with countries with advanced CMM experience.
Italy's natural gas market is highly evolved, providing for about 40 percent of the total energy
consumed by the country (IE A, 2009a). Therefore, Italy has a well-established network of pipelines
extending for 30,000 km—the third largest pipe network in Europe—and offers open access. As of
now, Sardinia is not connected to this gas transportation system but that will soon change with the
anticipated Galsi project: a gas pipeline that would transport natural gas from Algeria to Sardinia.
With a capacity of approximately 8 billion m3 per year, the Galsi pipeline will be approximately 830
kilometers long, 270 of which will be on Sardinian territory (ABO, 2014). This would be strategic
for implementing CBM marketing in Italy, since the Sulcis Basin in southern Sardinia is the most
promising site for CBM.
18.3.2 Regulatory Information
Italy's energy and natural resources policies allow both government and private companies to
operate production. Companies may be given concessions that need periodic renewal to recover
methane or mine coal. For a given coal basin, mining coal and draining methane can be executed by
separate companies.
The CMM recovery work is still in its infancy in Italy, and the country lacks legal regulation for the
CMM industry. An extension of the natural gas legal framework may, therefore, apply. ENI has been
controlling the gas industry almost completely. But, since 2000, the gas industry is slowly being
liberalized in compliance with the EU policies, including freeing of gas prices and decentralizing
production and distribution. Italy still has the state involved in response to public opinion. There is
no domestic private investment, but foreign private sector investments are involved (EIA, 2008).
All natural resources are owned by the government Licenses may be given at discretion to private
companies for exploration and production; terms of such deals appear open for negotiation. An
exploration permit is granted for six years and has to be renewed twice, every three years. A
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production license runs for 20 years and is renewable. For a license to be granted, the company at
hand must possess local knowledge. Royalties are set at 7 percent of the annual net production and
the corporate tax rate is set at 34 percent.
Italy is gradually defining stronger environmental regulations, not only to be in compliance with EU
standards, but also to respond to domestic opinions. The legal text of EU's environmental laws is in
the process of being incorporated into Italian law (EIA, 2008). Contributing to sustainable
development, the CMM project outputs (electricity and pipeline gas) may enjoy competitive pricing
in a free trade market.
18.4 Profiles of Individual Mines
Sulcis Basin, Sardinia
General Information
Total mineable reserves, million tonnes
50 (EIA, 2014]
Total mining area
615 km2
Depth of shafts
400 m
Mining capacity
400,000 tonnes/year
Geologic and Mining Conditions
Rank of coal
Sub-bituminous coal
No. of seams
Up to 13
Seam thickness
35 to 40 m cumulative thickness over 13 seams
Depth of mining
150 m
Calorific Value
5,000 kcal/kg
Ash content
Poor quality
Sulfur content
Poor quality
Mining equipment
Longwall
Source: Heritage Petroleum (2007]; IEA (2009b]
18.5 References
ABO (2014): "Algeria: A country with enormous opportunities, About Oil, 11 June 2014.
http://www.abo.net/oilportal/interview/view.do?contentId=22 55528
EC (2009): Fifth National Communication From The European Community Under The UNFCCC, European
Commission, Brussels, Belgium, 12 December 2009. http: //unfccc.int/resource/docs/natc/ec nc5.pdf
EGL (2010): "Tuscany Projects," European Gas Limited, 2010.
EIA (2008): EIA Country Analysis Briefs - Italy. Hosted by Encyclopedia of Earth, 2008.
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http: IIwww.eia.gov/cfapps /ipdbproi ect/1ED Index3.cfm
ENEL (2013): Shareholders, Ente Nazionale per l'energia ELettrica, Rome, Italy, 2013.
http://www.enel.com/en-GB/investor/shareholders/
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ENI (2014): "Corporate Governance, Major Shareholders," ENI, Rome, Italy, 2014.
http://www.eni.com/en IT/governance/shareholders/relevant-participation/relevant-
parti cipation.shtml
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
Heritage Petroleum (2007): Company Information: Heritage Petroleum, Heritage Petroleum, January 2007.
IEA (2009a): 2009 Energy Balance for Italy. International Energy Agency, Paris, France, 2009.
http://www.iea.org/stats/balancetable.asp7C0UNTRY C0DE=IT
IEA (2009b): Energy Policies of IEA Countries - Italy, International Energy Agency, Paris, France, 2009.
http://www.iea.org/countries/membercountries/italy/
IEA Clean Coal Center (2005): Coal Recovery from Waste Fines of the Nuraxi Figus Coal Treatment Plant by
Selective Flotations, presented at the Second International Conference on Clean Coal Technologies for our
Future, 2005. http://www.iea-
coal.org.uk/publishor/svstem/component view.asp?LogDocId=81265&PhvDocId=5654
M2M (2005): Coal Mine to Market Subcommittee Country Profile - Italy, Methane to Market Partnership,
2005. https://www.globalmethane.org/documents/events coal 20050427 italv profile.pdf
UN (2007): Environmental Action Strategy for Sustainable Development in Italy, Ministry for the
Environment and Territory.
http://www.un.org/esa/agenda21/natlinfo/countr/italy/Italian%20NSDS.pdf
UNFCCC (2014): Ratification Status - Italy, United Nations Framework Convention on Climate Change,
accessed June 2014. http: IImaindb.unfccc.int/public/countrv.pl?country=IT
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2002): The Mineral Industry of Italy, 2002.
http://minerals.usgs.gOv/minerals/pubs/country/2002/itmyb02.pdf
USGS (2003): Italy Production of Mineral Commodities, 2003.
USGS (2007): 2005 Minerals Yearbook - Italy, U.S. Geological Survey, Reston, VA, 2007.
http://minerals.usgs.gOv/minerals/puhs/country/2005/itmyh05.pdf
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19 Japan
19.1 Summary of Coal Industry
19.1.1 Role of Coal in Japan
Coal accounted for 23 percent of Japan's total energy consumption in 2012 (EIA, 2014a). However,
Japan does not have any active coal mines (domestic production ended in 2002) and now imports
100 percent of its coal. For three decades, Japan was the world's largest importer of coal. In 2012,
Japan was surpassed by China as the world's largest importer of coal. Japan now accounts for about
15 percent of total world coal imports, primarily from Australia (EIA, 2014a). Sources of imported
thermal and coking coal are Australia, Canada, China, Colombia, Indonesia, Mongolia, Russia, and
the United States; South Africa is also a source of thermal coal, while New Zealand is an additional
source of coking coal (IEEJ, 2012). While Japan does not have any active coal mines atthis time, it
operated as much as 600 coal mines in the 1960s (M2M, 2005). Its total coal reserves are estimated
at 347 million tonnes (Mmt) (Table 19-1) and lie primarily on the Hokkaido and Kyushu islands
(see Figure 19-1 on next page).
Table 19-1. Japan's Coal Reserves and Production
Anthracite &
Sub-
Indicator
Bituminous
bituminous
Total
Global Rank
(million
tonnes)
& Lignite
(million tonnes)
(million tonnes)
(# and %)
Estimated Proved Coal Reserves 336 11 347 38 (0.039%]
(2011]
Annual Coal Production (2012] 0 0 0 NA
Source: EIA (2014b]
19.1.2 Stakeholders
Table 19-2 identifies potential stakeholders in Japanese coal mine methane (CMM) development.
Table 19-2. Key Stakeholders in Japan's CMM Industry
Stakeholder Category Stakeholder Role
Developers ¦ See http: //www.epa.gov/coalbed/networkcontacts.html Project opportunity
identification and
planning
Engineering, Consultancy, ¦ See http://www.epa.gov/coalbed/networkcontacts.html Technical assistance
and Related Services
Government Groups ¦ Ministiy of Economy, Trade, and Industry Permitting, outreach
¦ Environment Management Bureau - Ministiy of the efforts
Environment
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Table 19-2. Key Stakeholders in Japan's CMM Industry
Stakeholder Category
Stakeholder
Role
Other
¦ Japan Bank for International Cooperation
¦ New Energy and Industrial Technology Development
Organization
¦ Japan Coal Energy Center
¦ Macquarie Bank Limited
¦ Mitsui Mining Co.
¦ Mitsubishi Materials Co.
¦ Mizuho Corporate Bank, Ltd.
Finance providers,
development
assistance providers,
carbon credit
purchasers
Figure 19-1. Japan's Coal Fields
La Perouse Strait
Sea of Japan
SADO/4
OKIGUNTO o
Korea Strait ^3'
Li SH1MA
JAPAN
OSUM1GUNTO
AM AMI O SH1MA
OKINAWA GUNTO
! \
V Coal Fields
Hokkaido
22 Owari-Mino
1 Tempoku
23 Mie
2 Nakagawa
24 Kumano
3 Kabato
25 Maizuru
4 Tomamae
26 Katsura
5 Rumoi
27 Matsue
6 Kushiro
28 Omine
7 Ishikari
29 Otsu
8 Yamabe
30 Ubc
9 Hitaka
10 Kayanuma
Kyushu
31 Kokura
Honshu
32 Chikuho
11 Shimokita
33 Munakata
12 Kuji
34 Asakura
13 Kitakami
35 b'ukuoka
14 Miyagi
36 Karatsu
IS Mogami
37 Miike
16 Nishitagawa
38 Sasebo
17 Joban
39 Sakito-
18 Takasaki
M at sushi ma
19 Higashichikuma
40 Isahaya
20 Kotaki
41 Takashima
21 Noto
4-2 Amakusa
Source: Schwochow (1997]
19.1.3 Status of Coal and the Coal Mining Industry
Japan's coal industry has declined steadily in the last 50 years. In the 1960s, Japan had about 600
coal mines and produced about 55 Mmt of coal annually. Due to competition with coal imports,
production declined to about 3.5 Mmt in 2001 (EIA, 2014b). Production ceased entirely in January
2002 with the closure of the last remaining Kushiro coal mines (EIA, 2008).
* 7<
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19.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database identifies two projects in
Japan at abandoned mines as described in Section 1.2.2 (GMI, 2014). Updates on future CMM
projects in Japan can be found at https: //www.globalmethane.org/coal-mines/cmm/index.aspx.
19.2.1 CMM Emissions from Operating Mines
Methane emissions in Japan totaled 53.9 million cubic meters (m3) in 2000, but are projected to
decrease significantly to 3.5 million m3 by 2015, and then only rise slightly to 4.2 million m3 by
2030 (see Table 19-3).
Table 19-3. Japan's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
53.9
4.9
3.5
3.5
Source: USEPA (2012]
19.2.2 CMM Emissions from Abandoned Coal Mines
Two CMM use projects that were operating at abandoned coal mines in Japan in the early 2000s
have since closed (M2M, 2006).
19.2.3 CBM from Virgin Coal Seams
There is no commercial development of coalbed methane in Japan at this time.
19.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Under the Kyoto Protocol, Japan pledged to reduce its national greenhouse gas (GHG) emissions by
6 percentin the period 2008 to 2012, relative to base year 1990 (UNFCCC, 2003). Table 19-4
summarizes Japan's climate change mitigation commitment It further pledged to cut GHG
emissions 25 percent below 1990 levels by 2020 during the 2009 Copenhagen United Nations
Climate Change Conference (UNFCCC, 2009).
Table 19-4. Japan's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 13,1992
May 28,1993 (Acceptance]
Kyoto Protocol
April 28,1998
June 4,2002 (Acceptance]
Source: UNFCCC (2014]
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In November 2013, atthe U.N. climate talks in Warsaw, Poland, Japan announced plans to scale
back its commitment to reducing GHG emissions from 25 percent below 1990 levels to 3.8 percent
below 2005 levels (representing a 3.1 percent increase from 1990 levels). This decision, known as
The Warsaw Target, was made in large part due to the fact that all of Japan's 5 0 nuclear reactors,
which produced about 30 percent of Japan's electricity, were shut down for safety inspections
following the March 2011earthquake. As of late 2013, Japan's nuclear power generation capacity
was entirely removed from service (EIA, 2014a). The Warsaw Target, therefore, assumes no
nuclear power generation and aggressive GDP growth. The target is tentative, however, and will
likely be revised based on future reviews. Japan's long-term commitment to reduce emissions to 80
percent below 1990 levels by 2050 still stands (WRI, 2014).
19.3.1 Market and Infrastructure Factors
Japan has developed considerable technical resources to develop CMM, including high efficiency
CMM recovery and power generation systems, well-developed town gas systems for subsidence
areas in coal mining regions, and technologies for dimethyl ether production from CMM (M2M,
2005).
Financing for CMM projects could potentially be acquired through the Japan Bank for International
Cooperation (JBIC). JBIC has been increasing financing for projects that address global
environmental problems, including global warming and environmental projects, such as those
aimed at reducing pollution. JBIC's Official Development Assistance loans give preference to
projects that support environmental efforts in developing countries. For example, JBIC is
supporting a CMM recovery project in Shanxi province, China. The project has been developed to
qualify as a Clean Development Mechanism project; Japanese firms are expected to purchase carbon
credits generated from the project (JBIC, 2007).
19.3.2 Regulatory Information
Japan lacks specific regulations for CMM industry and gives CMM ownership rights to coal mine
owners. The Mining Law provides a basic system that governs mining of mineral resources, while
the Mine Safety Law addresses mine safety issues and promotes the safe development of the
mineral resources.
19.4 Profiles of Individual Mines
No information profiling individual underground mines in Japan was found.
19.5 References
EIA (2008): Country Analysis Briefs - Japan, U.S. Energy Information Administration, Washington, DC,
accessed June 2010.
EIA (2014a): Country Analysis Briefs - Japan, U.S. Energy Information Administration, Washington, DC,
accessed June 2014. http: //www.eia.gov/countries/country-data.cfm?fips=IA
EIA (2014b): International Energy Statistics, U.S. Energy Information Administration, Washington, DC
accessed July 2014. http: IIwww.eia.gov /cfapps /ipdbproi ect/1ED Index3.cfm
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalinethane.org/coal-inines/cinm/index.aspx
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IEEJ (2012): "Coal Trends: Trends in coal supply, demand and prices as seen from statistics," The Institute of
Energy Economics - Japan, October 2012. http://eneken.ieei.or.ip/data/4583.pdf
JBIC (2007): Japan Bank for International Cooperation, accessed 2010. http://www.ibic.go.ip/wp-
content/uploads/today en/2007/03/2607/td 2007mar.pdf
M2M (2005): Japan Profile submitted to Methane to Markets, 2005.
https://www.glohalmethane.org/documents/events coal 20050427 iapan profile.pdf
M2M (2006): Japan Profile submitted to Methane to Markets, 2006.
https://www.glohalmethane.org/documents/events coal 20060525 iapan.pdf
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
UNFCCC (2003): In-depth review of the third national communication, United Nations Framework
Convention on Climate Change, 2003. http://unfccc.int/resource/docs/idr/ipn03.pdf
UNFCCC (2009): Copenhagen Accord, United Nations Framework Convention on Climate Change, 2009.
http://unfccc.int/meetings/copenhagen dec 2009/items/5262.php
UNFCCC (2014): Ratification Status - Japan, United Nations Framework Convention on Climate Change,
accessed November 2014. http: //maindb.unfccc.int/public/country.pl?country=IP
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
WRI (2014): "Post-Fukushima Climate Action: How Japan Can Achieve Greater Emissions Reductions", World
Resources Institute, 19 June 2014. http: //www.wri.org/hlog/2014/06/post-fukushima-climate-action-
how-iapan-can-achieve-greater-emissions-reductions
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20 Kazakhstan
20.1 Summary of Coal Industry
20.1.1 Role of Coal in Kazakhstan
Kazakhstan ranks 10th in the world in coal production, with coal comprising 64 percent of its total
energy consumption in 2012 (EIA, 2013). In 2012, it exported 25.3 percent of the coal produced (32
million tonnes [Mmt]), primarily to Russia and Ukraine. In 2011, 85 percent of power generation
was coal-fired and net generation totaled approximately 81.2 billion kilowatt-hours (kWh) of
electricity (EIA, 2013). Table 20-1 summarizes Kazakhstan's coal resources and recent production,
while Figure 20-1 shows historical annual coal production from 2000 to 2012 (EIA, 2013).
Table 20-1. Kazakhstan's Coal Reserves and Production
Anthracite &
Sub-bituminous
Total
Global Rank
(# and %)
Indicator
Bituminous
(million tonnes)
& Lignite
(million tonnes)
(million
tonnes)
Estimated Proved Coal Reserves 21,496 12,097 33,593 8 (3.78%]
(2011]
Annual Coal Production (2012] 120.5 5.5 126 10(1.6%]
Source: EIA (2013]
Figure 20-1. Kazakhstan Annual Coal Production
Source: EIA (2013]
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Kazakhstan has registered 49 coal deposits in its state reserve balance (USGS, 2010). The main
producing regions are located in the central and northern regions of Kazakhstan in the Ekibastuz,
Karaganda, Maykuben, Shubarkol and Turgay basins (Table 20-2).
Table 20-2. Kazakhstan's Major Coal Basins Production Capacity in 2012
Basin
Ekibastuz
Karaganda
Maykuben
Shubarkul
Zhelyn
Annual Estimated Production ^ ^
Capacity (million tonnes]
35.4
4.0
8.9
1.0
Source: USGS (2011]
20.1.2 Stakeholders
Thirty-three companies operate coal mines in Kazakhstan, including 28 of domestic origin, five
foreign companies and one joint venture (Energy Charter Secretariat, 2013). The major companies
are listed in Table 20-3. The table also lists other potential stakeholders in Kazakhstan's coal mine
methane (CMM) industry.
Table 20-3. Key Stakeholders in Kazakhstan's CMM Industry
Stakeholder Category
Stakeholder
Role
Coal Producing Enterprise ¦
JSC ArcelorMittal Termirtau
Project hosts
¦
Bogatyr-Access-Komir, Ltd.
¦
OJSC "Eurasian Natural Resources Corporation"
¦
OJSC "Borly"
¦
"Maykuben-West" joint venture
¦
Komirlnvest, Ltd.
¦
Transenergo, Ltd.
¦
"Gefest" Association
¦
Shubarkol Komir
Developer ¦
ZhumysStroiService LLP
Project opportunity
¦
KazTransGas JSC
(CBM from virgin
¦
Social enterprise company Saryarka
seams] identification
¦
See http://www.epa.gov/coalbed/networkcontacts.html
and planning
Engineering or ¦
Azimut Energy Services, Ltd.
Technical assistance
Consultancy Services ¦
Promelektronika-K LL C.
¦
Kar-Metan LL C.
¦
See http://www.epa.gov/coalbed/networkcontacts.html
Universities and Research ¦
Methane Center, Kazakhstan
Technical assistance
Centers ¦
Karaganda State Technical University
¦
Karaganda Institute for Scientific Research on Industrial
Safety
Other ¦
National Agency for Technological Development
¦
Zhasyl Damu state company (emissions trade system]
¦
National Geological Exploration Company "Kazgeologiya"
(assessment of CMM/CBM resources]
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Table 20-3. Key Stakeholders in Kazakhstan's CMM Industry
Stakeholder Category
Stakeholder
Role
Government Groups
Ministry of Energy (absorbed functions of former Ministry of
Industry and New Technologies, Ministry of Oil and Gas,
Ministry of Environment and Water Resources]
Ministry of National Economy
Ministry of Investment and Development (geology and
energy efficiency]
Kazakh Scientific Research Institute for Ecology and Climate
(KazNIIEC)
Drafting of legislation,
implementation of
laws, government
oversight
Source: KazNIIMOSK (2002]; Energy Charter Secretariat (2013]; Alekseev (2010]
20.1.3 Status of Coal and the Coal Mining industry
Kazakhstan's coal mining industry was restructured and largely privatized between 1995 and 1997
(State, 2005). The Karaganda and Ekibastuz mining associations were dissolved and the mines put
up for sale or lease. Many of the coal mining enterprises were closed or reorganized (USGS, 2010;
KazNIIMOSK, 2002).
Coal production in Kazakhstan declined by more than 50 percent in the years following
independence from the Soviet Union in 1991 through 1999 (BP, 2013). Since then Kazakhstan's
coal production has continued to increase with 2012 yielding production comparable to the Soviet
times (EIA, 2013). During the Soviet era, coal production was subsidized and mines were not
structured to maximize profits. When subsidies were removed and mines had to operate
competitively, it became extremely difficult to obtain foreign investment to maintain their
economic viability. This fundamental lack of profitability was compounded by other problems, such
as restructuring, mine problems, and accidents. Government efforts to significantly improve
production by 2015, by encouraging foreign interest in the coal mining industry, appear to have
been successful. Since the low point in 1999, annual production has steadily increased to rates
above 100 million tonnes, although the world-wide economic downturn in 2009 also affected
Kazakhstan coal production with a resultant 8.6 percent decline in production from 2008, but
rebounded to a 13.4 percent increase from 2008 to 2012. Consumption has risen steadily since
2000 with exports remaining relatively steady since 1999 (EIA, 2013).
Underground mining only occurs in the Karaganda basin, which produces the coking coals essential
to the steel and iron sectors and coke plants in Kazakhstan, Russia, Ukraine, and Georgia, and also
to the phosphoric and ferroalloy industries. The share of production from underground mines
decreased from about 27 percent in 1990 to just 11 percent in 2000 (KazNIIMOSK, 2002), and back
up to 30 percent in 2010 (Alekseev, 2010), following new investment from companies such as the
ArcelorMittal Group (USGS, 2010). The ArcelorMittal Coal Division operates eight underground
mines in the Karaganda Basin producing 12 Mmt annually (Baimukhametov, 2009). Twenty-six
underground mines were reportedly in operation in 1990 (KazNIIMOSK, 2002) with fifteen now
currently producing (Energy Charter Secretariat, 2013). Four mines operated by Komirlnvest and
Transenergo have nearly stopped production. ArcelorMittal's eight underground mines (originally
operated by Ispat-Karmet) were expanded in 1986 to stabilize production levels. The Gefest
Association also operates in the Karaganda Basin as the association of small mines. By 2007, the
Association represented about 30 mines with approximately 1 Mmt per year of combined coal
production (UNECE, 2008). For example, the Association represents Mine Batyr, an underground
mine in the Karaganda Basin.
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Table 20-4 provides mine statistics for Kazakhstan.
Table 20-4. Kazakhstan Mine and Production Statistics
Type of mine
Production
(million metric tonnes)
Number of major mines*
Underground (active]
31.5 (2009]
15 in Karaganda Basin
Surface (active]
69.9 (2009]
6 total:
3 mines in the Ekibastuz Basin - Bogatyr, Severny,
Vostochny (80% of surface production]
3 others - Borlinskoe deposit, Maykuben Basin, Karaganda
Basin (15-20% of surface production]
*Note these figures representee largest mines. The total number of mines operating in Kazakhstan is 35 (24
underground mines and 11 open pit mines (Energy Charter Secretariat, 2013]
Sources: Alekseev (2010]; EOK (2010]
20.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies two
CMM projects. One is operating at the Kazakhstanskaya underground mine in the Karaganda basin.
The methane currently drained from the mine is being used for boiler fuel in five neighboring mines
(GMI Projects, 2014). The mine is planning an expansion of its degasification systems by 8.5
kilometers (km) along with the installation of three KVTS-10 boilers utilizing 13 million m3
methane per year. Current coal production is 1 million tonnes per year (Mmt/y) with plans to
increase production to 1.8 Mmt/y by 2012. The second project is power generation from CMM at
the Lenina mine (1.4 MW CHP). In 2013, the CHP unit produced 5 million kWh, operating at 40
percent availability (Baimukhametov, 2014).
20.2.1 CMM Emissions from Operating Mines
The Kazakh coal mines are particularly gassy and prone to violent gas outbursts, and must be
degasified and ventilated to prevent explosions and promote worker safety. The underground
mines in the Karaganda basin use a variety of pre-mining and post-mining methane drainage
techniques. Most of the mines are operated at a depth of more than 500 m and gas contents in these
mines average between 18-24 m3/tonne (Baimukhametov et al, 2009) with specific emissions
averaging 33 m3/tonne (KazNIIMOSK, 2002). Pre-drainage has historically been carried outusing
in-seam boreholes. Advance degassing from the surface has been trialed with limited success
because of the low permeability of the coal seams. The ArcelorMittal Temirtau Coal Division has
had recent success in increasing degasification rates, and hence coal production rates, by drilling
cross-measure boreholes from a roadway driven 8-12 m below the coal seam. Gob gas is drained
with vertical wells from the surface or via galleries driven 20-30 m above the seam
(Baimukhametov etal, 2009).
Current drained methane emissions are estimated to be approximately 130 million m3 resulting
from increased underground coal production rates (Alekseev, 2010), However, the level of methane
utilization is very low, only about 25 million m3 annually, which is recovered and combusted in the
boiler houses of five mines for mine heating. Surface mines are heavily ventilated and ventilation
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air with methane concentrations of about 1 percent is vented to the atmosphere (KazNIIMOSK,
2002).
CO2 emissions from coal mining related activities in 2010 were 1,507 million m3 (USEPA, 2012).
Coal mining related activities were 12.5 percent of the total 12,075 million m3 of CO2 emissions
released from the consumption of energy in 2010 (EIA, 2013).
Table 20-5 details Kazakhstan's measured and estimated CMM emissions. The data in this table may
vary from the USEPA data presented in the Executive Summary due to differences in inventory
methodology and rounding.
Table 20-5. Kazakhstan's CMM Emissions (million cubic meters)
Emission Category
2000
2005*
(estimated
assuming
breakdown
from 2000)
2010*
(estimated
assuming
breakdown
from 2000)
2015
(projected)
Underground coal mines - ventilation
286.23
472.3
601.8
emissions
Underground coal mines - drained
41
67.7
86.2
emissions
Post-underground emissions
8.0
13.2
16.8
Surface mine emission
381
628.7
801
Total liberated (= sum of all above]
716.23
1,182
1,506
1,629.4*
Recovered & Used
12.2
25**
Total emitted (= Total liberated - recovered
704.03
467
955**
& used]
Sources: KazNIIMOSK (2002]; *USEPA (2012]; **Shultz & Alekseev (2010]
20.2.2 CMM Emissions from Abandoned Coal Mines
At least 16 underground coal mines in Kazakhstan have been abandoned since 1995. All are
considered gassy and every abandoned mine is classified as a high hazard for coal and gas
outbreaks. Starting in May 2001, measurement and data processing for gas drain pipes at
abandoned shafts, pit-holes, and boreholes have been implemented at 12 abandoned mines in the
Karaganda and Abay-Shakhtinsk districts, some abandoned before 1995. In total, approximately
3,000 measurements of methane flow rate and concentration are taken each year and have proven
useful in understanding methane released during and after coal mining.
After abandonment some mines have been sealed better than others, thus resulting in varying
methane release rates. For example, the "50 Years of October Revolution" mine, which was
abandoned in 1998, has the highest methane content of any of the abandoned mines due to being
well-sealed both at the surface and between old connections in the underground mine area. No
specific information about methane recovery projects at abandoned mines is available but analysis
is being conducted to evaluate utilization options for an AMM project at the "50 Years of October
Revolution" mine (EU, 2009).
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20.2.3 CBM from Virgin Coal Seams
According to the Ministry of Energy and Mineral Resources, Kazakhstan's CBM resources are some
of the highest among the coal basins of the world, as illustrated in T able 20-6.
Table 20-6. Summary of Kazakhstan's Selected CBM Resources
Basin or Field
CBM Resources (est.)
(billion cubic meters)
Karaganda Basin
550 - 750
Ekibastuz Basin
75 - 100
Zavialov Field
14.6 - 16.8
Samarskiy Field
11.0-14.2
Source: Stoupakand Zhukovskiy (2001}
Kazakhstan is one of the few countries actively pursuing to initiate commercial CBM production.
Figure 20-2 shows Kazakhstan's coal regions with estimated methane reserves for each region.
Figure 20-2. Kazakhstan Coal Regions and Coal Methane Reserves
»• Karasay »• X"4 I I Cenozolc
Coal Methane Reserves (billion.cub.m)
Source: Alekseev, et al. (2003)
Zhumys-Stroyservice LLP was awarded a CBM license in 2008 and proceeded with a pre-feasibility
assessment (by Schlumberger) and drilled a few pilot wells with a minor gas yield reached so far.
Zhumys-Stroyservice, announced (May, 2010) an agreement with the Australian company Arrow
Energy Ltd., to perform a feasibility study on the commercial production of CBM in the Karaganda
coal basin. Funding would be provided by Arrow Energy with plans for a pilot project to be
launched in 2014 (SteelGuru, 2010}.
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In April 2003, the former Ministry of Energy and Mineral Resources recommended that
BogatyrAccess Komyr, Ltd. and Azimut Energy Services, Ltd. pursue a CBM development effort in
the Ekibastuz basin. However, the project was ultimately suspended.
20.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Kazakhstan is a signatory to both the UNFCCC and the Kyoto Protocol (see Table 20-7). Kazakhstan
applied for Annex I status in June 1999, withdrew its application in June 2000, but finally ratified
the Protocol in March 2009. With Annex I status obtained, new CMM projects in Kazakhstan are
eligible to earn and sell emission reduction credits through the Clean Development Mechanism.
Until Kazakhstan is a member of Annex B, their domestic emissions trading system can only affect
their domestic market (EDF, 2014). Kazakhstan is currently awaiting status as an Annex B country.
Investment for CMM projects could also come from the National Innovation Fund, mine operators,
and foreign investors (Zhasyl Damu 2014).
Table 20-7. Kazakhstan's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 8.1992
May 17,1995
Kyoto Protocol
March 12,1999
March 26,2009
Source: UNFCCC (2014]
The Kazakh Emissions Trading Scheme (ETS) was enacted into law on December 3, 2011, through
an amendment to the country's "Ecological Code" (IETA, 2013). In January 2013, the ETS was
launched for a one year pilot phase. The program entered its second, two-year phase in January
2014. According to reports, the first allowance transaction took place on 28 March 2014, trading at
the price of 455 Tenge (about $2.60) (ICAP, 2014). The Government of Kazakhstan expects about
180 large GHG emitters (mainly industrial enterprises) to be covered under the new environment
code starting in 2015. The first official trading session in early 2014 generated a carbon price of
USD2.50/tCO2e (Zhasyl Damu 2014). Kazakhstan is also working on a domestic offset system for
specific sectors and gases (e.g. CH4) not covered by the scheme.
Reports are that international credits may be allowed in the future, subject to approval of the KAZ
CP2 (ICAP, 2014).
20.3.1 Market and Infrastructure Factors
Opportunities to develop the country's coal bed methane (CBM) and CMM resources are a
potentially significant source of investment, and Kazakhstan is working to establish an attractive
investment climate. The Kazakhstan government prioritizes CMM projects as a means of achieving
measurable and verifiable greenhouse gas emission reductions. Recently the government approved
proposals for establishing criteria and procedures for screening, review, and approval of GHG
emission reduction projects. It also approved similar proposals relating to baseline assessment and
validation; emission reduction calculation; monitoring verification, and registering emission
reduction projects; and allocating 5 million metric tons of CO2 equivalent (MMTCC^e) for transfer to
<
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investors in GHG reduction projects. As a next step, the government will promulgate regulations
(USEPA, 2005).
Kazakhstan will require significant infrastructure investments to commercialize CBM and CMM
development. Gas gathering systems will be required as well as interconnects with distribution
pipelines. Some synergies may be available with rapidly developing gas production associated with
expanding oil production. Kazakhstan produced 1.4 Tcf of natural gas in 2011. Between 2008 and
2010 Kazakhstan produced sufficient volume of dry gas to satisfy its domestic demand, although
increased domestic consumption resulted in Kazakhstan becoming a net gas importer again in 2011
(EIA, 2013). Production has been growing at 22 percent annually over the last decade, compared to
consumption growth of 9 percent annually, and Kazakhstan is, therefore, expected to become a net
exporter of gas within the next few years. Current and proposed major gas distribution pipelines
are routed mainly in the west and south of the country and so opportunities for local CMM/CBM
projects in the central and northern coal-fields may arise as a result of proximity to underserved
markets in these areas. Regional gas demands are increasing, especially from neighboring China,
suggesting adequate markets for all methane that can be produced. Possible end uses for recovered
methane include industrial boilers, power generation, heating and transportation fuel (for fleets
and private vehicle conversions).
In 2005,14,609 million KZT was invested in the mining industry. A large portion of those
investments, 5,998 million KZT, went into coal production and improvement (CMAR, 2006). In
2007, the ArcelorMittal Group pledged to invest 500 million USD to increase coal production in the
Karaganda region by around 5 Mmt. These large investments in the nation's coal production could
lead to increased CMM development projects.
20.3.2 Regulatory Information
The Government owns all subsurface gas and minerals but has allocated coal reserves to private
mine operators as part of their contracts and CMM to contracted coal operators. CMM and CBM
project developers must enter into agreements with the coal operators for development and sale of
the gas resources (KMIC, nd). Upcoming petroleum legislation and provisional rules for exploration
and development will provide a comprehensive and consistent legal framework for CBM
exploration and exploitation. At this time, no legislation is in place which distinguishes CMM/CBM
production from that of natural gas. When CMM is moved offsite of the mine, it is treated by the
same rules and taxes that apply to natural gas. A recent law, "In Support of the Use of Renewable
Energy Resources" introduced in July 2009, does not include references to CMM (Alekseev, 2010).
Kazakhstan is in the process of developing a new mining code in which CBM and CMM are expected
to be included.
Mining companies understand the safety issues and are becoming increasingly familiar with the
environmental issues associated with CMM. Coal mine safety is a key concern in surface and
underground mines - numerous deaths due to mine explosions and methane outbursts underscore
the importance of this problem. Environmental legislation exists that require pollution permits and
payment of pollution fines for coal mining activities. Environmental and safety standards are
improving, but are also driving up development costs.
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20.4 Profile of Individual Mines
Kazakhstanskaya Mine
Mine Status
Active
Operator/Owner
ArcelorMittal Temirtau
Coal Division
Mine Area
47 km2
Coal Basin
Karaganda
Mining Method
Conventional Longwall
Location
Shakhtinsk District, 30 km
west of the city of
Karaganda
Reserves (coking coal)
103.4 Mt
2011 VAM volume
29.3 million m3 per year
No. of seams mined
2 (D6&D10)
2011 Drained volume
10.4 Mm3/y
Depth of seams
650-700 m
2009 Utilized volume
Utilization method
7.8 Mm3/y
Boilers
Lenina Mine
Mine Status
Active
Operator/Owner
ArcelorMittal Temirtau
Coal Division
Mine Area
10.7 km2
Coal Basin
Karaganda
Mining Method
Conventional Longwall
Location
Shakhtinskiy District, 60
km west of the city of
Karaganda
Reserves (coking coal)
65.6 Mt
2011 VAM volume
38.1 million m3 per year
No. of seams mined
8 (Dl-Dll]
2011 Drained volume
24.3 Mm3/y
Depth of seams
650 - 700 m
Utilization method
Boilers, Power Generation
Abaiskaya Mine
Mine Status
Active
Operator/Owner
ArcelorMittal Temirtau
Coal Division
Mine Area
34.45 km2
Coal Basin
Karaganda
Mining Method
Conventional Longwall
Location
Abai District, 35 km from
the city of Karaganda
Reserves (coking coal)
81.6 Mt
2011 VAM volume
25.9 million m3 per year
No. of seams mined
6 (K18, K13, K12, K10,
Kll, K7]
2011 Drained volume
44.3 Mm3/y
Depth of seams
549 m
Utilization method
Boilers
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Tentekskaya Mine
Mine Status
Active
Operator/Owner
ArcelorMittal Temirtau
Coal Division
Mine Area
71.47 km2
Coal Basin
Karaganda
Mining Method
Conventional Longwall
Location
Shakhtinskiy District, 60
km from the city of
Karaganda
Reserves (coking coal)
134.9 Mt
2011 VAM volume
12.8 million m3 per year
No. of seams mined
2 (D6&T1)
2011 Drained volume
10.1 Mm3/y
Depth of seams
230-350 m
Utilization method
Boilers
More information about these mines of the Karaganda Coal Basin can be found at
http://www.epa.gov/cmop/docs/Karaganda.pdf.
20.5 References
Alekseev, et al. (2003): Coal Methane: Potential Energy Prospects for Kazakhstan, Alekseev, E.G., R.K. Mustafin
and N.S. Umarhajleva, presented to UNECE Ad Hoc Group of Experts on Coal in Sustainable Development,
Almaty, Kazakhstan, 17 November 2003. www.unece.org/ie/se/pp/coal/mustafin.pdf
Alekseev (2010): Personal communication.
Baimukhametov, D., Polchin, A., Dauov, T. & Ogay, S. (2009): Gate Road Development in High Gas Content Coal
Seams at Karaganda Basin Coal Mines, Kazakhstan, In Aziz, N (ed) Coal 2009: Coal Operators' Conference,
University of Wollongong & the Australasian Institute of Mining and Metallurgy, pp 90-95,2009.
http://ro.uow.edu.au/coal/85
Baimukhametov, Sergazy (2014): "ArcelorMittal Temirtau" JSC Coal Division Issues in Terms of Coal Mine
Methane," presented to 9th Session of UNECE Group of Experts, Geneva, Switzerland, October 2014.
www.unece.org/fileadmin/DAM/energy/se/pp/coal/cmm/9cmm oct2014/5 Baimukhametov.pdf
BP (2013): Statistical Review of World Energy, June 2013.
http://www.bp.com/content/dam/bp/pdf/statisticalreview/statistical review of world energy 2013.p
df
CMAR (2006): Strategy of Territorial Development of the Karaganda Oblast Until 2015, Center for Marketing
and Analytical Research, JSC, 2006.
EDF (2014): The World's Carbon Markets: A Case Study Guide to Emissions Trading, Environmental Defense
Fund and International Emissions Trading Association, Washington, DC, March 2014.
http://www.edf.org/sites/default/files/Kazakhstan-ETS-Case-Study-March-2014.pdf
EIA (2007): Data obtained from International Energy Annual 2005. U.S. Energy Information Administration,
Washington, DC, table posted 21 June 2007.
EIA (2009): Kazakhstan Country Analysis Brief, U.S. Energy Information Administration, November 2009.
EIA (2013): Kazakhstan Country Analysis Brief, U.S. Energy Information Administration, Washington, DC,
October 2013. http:IIwww.eia.gov/countries/cab.cfm?fips=KZ
Energy Charter Secretariat (2013): Investment Climate and Market Structure Review in the Energy Sector of
Kazakhstan, 2013.
http://www.encharter.org/fileadmin/user upload/Publications/Kazakhstan ICMS 2013 ENG.pdf
^ ,
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EOK [2010]: Energy Sector - Coal, Embassy of Kazakhstan, Washington, DC, website accessed July 2010.
http://www.kazakhembus.com/index.php?page=energy-sector
EU (2009): Potential analysis for CMM utilization in Kazakhstan and concepts for CMM utilization, October
2009.
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.glohalmethane.org/coal-mines/cmm/index.aspx
ICAP (2014): Kazakhstan Emissions Trading Scheme (KAZ ETS), International Carbon Action Partnership, 27
October 2014.
https://icapcarbonaction.com/index.php?option=com etsmap&task=export&format=pdf&layout=list&sy
stems%5B%5D=46
IETA (2013): The World's Carbon Markets: A Case Study Guide to Emissions Trading - Kazakhstan,
International Emissions Trading Association, September 2013.
http: //www.ieta.org/assets/Reports/EmissionsTradingAroundTheWorld/edf ieta kazakhstan case stud
v September 2013.pdf
KazNIIMOSK (2002): Kazakhstani GNG Emissions Inventory from Coal Mining and Road Transportation -
Final Project Report, Kazakh Research Institute for Environment Monitoring and Climate (KazNIIMOSK),
Almaty, July 2002.
KMIC (nd): Pilot CBM Extraction Project in Taldykuduk Area of Central Kazakhstan, Kazakhstan Methane
Information Center, not dated.
State (2005): 2005 Investment Climate Statement - Kazakhstan, U.S. Department of State, 2005.
Shultz, K. and Alekseev, E. (2010): The Role of Policy on CMM Project Development: Ukraine and Kazakhstan
as Case Studies. Presented at International Investment Forum: Funding of CMM Project in Ukraine.
Donetsk, Ukraine, 3 June 2010.
Stoupak and Zhukovskiy (2001): Coalbed Methane in Kazakhstan: Investment Opportunities, Stoupak,
Serguei and Valeriy Zhukovskiy, presented in January 2001.
UNECE (2008): Final Technical Report: Project for the Development of Coal Mine Methane Projects in Central
and Eastern Europe and the Commonwealth of Independent States. Submitted to the U.S. Environmental
Protection Agency by the United Nations Economic Commission for Europe, December 2008.
UNFCCC (2014): Status of Ratification - Kazakhstan, United Nations Framework Convention on Climate
Change, accessed July 2014. http://maindb.unfccc.int/public/country.pl?countrv=KZ
USEPA (2005): Correspondence between Saule Arapova, Director, National Innovation Fund, and Mr. Clark
Talkington, U.S. Environmental Protection Agency, Coalbed Methane Outreach Program, 2005.
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990 - 2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2010): The Mineral Industry of Kazakhstan, 2007 Minerals Yearbook, U.S. Geological Survey, by Levine,
R.M., Brininstool, M. and Wallace, G.J., May 2010.
http://minerals.usgs.gOv/minerals/pubs/country/2007/myb3-2007-kz.pdf
USGS (2011): The Mineral Industry of Kazakhstan, 2009 Minerals Yearbook, U.S. Geological Survey, by Levine,
R.M., Brininstool, M. and Wallace, G.J., December 2011.
http://minerals.usgs.gOv/minerals/pubs/country/2009/myb3-2009-kz.pdf
Zhasyl Damu (2014): Information on the Kazakhstan CO2 trading scheme, accessed July 2014.
http://zhasyldamu.kz / en/activities / greenhouse-gases / activities.html
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21 Mexico
21.1 Summary of Coal Industry
21.1.1 Role of Coal in Mexico
Coal is a relatively small component of Mexico's energy production and consumption, compared to
petroleum and natural gas. In 2012, coal accounted for only five percent of total energy
consumption while oil and natural gas made up 53 percent and 36 percent, respectively (EIA,
2014). Coal is used primarily for steel production and electric power generation. According to
Mexico's Energy Secretariat, while natural gas is still the dominant feedstock for electricity
generation, coal consumption by the electricity sector had risen to 320 trillion British thermal units
(Btus) in 2013 (EIA, 2014).
Annual coal production in Mexico increased from 10.8 million tonnes (Mmt) in 2005 to 15.2 Mmt in
2012, with estimated proved coal resources of 1,210 Mmt at the end of 2011 (see Table 21-1).
Table 21-1. Mexico's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million
tonnes)
Sub-
bituminous &
Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
859
351
1,210
25 (0.14%]
Annual Coal Production (2012]
15.2
0
15.2
25 (0.19%]
Source: EIA (2013]
Figure 21-1 shows the distribution of coal fields, while Table 21-2 outlines the key characteristics of
the major coal basins. As seen, the majority of Mexico's coal reserves are located in Coahuila State in
the northeast part of the country. Additional resources are located in Sonora (in northwest Mexico)
and Oaxaca (southern Mexico).
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Figure 21-1. Mexico's Coal Fields
Source: Adapted from Santillan (2006)
Bituminous
Coal
Coking
Coal
Lignite
Bitumen
. Localities with Region with
evidence of coal evidence of
coal
Table 21-2. Mexico's Major Coal Basins
State
Basin / Sub-basin
Age
Usage
Resources
(million tonnes)
Coahuila
Oaxaca
Sonora
Chihuahua
Coahuila / Sabinas-Saltillo-
Monclova
Fuentes-Rio Escondido
Colombia-San Ignacio
Mixteca
Barranca
Cabullona
San Pedro Corrallitos
Maestrichtian
Maestrichtian
Eocene
Triassic - Jurassic
Triassic - Jurassic
Maestrichtian
Maestrichtian
Metallurgical
Steam
Bituminous
1,180
1,216
252
163
143
80
6
3,154
66
83
17
Total
*3,040 **3,320
Sources: *Querol-Sune (2001); ** Cabrera [2009]
21.1.2 Stakeholders
The key stakeholders involved with the coal industry and the coal mine methane (CMM) and coal
bed methane (CBM) industries are listed in Table 21-3.
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Table 21-3. Key Stakeholders in Mexico's CMM Industry
Stakeholder
Category
Stakeholder
Role
Mining
Minera del Norte, SA de CV (MINOSA]
Major mining company in Mexico. MINOSA
Companies
produces a large percentage of Mexico's
coking coal. It is part of Grupo Acerero del
Norte (GAN]
¦ Minera Carbonifera Rio Escondido (MICARE]
MICARE produces steam coal and is also a
part of GAN
Grupo Mexico S.A.B. de C.V. (Sociedad Anonima
Largest mining corporation (mainly
Bursatil de capital variable - limited liability stock
copper] in Mexico
corporation with variable capital]
Developers
See
Project opportunity identification and
http://www.epa.gov/coalbed/networkcontacts.html
planning
Engineering,
REI Drilling Inc.
Technical assistance
Consultancy
HEL-East Ltd.
and Related
Advanced Resources International, Inc.
Services
Caterpillar
Biogas Technology Ltd.
See also
http://www.epa.gov/cmop/networkcontacts.html
Government
Mexican Electricity Commission (CFE]
Regulatory
Agencies
Energy Regulatory Commission (CRE]
Petroleos Mexicanos (PEMEX]
Secretariat of Economy
Secretariat for Environment and Natural Resources
Ministry of Energy
Comision Federal de Electricidad
21.1.3 Status of Coal and the Coal Mining Industry
Coal has contributed substantially to the development of industry in Mexico, starting with the
development of the railroad industry. Although coal was largely replaced by oil from 1910 to 1954,
it remained a major raw material for the steel industry. The mining of iron-ore and coal started
formally with the development of the Mexican steel industry in 1930. Coal mining in Mexico
increased considerably with the opening of coking facilities in 1954 and in 1959, and a fertilizer
plant was opened in Monclova that used gas emitted from the coking facilities.
Starting in 1960, the Energy Regulatory Commission developed a program to generate electricity
through two coal-operated thermoelectric power stations, which were installed in Nava, Coahuila,
between the late 1970s and the early 1990s. This program led to extensive coal exploration in the
Fuentes-Rio Escondido Basin of Northern Coahuila and an increase in coal mining activities
(Verdugo, 1991).
In 1992, passage of the Mexican Mining Law allowed 100 percent private ownership of coal mines
by both Mexican interests and foreign mining companies. Government-owned Minera Carbonifera
Rio Escondido (MICARE) was privatized in 1992 and is now a subsidiary of Altos Hornos de Mexico
(AHMSA), a large integrated steel company based in Coahuila state. Minera del Norte (MINOSA),
Mexico's principal producer of metallurgical coal is also a subsidiary of AHMSA, which is in turn
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controlled by Grupo Acerero del Norte (GAN), a corporation focusing on steel production, and the
mining of coal and copper.
MINOSA was formerly the name of the subsidiary operating AHMSA's iron ore mines and Minerales
Monclova (MIMOSA) operated AHMSA's coal interests. GAN now operates all their mines under
MINOSA. The GAN mines together produced about 82 percent of Mexico's coal in 2013. Other
important mining companies with coal interests include Grupo Mexico and Carbonifera de San
Patricio (Santillan, 2014).
21.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies two
active CMM recovery projects and three proposed CMM recovery projects in Mexico. All of the
projects, but one, are designed for active underground mines. The operational projects use
captured methane for boiler fuel and flaring while the proposed projects are designed to use
captured methane for power generation and flaring (GMI, 2014).
21.2.1 CMM Emissions from Operating Mines
In November 2006, Mexico submitted its third National Communication reporting 1.39 MTC02e of
fugitive methane emissions from solid fuels for 2002 (IPCC Source Category 1B1) and another
36.69 MTC02e from petroleum and natural gas and a total of 389.50 MTC02e from all energy
consumption (Category 1B2) (UNFCCC, 2006). In the fifth communication in December 2012,
Mexico reported that total emissions amounted to 748.252 MTC02e in 2010. The energy sector
accounted for 67.3 percent (503.817 MTC02e), of which, 48.8 percent was from the energy industry
and fugitive emissions (SEMARNAT, 2012).
Estimates for emissions specific to coal mining activities have varied. The National Greenhouse Gas
Inventory 1990-2002 reported 1.56 MTC02efrom coal mining activities in 2002 (Category lBla)
(UNFCCC, 2007). According to the Mexican environment ministry's undersecretary for
environmental norms, approximately 2.14 MTC02e of methane had been liberated from coal mines
into the air each year (Bremer, 2006). These numbers differ slightly from U.S.EPA estimates for
emissions related to coal mining activities of 1.729, 2.157, and 2.353 MTC02e for the years 2002,
2005, and 2010, respectively. An emissions estimate of 1.836 MTC02e is predicted for 2015 (USEPA,
2012).
Table 21-4 shows CMM emissions in Mexico. The data in this table may vary from U.S. EPA data
presented in the Executive Summary due to differences in inventory methodology and rounding.
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Table 21-4. Mexico's CMM Emissions (million cubic meters)
Emissions
2000
2005*
2010*
2015*
(projected]
Underground mining
109.54
Surface mining
4.70
Underground Post-
mining
6.76
Total CH4 Emitted
121.01
145.71
158.95
124.06
Sources: Flores (2007], *USEPA (2012]
MINOSA (formerly MIMOSA) operates five underground mines in the gassy coals of the Upper
Cretaceous Los Olmos Formation in the state of Coahuila in northern Mexico and has been draining
the coal beds prior to mining through in-seam horizontal boreholes since 1992, with efficiency
above 30 percent (Brunner, 1999). MINOSA has several active CMM gas drainage projects and has
been very progressive in their pursuit of reducing methane emissions from their mining operations.
In addition to a boiler operation at the Esmeralda mine, MINOSA began operating the first CMM
flare atan active coal mine in September 2011 (CDM, 2014).
The MINOSA flaring project destroys mine methane from gas drainage systems at three of its mines
in northern Mexico (CDM, 2014):
¦ 1 flare at the Esmeralda Mine (Mine 5) in the Saltillo Basin commissioned in October 2012
¦ 1 flare at Mine 6 (Sabinas Basin) commissioned in April 2014
¦ 1 flare at Mine 7 (Sabinas Basin) commissioned in September 2011
The mines have been in operation for 15 years, with annual coal production totaling 3.9 million
tonnes per year. According to MINOSA, the mines have a remaining life of more than 20 years.
Although the coal industry of Mexico is relatively small with 15 million tonnes of coal mined per
year, the coal mines of northern Mexico are notoriously gassy and these three mines are among the
gassiest
Recent estimates by Mexican experts suggest that combined emissions from the mines total 208
million cubic meters (m3) of methane, which is significantly greater than emissions projected by
EPA in Table 21-4 (Santillan, 2013). This equates to an average specific emission rate of about 50
m3 per tonne of coal mined with a range of 30 m3 to 60 m3 at current production rates (CDM, 2014).
Internationally, the often accepted standard for a "gassy" mine is 10 m3 per tonne, which gives an
indication of the challenges facing MINOSA and other coal producers in Mexico.
The high gas content of the coal has resulted in a sustained effort by MINOSA to address methane
issues through employment of a holistic approach targeting gas drainage systems and mine
ventilation air. The mine ventilation systems at the mines account for 70 percent of the methane
liberated at the three mines, with the remainder of emissions coming from methane drainage
systems (CDM, 2014). MINOSA's gas drainage program entails a range of degasification methods
including surface vertical pre-drainage wells, surface to inseam directional drilling surface gob
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wells, and in-mine long hole directional boreholes that is proving very effective. Methane
concentrations in the drainage system average 95 percent according to Santillan (Santillan, 2013).
As a first step in a comprehensive program designed to manage its CMM emissions, MINOSA
constructed the flares at Mine 7 and Mine 5, and finally, Mine 6. The projects are sited at fixed
locations and are enclosed flares (also known as ground flares) where the flame is contained within
the stack and is not visible. The projects include 9 meter stacks and have a total combined
throughput capacity of 6,000 Nm3/hour (1 flare per mine x 2,000 Nm3/hour/flare).
The equipment contains important safety features such as flame arrestors. The flares are also
designed to stop operating when the oxygen concentration reaches 6 percent, the combustion
temperature reaches 1200 °C, or the pressure reaches 200 mbar. Currently MINOSA anticipates a
project life of seven years.
Thus far the three projects have performed at 7 percent (Mine 5), 24 percent (Mine 6) and 90
percent (Mine 7) availability, respectively (CDM, 2014), and with nearly 100 percent destruction
efficiency and no reported operational problems (Santillan, 2013). CMM emission reductions
totaled 13,660 tC02e in 2012 (Santillan, 2013) and 87,865 tC02e from October 2013 through
October 2014 (CDM, 2014).
With the implementation of a comprehensive mine gas drainage program and the deployment of
flares at three of its mines, MINOSA has taken the initial steps in what is expected to be one of the
most comprehensive and ambitious CMM projects worldwide. Ultimately the company expects to
operate CMM flares at other MINOSA mines, generate power from CMM and employ VAM oxidation
to minimize its carbon footprint. Expected emission reductions from the integrated project are
expected to be around 3.1 million tC02e once the project is fully implemented. The project was
approved by the United Nations CDM Executive Board and the company is now monetizing the
carbon credits generated by the project
MINOSA also has developed several previous CMM projects involving their No.5 (Esmeralda), No.6
and No.7 mines. A total of almost 10 kilometers (km) of in-seam drainage holes were drilled at the
three mines, along with 52 gob wells in Mine 5 and 23 gob wells in Mine 6 (Santillan, 2010). In
1991, more than 3,000 meters of in-seam horizontal drainage boreholes were drilled in advance of
mining development at the Pasta de Conchos mine in the Coahuila coal region. The project was
successful in reducing the methane concentration in return ventilation air from 1 percent to 0.8
percent and had a peak methane production rate of 45,000 m3 per day (WME, 1994). An expanded
CMM/CBM development program was under consideration by the mine owners, Grupo Mexico,
including analysis of various end-use options. However, in February 2006, the mine experienced a
lethal methane explosion that killed 65 miners and the mine was closed (El Universal, 2007). This
mine disaster led to increased awareness of CMM drainage issues and a revision of Mexican mining
law (see section 21.3.2).
MINOSA is currently planning on developing a new mine area, "Conchas Sur," which is projected to
be as gassy as their current mines. U.S. EPA recently funded a pre-feasibility study to look at the
technical and economic aspects of pre-mine drainage for this new mine complex.
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21.2.2 CMM Emissions from Abandoned Coal Mines
MINOSA has closed several gassy mines in Northern Mexico, and these mines are believed to
present excellent opportunities for abandoned mine methane (AMM) projects. In addition, mines
controlled by other companies that were gassy during operation also exist in the Sabinas Basin and
likely present good AMM opportunities. However, it is important to note that there is no definitive
data on AMM emissions and potential at this time and project development would require
substantial due diligence. In addition, recovery of AMM would be probably be independent of active
mining operations and would likely fall under traditional oil and gas regulation.
A 2010 presentation by MINOSA indicates that the company has considered an AMM project at their
No.2 mine in the Sabinas basin. MINOSA estimated emissions from the mine to be 4.1 million m3 per
year (100 percent methane). The project envisions utilizing the methane for power generation and
selling the produced electricity to the grid or using it to power maintenance depots at the mine site
(Santillan, 2010). MINOSA, though, has prioritized developing flaring and power generation at its
active mines, and thus far has not pursued AMM project development at the No. 2 mine or any other
of its closed mines (Santillan, 2014).
21.2.3 CBM from Virgin Coal Seams
The coal in Mexico can be quite gassy. MINOSA reports an average in situ content of gas in the coals
of the Sabinas Sub-basin at 10 to 14 m3 per tonne and 12 to 18 m3per tonne in the coals of the
Saltillo Sub-basin (Santillan, 2004). Methane content in the gas is usually above 97 percent Total
gas resources in the Maestrichtian coals of Coahuila are estimated between 122 and 220 billion m3
(Santillan, 2004).
Very little published data are available for CBM in Mexico. It is apparent from the quality of coal
that the basins of Coahuila are the most promising sources of CBM because of their relatively high
gas contents, moderate permeability, and relatively shallow depth. Mexico's CBM reserves are
estimated at between 4.2 and 7.5 trillion cubic feet and are concentrated in the northern states of
Coahuila and Sonora, according to the Economic Ministry's mining division.
Until the change in the mining law in 2006, only the state owned oil and gas monopoly, Petroleos
Mexicanos (PEMEX) had the right to exploit Mexico's natural gas resources, including CBM. PEMEX
has done several studies on the potential of CBM in the Sabinas Basin region, but their data are not
publically available. They have invested little in CBM extraction, focusing on their core business of
oil and conventional gas extraction (Barclay, 2006). The major coal companies had little incentive
to research CBM drilling prior to 2006 focusing instead on CMM emissions. MINOSA has done
significant research regarding the potential of CMM in the Sabinas Basin and appears, at this time,
to be following up on potential CMM projects rather than ones involving CBM extraction.
The Mexican government has recently proposed new regulations for the oil and gas industry which
are intended to further liberalize the sector and promote private investment and development. The
passage of this new legislation should provide added incentives for CMM and CBM development
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21.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Mexico is a signatory to both the UNFCCC and the Kyoto Protocol (see Table 21-5). As a Non-Annex
I Party to the Kyoto Protocol, Mexico has no national emissions targets but is eligible to host
mitigation projects under the Clean Development Mechanism (CDM). The MINOSA CMM flaring
project is currently the only CMM/CBM project in Mexico registered under the CDM (UNEP, 2010).
Table 21-5. Mexico's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 13,1992
March 11,1993
Kyoto Protocol
June 9,1998
September 7,2000
Source: UNFCCC (2014]
21.3.1 Market and Infrastructure Factors
PEMEX's natural gas network currently exceeds 93,032 km (PEMEX, 2011) and has 12 compression
stations. There were 13 natural gas interconnection stations between Mexico and the United States
at the end of 2013, with atleasttwo newpipeline interconnections planned (EIA, 2014). Natural
gas import capacity was increased when two new pipelines came on-stream during 2003 and in
2012 Mexico imported 620 billion cubic feet (Bcf) of natural gas from the United States (EIA, 2014).
Currently, all proposed CMM utilization projects are limited to coal mine operations and local
power generation and not to pipeline sales.
If it were on the market, CMM would compete directly with other supplies of natural gas in Mexico,
which come from various natural gas basins and as associated gas from increasing onshore and
offshore oil production. Rising natural gas prices and increasing gas demand for expanding power
generation capacity are expected to make CMM and CBM prices competitive with natural gas and
other resources, including coal. Market access for CMM is currently limited by legal requirements
that hydrocarbon resources be handled through contracts with PEMEX.
21.3.2 Regulatory Information
Mineral exploration and mining in Mexico are regulated by the Mining Law of 1992 (as amended in
2006), which establishes that all minerals found in Mexican territory are owned by the Mexican
nation, and that private parties may exploit such minerals (except oil and nuclear fuel minerals)
through mining licenses, or concessions, granted by the Federal Government
Before 2006, Mexico's Constitution (Article 27), enacted through the Ruling Law on the Subject of
Hydrocarbons required that all exploration, recovery, processing and sales of methane were to be
managed by PEMEX. Therefore, coal mines did not have the right to sell CMM or to use CMM to
generate heat or electricity on site.
However, changes to this regulatory barrier have been made. Media attention to the dangers posed
by CMM was triggered by an explosion at Pasta de Conchos coal mine in Coahuila in February 2006
that killed 65 miners. Following this disaster, the Congress and the Senate quickly passed an
amendment to the Mining Law (April 2006), allowing coal mines to recover and use CBM, CMM,
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AMM, and ventilation air methane from their coal mining operations for any purpose. The
amendment also allowed the concessionaires to sell the gas to PEMEX through a contract (Flores,
2007).
The regulations were further adjusted by an amendmentto the Mining Law on June 26, 2006 which
allows holders of coal mineral concessions to recover and use methane in order to stop methane
venting. Methane can be used on-site and/or delivered to PEMEX, which is required to pay
justifiable market rates for recovery, transportation, operation and maintenance plus a reasonable
profit Holders of CMM concessions are contracted to report on the start and suspension of any
activities, collect geological data, report on discovery of non-associated gas, and deliver captured,
non-self-consumed CMM to PEMEX (Flores, 2007; LatinPetroleum, 2006).
A new law, "Safety for Underground Mines" (NOM-STPS-032-2008), was passed in 2008 and
contained rules for obtaining permits and authorizations that grant the use and recovery of coal
mine gas (Cabrera, 2009; Briseno, 2009). The Secretaria de Energia (SENER) is the agency in charge
of authorizing and monitoring CBM/CMM activity, and issues permission for the recovery and
utilization of CBM. SENER will also issue contracts for the delivery of gas to PEMEX; establish terms
for payment for the delivery of gas, and is charged with developing policies for recovery and
utilization of CBM (Roldan, 2009).
The Mexican government recently staked out three large regions and designated them for CBM
development The staking is a response to the changes to the Mining Law passed in 2006, and seeks
to assert the primacy of CBM resources in these areas. Until the concessions are put up for auction,
the reservation of these areas will be an impediment to other mining development (Wood, 2007).
Figure 21-2 shows an estimate of the outlines of the staked regions.
Figure 21-2: Estimated Boundaries of Recent CBM Staking
by the Mexican Government
Source: Wood (2007]
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21.4 Profiles of Individual Mines
Mexico has seven significant coal basins spread across the country. Two-thirds of the country's
resources are located in Coahuila where most of the active mining is taking place. Table 21-6 shows
the coal characteristics ofthe different coal basins inMexico andTable 21-7 gives a jointprofile of
three MINOSA mines in the Sabinas basin.
Table 21-6. Coal Characteristics of Mexican Coal Basins
Site
Carbon
%
Volatile
Matter
%
Ash
%
Sulfur
Total
%
Moisture
%
Calorific
Value
Btu/ kg
Resources
On Site
(million
tonnes)
Sabinas-Saltillito-Monclova Sub-Basins,
Coahuila
45.61
16.97
40.43
1.0
1.26
5,897
1,180
Fuentes-Rio Escondido Basin, Coahuila
32.07
30.50
33.27
4.16
3,740
1,216
Colombia-San Ignacio Basin, Coahuila
32.4
42.6
44.0
3.5
4.10
5,053
252
Mixteca Basin, Oaxaca. Areas:
- Plaza de Lobos
-Plancha-el Consuelo
31.11
6.92
60.30
0.26
1.05
163
- San Juan Viejo
29.75
40.14
6.02
10.07
63.11
49.13
0.25
0.28
0.82
0.47
Barranca Basin, Sonora
77.3
4.8
10.6
0.37
8.0
5,216
143
Cabullona Basin, Sonora
67.45
9.92
18.86
0.00
3.76
4,107
80
San Pedro Corralitos Basin, Chihuahua
27.37
26.75
45.86
0.34
18.2
6
Total
3,040
Source: Flores-Galicia (2001]
Table 21-7. Profile of MINOSA Mines V, VI & VII
MINOSA Mines - 5, 6, and 7
Mine Status
Mining Method
Depth of Seams
No. of Seams
Seam Thickness
2008 Coal Production
Active
Longwall
120-150 m
2 - Olmos Fmtn
1.2-3.5 m (total]
3.5 million tonnes
Mine Owner
Parent Company
Location
2008 VAM Volume
2008 Drained CH4 Volume
2008 Utilized CH4 Volume
MINOSA Mines
Altos Hornos de Mexico
Sabinas Coal Basin, Coahuila
128. Mm3
6.41
0
Coal Production (thousand
tonnes/yr]
Methane (million m3/yr]
Emitted from ventilation systems
Liberated from drainage systems
Total Methane Emissions
2000
1714.6
42.40
3.90
46.3
2001
2093.7
81.13
4.82
85.95
2002
1910.9
107.73
13.44
121.17
2003
1319.7
101.18
20.11
121.29
2004
1814.2
107.7
4.82
112.52
2005
1641.9
128.2
13.4
141.6
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Table 21-7. Profile of MINOSA Mines V, VI & VII
MINOSA Mines - 5, 6, and 7
Coal Production (thousand
tonnes/yr]
Methane (million m3/yr]
Emitted from ventilation systems
Liberated from drainage systems
Total Methane Emissions
Coal Production (thousand
tonnes/yr]
Methane (million m3/yr]
Emitted from ventilation systems
Liberated from drainage systems
Total Methane Emissions
2006 2007 2008
2676.9 1897.2 2586.9
118.1 102.3 128.4
20.1 14.18 6.41
138.2 116.4 134.8
2012* 2013* 2014*
5,654 4,603 5,444
0 0 0
111.3 111.3 111.3
22.1 22.1 22.1
133.4 133.4 133.4
2009* 2010* 2011*
3,992 3,641 4,008
111.3 111.3 111.3
22.1 22.1 22.1
133.4 133.4 133.4
*Projected from Mina La Esmeralda, Mina VI, and Mina VII (GMI, 2010]
Profiles of five potential CMM projects in Mexico have been presented as project posters at GMI Expos can be found at:
MIMOSA power and flaring project (Beijing Expo 2007]
https://www.globalmethane.org/activities/actDetails.aspx?ID=269
CMM Recovery and Use at MIMOSA mines (New Delhi Expo 2010]
https://www.globalmethane.org/activities/actDetails.aspx?ID=1080
Advanced Gob Gas Drainage at MIMOSA Mines (New Delhi Expo 2010]
https://www.globalmethane.org/activities/actDetails.aspx?ID=1081
MIMOSA CMM Project (Sabinas Basin, Coahuila, Mexico] (Vancouver Expo 2013]
https://www.globalmethane.org/expo-docs/posters/CoalMines/CM MX Project Mimosa FINAL.pdf
MIMOSA VAM Destruction Project (Sabinas Basin, Coahuila, Mexico] (Vancouver Expo 2013]
https://www.globalmethane.org/expo-docs/posters/CoalMines/CM MX Success Mimosa FINAL.pdf
21.5 References
Barclay (2006): Mexico may open niche for private business, Houston Chronicle, Barclay, E., accessed July
2010. http://www.chron.com/disp/story.mpl/business/3726554.html
Bremer (2006): Mexico Pushes Law to Help Rid Mines of Toxic Gas, Reuters, Catherine Bremer, 7 March 2006.
http://www.redorbit.com/news/science/419391/mexico pushes law to help rid mines of toxic gas/
Briseno (2009): Methane to Markets in Mexico, presented at the Methane to Markets Partnership Coal
Technology Transfer Workshop, Olga Briseno Senosiain, Director for Mining, SEMARNAT, Monterrey,
Mexico, January 2009.
https://www.globalmethane.org/documents/events coal 20090127 techtrans briseno.pdf
Brunner (1999): Methane Drainage at the Minerales Monclova Mines in the Sabinas Coal Basin in Coahuila,
Mexico, presented at the 8th U.S. Mine Ventilation Symposium, pp 123-29, D.J. Brunner and J.R. Ponce,
Rolla, Missouri, 11-17 June 1999.
Cabrera (2009): Methane Market M2M - Invest Coahuila, presented at the Methane to Markets Partnership
Coal Technology Transfer Workshop, Ing. Alfredo Abraham Cabrera, Undersecretary of Mining and
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Energetics, Economic Development Department, Monterrey, Mexico, January 2009.
https://www.globalmethane.org/documents/events coal 20090127 techtrans cabrera.pdf
CDM (2014): Monitoring Report for the MIMOSA Coal Mine Methane Project, submitted to the Clean
Development Mechanism (CDM) Executive Board, 24 October 2014.
https://cdm.unfccc.int/Proiects/DB/DNV-CUK1275307657.99/view
EIA (2013): International Energy Statistics, U.S. Energy Information Administration, 30 May 2013.
http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
EIA (2014): Country Analysis Brief - Mexico, U.S. Energy Information Administration, accessed April 2014.
http://www.eia.gov/countries/cab.cfm?fips=MX
El Universal (2007): Pasta de Conchos case closed after payments, El Universal Mexico News, 19 April 2007.
http://www.eluniversal.com.mx/miami/24291.html
Flores (2007): Recovery and Use of Methane Associated to Mexican Coal Mines, presented at the 6th Session of
the Methane to Markets Partnership Coal Subcommittee Meeting, Ramon Carlos Torres Flores, General
Director for Energy and Mining, Mexico Secretariat of Environment and Natural Resources, Geneva,
Switzerland, 3 April 2007.
https://www.globalmethane.org/documents/events coal 20070402 mexico.pdf
Flores-Galicia (2001): Exploracion y recourses de carbon en la Republica Mexicana (Geology and reserves of
coal deposits in Mexico), The Geology of North America, v. P-3, Economic Geology, The Geological Society
of America, Chapter 11, p. 131-160, 2001.
GMI (2010): Coal Mine Methane Projects in Mexico, Global Methane Initiative, website accessed in October
2010.
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed October
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
LatinPetroleum (2006): Mexico reforms Mining Law, Leopoldo Burguete Stanek; Partner with Gonzalez
Calvillo S.C., via LatinPetroleum.com, 23 July 2006.
http://www.latinpetroleum.com/new/newsdetail.php?aid=13&cid=20&content=F&pagename=article&p
age=28
PEMEX (2011): PEMEX Outlook Presentation, Petroleos Mexicanos, July 2011.
http://www.ri.pemex.com/files/content/PEMEX Outlook 110719 ril.pdf
Querol-Sune (2001): Exploration and Coal Resources of Mexico, Summary in GSA Abstracts with programs,
Vol. 33, num. 6, p. A-354, Francisco Querol-Sune, Director General, Consejo de Recursos Minerale,
November 2001. http://gsa.confex.com/gsa/2 001AM /finalprogram/abstract 26383.htm
Roldan (2009): Coalbed Methane Regulation, presented at the Methane to Markets Partnership Coal
Technology Transfer Workshop, Oscar Roldan Flores, Deputy Director for Exploration and Production,
Secretariat of Energy, Monterrey, Mexico, January 2009.
https://www.globalmethane.org/documents/events coal 20090127 techtrans roldan.pdf
Santillan (2004): Potencial uso del gas Metano del carbon como Energi'a (Potential Use of Methane Gas for
Coal-based Energy), Draft Report, M.A. Santillan-Gonzales, 2004.
Santillan (2006): Information provided by Mario Santillan-Gonzales, Minerales Monclova, 2006.
Santillan (2010): Mexico's experience reducing barriers and developing new CMM recovery and use projects,
presented at the Methane to Markets Partnership Expo, Mario Santillan, New Delhi, India, March 2010.
https://www.glohalmethane.org/expo-docs/indialO/postexpo/coal santillan.pdf
Santillan (2013): personal communication with Mario Santillan-Gonzales, AHMSA/MINOSA, in preparation
for Coalbed Methane Extra article "MINOSA hosts the first CMM flaring projects in Mexico," 2013.
http://www.epa.gov/cmop/docs/Winter 2013.pdf
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Santillan (2014): Information and mine data provided through personal communication with Mario Santillan-
Gonzales, Grupo Acerero del Norte (GAN), 5 November 2014.
SEMARNAT (2012): Mexico's Fifth National Communication to the United Nations Framework Convention on
Climate Change, Mexico Ministry of Environment and Natural Resources (SEMARNAT), National Institute
of Ecology, 2012. http: //unfccc.int/resource/docs /natc/mexnc5s.pdf
UNFCCC (2006): Mexico's Third National Communication to the United Nations Framework Convention on
Climate Change, Non-Annex I national communications, 11 November 2006.
http://unfccc.int/resource/docs/natc/mexnc3.pdf
UNFCCC (2007): Inventario Nacional de Emisiones de Gases de Efecto Invernadero 1990-2002 (National
Greenhouse Gas Inventory 1990-2002 Report of Mexico), Greenhouse gas inventory submissions from
non-Annex I Parties, United Nations Framework Convention on Climate Change, 12 April 2007.
http://unfccc.int/ghg emissions data/items/3962.php
UNFCCC (2014): Ratification Status - Mexico, United Nations Framework Convention on Climate Change,
accessed September 2014. http: //maindh.unfccc.int/puhlic/country.pl?country=MX
UNEP (2010): Mexico CDM Project Search. United Nations Environment Programme - Risoe Centre on
Energy, Climate and Sustainable Development, Roskilde, Denmark, accessed July 2010.
http://cdmpipeline.org/publications/CDMPipeline.xlsx
USEPA (2012): Global Anthropogenic Non-C02 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
Verdugo (1991): The Fuentes-Rio Escondido Coal Basin, Coahuila, Salas, G.C., ed., Economic Geology, Mexico,
Boulder, The Geological Society of America (Decade of North American Geology), Geology of North
America, V. P-3, p. 107-128, F.D. Verdugo and M.C. Ariciaga, 1991.
Wood (2007): Mexico Plans Coalbed Methane Auction in Wake of Massive Land Grab, Resource Investor, Tim
Wood, 6 September 2007. http: //www.resourceinvestor.eom/2007/09/06/mexico-plans-coalbed-
methane-auction-in-wake-of-ma
WME (1994): Directional drilling techniques for exploration in advance of mining, World Mining Equipment,
Industrial Minerals, January 1994. http://www.targetdrilling.com/pdf/puhs/Directional-Drilling-
Techniques-World-Mining-Equip.pdf
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22 Mongolia
22.1 Summary of Coal Industry
22.1.1 Role of Coal in Mongolia
Mongolia's energy needs are met primarily by coal, which accounts for 73 percent of total energy
consumption (IEEJ, 2012). Mongolia presently ranks 22nd worldwide in production of coal. Coal
production in Mongolia has seen a six-fold increase since 2000. Mongolia has been a net exporter of
coal since 2005, exporting over 22 million tonnes (Mmt) in 2012 (EIA, 2014). Table 22-1 provides
proven coal reserves and recent coal production data for Mongolia.
Table 22-1. Mongolia's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-bituminous
& Lignite
(million tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
2,520 (12,200*]
19 (0.28%]
(2011]
Annual Coal Production (2012]
23.6
9.98
33.6
21(0.4%]
Sources: EIA (2014], *2008 estimate by Ganbaatar (2008]
Mongolia's coal consumption increased in recentyears, from less than 6 Mmt in 2008 to almost 10
Mmt in 2012; however, as a result of decreased export demand and coal price declines, Mongolia
experienced a slump in coal production in 2013. Figure 22-1 below shows Mongolia's production,
consumption, and exports from 2000 to 2012.
Figure 22-1. Mongolia's Coal Production, Consumption, and Exports (million tonnes)
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Mongolia has estimated coal resources of 173.3 billion tonnes (MRAM, 2013) with proved coal
reserves of 12.2 billion tonnes, including 2 billion tonnes of coking coal and 10.1 billion tonnes of
thermal coal (IEEJ, 2012) in over 370 deposits and occurrences in 15 different basins (shown in
Figure 22-2).
Table 22-2 summarizes the reserves found in major coal deposits of Mongolia.
Table 22-2. Coal Resources Found in Major Coal Deposits
Estimated
Region
Coal Deposit
Resources
(million tonnes)
Coal Rank
Coal Basin
Central
Shivee Ovoo
563
Lignite
Choir-Nyalga
Mongolia
Tevshiin Govi
588
Lignite
Choir-Nyalga
Tugrugnuur and
Tsaidannuur
2,000*
Brown
Choir-Nyalga
Baganuur
511
Lignite
Choir-Nyalga
Chandgan Tal
123
Lignite
Choir-Nyalga
Khuut
87.5
Sub-bituminous
Middle Gobi
Uvdug Khudag
159.2
Lignite
Middle Gobi
Bayan Teeg
29.7
Bituminous
Ongyin Gol
Shaiyn Gol
61.3
Sub-bituminous
Orkhon-Selenge
Ulaan-Ovoo
54
Sub-bituminous
Orkhon-Selenge
Nalaikh
59
Sub-bituminous
Orkhon-Selenge
Mogoin Gol
4.1
Bituminous
Orkhon-Selenge
Saikhan-Ovoo
190**
Anthracite and
Bituminous
Orkhon-Selenge
East Mongolia
Adduun Chuluun
241.3
Lignite
Choibalsan
Tugalgatai
3,000*
Sub-bituminous
Choir-Nyalga
Chandgana Tal
Lignite
Choir-Nyalga
Talbulag
81.5
Lignite
Sukhbaatar
West
Khushuut
300*
Bituminous and
Mongol-Altai
Mongolia
metallurgical
Zeegt
4.9
Bituminous
Mongol-Altai
Nuurst Khotgor
143.3
Bituminous
Kharkhiraa
Khar Tarvagatai
19.7
Bituminous
Kharkhiraa
Uvurchuluut
3.8
Lignite and Sub-
bituminous
South Khangai
South Gobi
Tavan Tolgoi
6400
Bituminous
South Gobi
Baruun Naran
155*
Thermal and
metallurgical
South Gobi
Naryn Sukhait
220f
Bituminous
South Gobi
Aman Gol
1,500
Sub-bituminous
South Gobi
Ovoot Tolgoi
150*
South Gobi
Sources: MNEC (2014]; *Ganbaatar (2008]; Asia Coal Limited (2014]; fMAK (2010]
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Figure 22-2. Mongolia's Coal Basins
Coal-bearing basins
1 1 Bituminous
I 1 Subbituminous and lignite
Outlines adapted from Chimiddorj (1995)
Browncoal Basins
7 Orkhon-Selenge (J)
8 Oiigiyiigol (J)
Hardcoal Basins 9 Big Bogdyn (J)
1 Kharkhiraa (C) 10 Choir-Niarga (K)
2 Bayan-Ulegei (C) 11 Middle Govi (K)
3 Mongol Altay (C) 12 Hast Govi (K)
4 Altay-Chandmani (C) 13 Sukhe Bator (K)
5 South Khangay (P) 14 Choybalsan (K)
6 South Govi (P) 15 Tamtsak(K)
K, Cretaceous: J, Jurassic; P, Permian; C, Carboniferous
Source: Schwochow (1997], modified from Chimiddorj (1995)
22.1.2 Stakeholders
Table 22-3 identifies potential key stakeholders in coal mine methane (CMM) development in
Mongolia.
Table 22-3. Key Stakeholders in Mongolia's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies
Aduunchuluun LLC
Asian Coal Ltd.
Aspire Mining Limited
Baganuur JSC
Bayanteeg LLC
Chandganacoal LLC
Chingisiin har alt LLC
Energy Resources LLC
Erdenes MGL
Gobi Coal and Energy LLC
Gobi Khurakh LLC
Hunnu Coal
Korea Resources Corporation
Leighton LLC
Macmahon Mongolia LLC
Maral Michid Od LLC
MoEnCo LLC
Mongolyn Alt (MAK) Group
Peabody Winsway Resources LLC
Project hosts
ffr,
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Table 22-3. Key Stakeholders in Mongolia's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies (con't]
¦ Prophecy Coal Corporation
¦ QGX Ltd.
¦ Red Hill Mongolia LLC
¦ Big Mogul Coal & Energy LLC
¦ Shivee Ovoo JSC
¦ South Gobi Resources
¦ South Gobi Sands LLC
¦ Tevshiin Gobi LLC
¦ Tsegeen Uuden LLC
¦ Tugrug Nuuriin Energy LLC
¦ Xanadu Mines Ltd.
Project hosts
Developers
¦ KOGAS
Project opportunity
identification and
planning
Engineering, consultancy.
¦ Geomaster Engineering LLC
Technical assistance
and related services
¦ MegaWatt Company Ltd.
¦ Center of Mongolian Mining Professional Engineers
¦ Sproule
Universities, Research
¦ National University of Mongolia
Technical assistance
Establishments
¦ Mongolian University of Science and Technology
¦ Mongolian Technical University
Regulatory Agencies and
¦ Ministry of Mining
Project identification
Government Groups
¦ Ministiy of Nature, Environment, and Green Development
¦ Ministry of Energy
¦ Mineral Resources Authority
¦ Petroleum Authority
¦ Ministiy of Economic Development
¦ Millennium Challenge Account - Mongolia
and assessment support
Non-governmental
¦ Mongolian Nature and Environment Consortium
Organizations
¦ Mongolian National Mining Association
¦ Mongolian Coal Association
¦ Federation Of Energy, Geology And Mining Workers'
Trade Unions Of Mongolia - MEGM
Sources: Mongolian Mining Directory (2013]; InfoMongolia (2014]; UNFCCC (2014]
22.1.3 Status of Coal and the Coal Mining Industry
Mongolia produced more than 33 Mmtof coal in 2012 (Table 22-1), consuming only 10 Mmt and
exporting the remainder. There are more than 30 surface (or open cast) mines in Mongolia,
providing almost 99 percent of Mongolia's coal production. Domestic demand for coal is on the rise
with increased power demand, which is expected to reach 1,375 megawatts (MW) in 2015 due to
Mongolia's rapidly developing mining-based economy and urbanization acceleration. Mining
companies account for 40 percent of Mongolia's total electricity consumption (Kohn, 2013). In
2009, it was reported that almost all of Mongolia's exported coal went to China (Liu, 2012). China
has historically produced its own coking coal; however, growing demand for coking coal due to a
rapid increase in steel production has led to demand for imports from Australia and Mongolia. In
2008, Mongolia supplied more than half of China's coking coal imports and maintained its position
as top exporter until the first half of 2013, when Mongolia's exports of coking coal to China fell by
36 percent while Australia's doubled. As of late 2013, Mongolia's coal made up only 17 percent of
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China's imports while Australia supplied 39 percent (Els, 2013). Despite the shorter distance to
China's steel mills, Mongolian coal must be trucked to the Chinese border, increasing the cost
compared to Australia's seaborne coal. As a result of decreased demand from China, as well as coal
price declines, Mongolia experienced a slump in coal production in 2013.
It is expected that installation of a railway will increase the competitiveness of Mongolia's coal in
China (Ng 2013). In Mongolia, many of the more substantial deposits of proven coal reserves
remain undeveloped due to the lack of infrastructure. Several infrastructure improvements are
planned to accommodate an increase in coal mining as well as mining of other vast and valuable
mineral reserves such as copper and gold. In October 2013, a consortium of Mongolian coal mining
companies including Mongolia Mining Corporation, Erdenes Tavan Tolgoi, Energy Resources LLC
and Tavan Tolgoi JSC as well as Chinese state-owned mining and energy company Shenhua Group
Corporation Limited, signed a Memorandum of Understanding
with the Mongolian Railway State-Owned JSC (MTZ) to construct a freight railway, primarily for
transport of coking coal to China. The rail will connect the Gashuun Sukhait border point south of
Tavan Tolgoi with the Ganqimoadu port in China (MMC, 2013a).
In November 2013, a 220-kV overhead transmission line connecting the South Gobi region mines
Oyu Tolgoi (copper), Tavan Tolgoi (coal), and Tsagaan Suvarga (copper and molybdenum) and
South Gobi region customers with Mongolia's Central Electricity System was completed (MCS,
2013). Additionally, World Bank's International Development Association is providing support to
create infrastructure necessary for the development of natural resources (World Bank, 2014).
Mongolia's Ministry of Energy (MOE) has outlined a number of policy goals including increased
government support in coal export, reductions in customs taxes for coal export, reduction of rail
transport tariffs and appropriate changes in relevant laws, all of which will encourage increased
coal production (Ganbataar, 2005).
Several new surface coal mine developments are planned. Tethys Mining LLC discovered a large
coal deposit, Tugalgatai, in the eastern Mongolian province of Khentii (spelled Hentiy on the map in
Figure 22-2) (Daly, 2008). In 2013, Canadian coal company Prophecy Coal Corp. reported that it
was in discussions with Tethys to purchase the Tugalgatai coal licenses. Tugalgatai is contiguous to
the company's Chandgana licenses, which host a measured resource of 650 Mmt and an indicated
resource of 540 Mmt of thermal coal. The Chandgana Coal Project is expected to begin delivery of
coal in 2016 to Prophecy's 600-MW Chandgana Power Plant The plant was approved by the
Mongolian government in early 2014 (Prophecy, 2013a; Prophecy, 2014a; Prophecy, 2014b).
Production at the Zeegt coal mine in Gobi-Altai Province is expected to begin in 2015. Gobi Coal and
Energy began exploration work in 2006 around a small, formerly-state owned mine (Gobi Coal and
Energy, 2014).
Aspire Mining Limited's Ovoot Coking Coal Project is being developed in Khusvgul Province in
northwestern Mongolia. Aspire has signed an agreement with the Mongolian government to
provide coal to the planned Sainshand Industrial Complex, which is intended to accommodate coke
and steel plants. In order to supply the Sainshand Park with Ovoot Project coking coal, the Erdenet
- Ovoot Project Railway connecting to the Trans-Mongolian Railway will need to be completed.
Northern Railways, Aspire's Mongolian rail infrastructure subsidiary, has applied to the Mongolian
Government for a rail concession over the Northern Rail Line (Proactive, 2014).
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South Gobi Resources has outlined plans to develop properties near its existing OvootTolgoi coal
mine in Omnogovi Province, namely the Soumber Deposit 20 km east and the Zag Suuj Deposit,
located approximately 150km east. South Gobi is developing an additional deposit, the Tsagaan
Tolgoi deposit, 415 km northeast of OvootTolgoi (South Gobi, 2014).
Mongolia is also pursuing development of coal-to-liquids capacity. In August of 2013 a South
Korean steelmaker, POSCO, announced a joint partnership with Mongolia's MCS Group to develop a
coal-to-liquids plant in Ulaanbaatar's Baganuur district. The joint venture (named the Baganuur
Energy Corporation) would build and operate a plant to annually produce 450,000 tonnes of diesel
and 100,000 tonnes of dimethyl ether (Oxford, 2013). The Ovdog Hudag mine in Dundgovi Province
has also been considered for this purpose (Ariuntuya, 2012).
Mongolia's largest underground coal mine, Nalaikh, near Ulaanbaatar, was closed in 1993 due to a
major mine fire. Small shallow depth mining at coal outcrops at Nalaikh began in 1922, for the
purpose of supplying coal to customers of the capital city of Ulaanbaatar. In 1954 - 1958, the larger
underground mining operations were established with the production capacity of 600 thousand
tonnes annually. By 1987, the mine reached full capacity, producing 800 thousand tonnes per year.
Official underground mining in this area ceased in 1993; however, after the formal closure of the
underground mine, the masses of freshly unemployed and skilled miners turned to illegal mining of
the Nalaikh deposit. With nearly 200 shafts and five to ten workers per shaft, there are roughly
2,500 miners working the area during the peak season between September and May. The shafts are
dug haphazardly, with little to no coordination between shafts. Mining dangers, such as cave-ins,
are becoming more frequent (World Bank, 2004; MNEC, 2014). There is interest in CMM recovery
and utilization at the Nalaikh mine, and the mine was subject of a United States Environmental
Protection Agency Cooperative Agreement entitled, Pre-feasibility Study on Methane Recovery &
Utilization in Nalaikh Coal Mine, available at
https://www. globalmethane.org/activities/actDetails. aspx?ID=346.
Profiles of Mongolia's major coal mines are located in Section 1.4, Profiles of Individual Mines.
22.2 Overview of CMM Emissions and Development
Potential
Other than the minor production from the Nalaikh mine (still formally closed), all of Mongolia's coal
production is from surface mines. Thus, CMM development potential in Mongolia lies
predominantly in pre-mine drainage in advance of surface mining operations. Underground CMM
recovery and utilization at the Nalaikh mine may occur if coal mining resumes and a project proves
to be economically feasible.
22.2.1 CMM Emissions from Operating Mines
In Mongolia's first National Communication under the United Nations Framework Convention on
Climate Change (UNFCCC), the analysis of GHG emissions by fuel type estimates that methane
emissions released during coal mining activities, coal mining and post-mining activities comprise
1.6-3.5 percent of all methane emissions (UNFCCC, 2001). As new mining areas have developed,
CMM emissions have increased. Table 22-4 summarizes Mongolia's estimated CMM emissions from
2000 - 2010, with projection for 2015.
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Table 22-4. Mongolia's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
6.7
10.5
13.7
15.1
Source: USEPA(2012)
A detailed calculation of methane emissions from Mongolia's coal mines was carried out, under the
United States Environmental Protection Agency (U.S. EPA) Cooperative Agreement Coal Mine
Methane (CMM) Resource Assessment and Emissions Inventory Development in Mongolia. The
Mongolian Nature and Environment Consortium (MNEC) has developed basin-specific emission
factors which were used to calculate emissions on a basin-by-basin basis. For more information, see
https://www. globalmethane.org/activities/actDetails. aspx?ID=l 200.
A pre-feasibility study has been completed for the Nalaikh mine, assessing the potential for power
generation using CMM. Based on a 3.6-MW design capacity using two internal combustion engines,
greenhouse gas (GHG) emissions reductions for this project are estimated to be about 96,000 tons
CO2 equivalent annually for such a power generation project, over a 17-year project life. The Pre-
feasibility Study on Methane Recovery & Utilization in Nalaikh Coal Mine is available at
https://www. globalmethane.org/activities/actDetails. aspx?ID=346.
Pre-feasibility studies were also completed by U.S. EPA at the Naryn Sukhait and Baganuur mines.
The Naryn Sukhait study, completed in March of 2013, forecasted water and gas production and
estimated that a pilot project could produce enough gas to fuel an 8.55-MW power generation
facility, reducing GHG emissions by 187,900 tonnes over the project's 15-year life. The Pre-
feasibility Study for Coal Mine Methane Recovery and Utilization at Naryn Sukhait Mine is available at
http://epa.gov/cmop/docs/Mongolia %20Naryn%20Sukhait%20Prefeasibility%20Study FINAL.p
df.
The Baganuur Mine study was completed in December 2013. The pre-feasibility study evaluated
utilization of pre-drained CMM for on-site use to fuel an internal combustion power generation
facility located in close proximity to the mine's surface facilities. Production modeling performed
for this study, estimated CMM production is 54.3 million m3 of methane over 10 years, equating to
an installed capacity of approximately 5.0 MW of combined electrical and thermal generating
capacity. The proposed power generation project is estimated to reduce CMM emissions by 104,500
tonnes of CChe over the project's 10-year life. The study, entitled Pre-feasibility Study for Coal Mine
Methane Recovery and Utilization at Baganuur Mine, is available at
http://epa.gov/cmop/docs/2013%20Coal%20Mongolia%20Baganuur%20PFS.pdf.
22.2.2 CMM Emissions from Abandoned Coal Mines
Emissions estimates from the closed Nalaikh coal mine indicate that the mine workings are now
completely flooded and there are negligible emissions from the abandoned mine (MNEC, 2010).
When the mine was operating the excess mine gas was vented. Emissions rates from the mine prior
to its closure (for the period from 1988 to 1993) have been estimated to be as high as 355 liters
methane per second (MNEC, 2010).
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22.2.3 CBM from Virgin Coal Seams
As no natural gas infrastructure exists in Mongolia, CBM activity is in its infancy. Currently neither
conventional natural gas nor CBM is produced or consumed in Mongolia. Based on coal
characteristics, the South Gobi, Kharkhiraa, and Altay-Chamandi basins in southern and western
Mongolia appear to be the most likely areas for future CBM development, should it become a viable
resource (Schwochow, 1997). The Choir-Nyalga basin within the northwest portion of the Eastern
Mongolian coal-bearing province also presents characteristics favorable to future CBM
development (MNEC, 2014).
A Canadian company, Storm Cat Energy Corp., acquired a CBM exploration license in the Noyon Uul
region of the South Gobi basin in 2004 through a Production Sharing Contract (PSC) with the
Petroleum Authority of Mongolia. Results of coring and desorption revealed a total coal thickness of
76.6 meters and gas contents which ranged from 2.34 m3/tonne to 11.8 m3/tonne. Storm Cat
estimated the potential CBM resource of the area to range from 17 billion m3 to 34 billion m3, with a
best estimate of 25.5 billion m3 (Storm Cat, 2005). This resource estimate was based on the volume
of coal estimated at depths shallower than the 1,500-meter drill depth, combined with average gas
contents obtained from desorption analyses. While the potential resource is relatively large, no gas
production has occurred. Storm Cat has determined that further geological review is necessary.
Sproule, a Canadian consulting company, also reports to have evaluated CBM resources in Mongolia
(Sproule, 2010). Following talks beginning in 2009, Korean Gas concluded the "Korea-Mongolia Gas
Partnership," an agreement for joint research and exploration to develop CBM in Mongolia, with the
MOE in 2010. The agreement seeks to supply methane to Ulaanbaatar through CBM exploration and
production activities undertaken by the Korean Gas Research and Development Division and the
Korea Institute of Geoscience and Mineral Resources. Drilling thus far has yielded no tangible
results (KOGAS, 2010).
22.3 Opportunities and Challenges to CMM Recovery and
Use
Mongolia is a signatory to the UNFCCC (Table 22-5). As a Non-Annex I Party to the Kyoto Protocol,
Mongolia has no national emissions targets. Mongolia was eligible to host GHG mitigation projects
under the Clean Development Mechanism (CDM), and registered four projects in the wind,
hydropower, and supply side energy efficiency improvements sectors. No CMM projects were
hosted by Mongolia.
Table 22-5. Mongolia's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 12,1992
September 30,1993
Kyoto Protocol
December 15,1999
Source: UNFCCC (2014]
22.3.1 Market and Infrastructure Factors
The greatest challenge to CMM recovery and utilization in Mongolia is the lack of current markets
or infrastructure to support it. With no natural gas production or imports, other fuel sources,
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primarily coal, are the principle sources for heat and power. Possible markets for onsite heat
and/or power generation include industrial sites and coal mines, based on both their intense
electricity demands and extremely harsh winter weather conditions. For example, the Tavan Tolgoi
coal mine development will require an estimated 100 MW (Tserenpurev, 2008). In addition, high
and steadily increasing costs of petroleum imports to Mongolia may create potential new market
demand for liquefied natural gas (LNG) as a vehicle fuel.
Mongolia's installed power capacity is 1,062 MW, most of which is provided by coal (see Figure 22-
3); however, only 836 MW (80 percent) is available due to aging power plants operating below
design capacity. Mongolia's electricity transmission network connects approximately 70 percent of
the country's population, but is considered unreliable, fraught with frequent blackouts occurring in
major cities due to aging infrastructure (IEEJ, 2012). Mining accounts for 40 percent of Mongolia's
energy consumption, and electricity prices for mining companies that tap into Mongolia's Central
Electricity System (CES) will rise by as much as 30 percent according to Mongolia's Energy
Regulatory Commission (Kohn, 2013). Electricity demand has increased at an average annual rate
of 2.9 percent since 2005, a trend that is expected to continue through 2020.
Figure 22-3. Mongolia's Electricity Supply
Small diesel
generators,
74.3,8%
A
Hydroelectric,
m W1
27.5,3%
VSolar/wind,
6.7,1%
Coal-fired
CHP, 828.8,
88%
Source: IEEJ (2012]
Mongolia's main electricity grid is the CES, which covers 80 percent of Mongolia's electricity supply
and includes five coal-fired power plants and an interconnection with Russia for import of
electricity. It has a basic transmission grid of 220 kV and 110 kV overhead transmission lines
(OHTL). A 220 kV ring system connects the principal generation and load centers of Ulaanbaatar,
Darkhan and Erdenetand additional 220 kV connections with load centers of Baganuur and Choir.
The Baganuur substation is linked with Power Plant #4 in Ulaanbaatar by a 220 kV two circuit
OHTL approximately 130 km long. During peak load periods, electricity is imported from the
Russian Federation in order to meet and regulate electricity demand of the system (Prophecy,
2013b). Maximum current import capacity from Russia of 255 MW is expected to be reached (IEEJ,
2012); however, increased imports from Russia are not considered an option for meeting demand
as the Mongolian government is concerned about supply security risks attached to reliance on
Russian imports as well as the increased expense of Russian electricity.
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Mongolia has several laws and resolutions that favor foreign investment in CMM projects. For
instance, under the 1993 Law on Foreign Investment, an investor may request a stability agreement
providing the investor a legal guarantee for a stable fiscal environment and protection from
changes in taxation policy for 10 to 15 years. This protects the contractor from any changes of
taxation policy (Chimiddorj, 2006).
The Parliament also passed Resolution #140 on 27 June 2001, which approves a list of favored
industries in which foreign investment and involvement will be encouraged. Of these, oil and gas
production as well as transmission pipeline construction are included. The MOE's Fuel Division has
outlined various development goals which include extraction of petroleum products from coal
(Ganbaatar, 2005).
Mongolia's tax policy also appears to be favorable towards CMM project development Materials
and equipment necessary to conduct petroleum operations that are imported by contractors are
exempt from customs taxes, value added taxes, and excise taxes. Contractors' earnings from
petroleum shares are exempt from income taxes.
22.3.2 Regulatory Information
The Constitution of Mongolia indicates that mineral resources in Mongolia are owned by the state.
Coal exploration and production are regulated by the Law of Mineral Resources while natural gas
and CBM are regulated by the Petroleum Law (Tumurbaatar and Altanchimeg 2009).
In 1991, the Petroleum Law of Mongolia was ratified by the Parliament The Law established a legal
foundation for new development of petroleum exploration in Mongolia. In 2004, the Mineral
Resources and Petroleum Authority of Mongolia (MRPAM) was formed and authorized by the
Government of Mongolia to enter into contracts on the matters of oil and gas exploration,
development, production, processing marketing and supply of petroleum products in Mongolia,
and to exercise supervision and assistance towards the implementation of such contracts (MIF,
2006). According to Parliament Resolution #43 and Government Resolution #64, MRP AM was
reorganized and divided into the separate entities of the Mineral Resources Authority of Mongolia
(MRAM) and the Petroleum Authority under the former Ministry of Minerals and Energy,
subsequently the Ministry of Mining (MRAM, 2009).
The primary form of petroleum exploration contract in Mongolia is Production Sharing Contract
(PSC). Applications are submitted to the Petroleum Authority which signs a PSC with the contractor
on the recommendation of the National Security Council and with permission of the Mongolian
Government All materials and equipment necessary to conduct petroleum operations, imported by
contractors, are exempt from all customs taxes, value added taxes and excise taxes. The earnings of
contractors from their share of petroleum are also exempt from income taxes (Chimiddorj, 2006).
Mongolia's mineral resources are federally owned and administered through the Ministry of Mining
(MOM). MRAM and the Petroleum Authority are implementing agencies under the MOM, and are
charged with responsible development of mineral and petroleum resources through licensure, and
the enforcement of regulations governing development. MRAM is responsible for development of
minerals such as coal under the Minerals Law (2006), and the Petroleum Authority, under authority
of the Petroleum Law (1991), which governs the production of liquid and gaseous hydrocarbons.
The MOM also houses a Fuel Policy Division.
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To date there has been no commercial CBM or CMM activity; however, there have been CBM
exploration and PSC such as that entered into by Storm Cat Energy with the Petroleum Authority in
2004. Storm Cat Energy explored for CBM both near Ulaanbaatar (Tsaidam block area) and in the
South Gobi region near the present Naryn Sukhait surface coal mine (SEC, 2005). No exploration or
PSC have been negotiated for resources distinguished as CMM; however, members of the MRAM
have indicated that there are regulations which require coal lease holders to not only assess the
value of coal within their leasehold, but also estimate the methane resources associated with coal
and surrounding strata.
Both the Minerals Law and the Petroleum Law are being revised. A revised draft of the Minerals
Law was published in December 2012. The MOM submitted the renewed draft bill of the Petroleum
Law to parliament in June 2013, which was passed and made effective on ljuly 2014. This law
defines a new category of petroleum resource, unconventional petroleum, which includes bitumen,
oil shale, tar sand, gas rich shale, gas sand, and coalbed methane. Conflicts regarding overlap of
rights to explore and develop conventional and unconventional petroleum deposits are addressed
by encouraging companies interested in developing multiple mineral deposit types and/or oil and
gas deposits to apply for the rights to all. If there is overlap of rights among entities, they encourage
the leaseholders to find a workable and mutually beneficial approach; if this not possible, the
Cabinet will determine the best way forward based on social and economic factors.
Though previous CBM activity has been managed by the Petroleum Authority of the MOM, the MOE
claims rights relating to granting permission for research and exploration of methane resources.
The primary focus of the MOE has been to supply and distribution of energy. It included a Fuel
Division concerned with CBM development and research and asserts that CBM exploration must be
permitted through the MOE, but these conflicts may now be resolved internally if the new ministry
is created by the merger of MOM and MOE.
22.4 Profiles of Individual Mines
22.4.1 TavanTolgoi
The TavanTolgoi coal deposit is located in the territory ofTsogtTsetsii Soum, within the Omnogovi
Province, approximately 540 km south of Ulaanbaatar. Tavan Tolgoi is one of the world's largest
untapped coking and thermal coal deposits. It is divided into six coalfields: Tsankhi, Ukhaa Khudag,
Bor Tolgoi, Bor Teeg, Southwest and Eastern coalfields. A small coal mine within the Tavan Tolgoi
coal deposit has been in operation since 1967, which until 2011, has supplied coal directly into the
Mongolian domestic market After 2011, all coal produced is exported to China. This coal mine is
owned by the local government (51 percent) and other private shareholders. The coal production
plan for 2013 was 2 Mmt Ninety-six percent of the Tavan Tolgoi deposit area is owned by Erdenes
MGL (a government owned company), with the exception of the Ukhaa Khudag field which is mined
by the Mongolian Mining Corporation (Energy Resources LLC). Erdenes Tavan Tolgoi LLC (Erdenes
TT), a subsidiary of Erdenes MGL, is managing the development of the deposit The Tsankhi field is
the largest portion of the entire coal deposit, and is divided into the East and West Tsankhi areas.
Recent work has been focused in these two areas. Erdenes TT has chosen the joint venture
company of Macmahon Holdings and BBM Operta to operate the mine under a five year contract
which extends from 2012 - 2017. Production in 2013 from EastTsahkhi mine is expected to be 6
Mmt and 1.5 Mmtfrom WestTsankhi. The Ukhaa Khudag field, located within the Tavan Tolgoi coal
formation is mined by Mongolian Mining Corporation (MMC). The mine is strategically located
approximately 240 km from the Mongolian-Chinese border and about 600 km north of Baotou,
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China, an important railway transportation hub. The hub provides access to the largest steel
producing provinces within China.
MMC began mining operations at Ukhaa Hudag in April of 2009 and became profitable in the first
year of operations. MMC's coking coal production has steadily increased from 1.8 Mt in 2009 to 3.9
Mtin 2010, 7.1 Mt in 2011 and 8.6 Mtin 2012, with plans to produce 15 Mtin 2014.
The mine serves as an operational hub for processing coal from Ukhaa Khudag and Baruun Naran
mines, complete with all necessary utility infrastructure facilities, including an 18-MW on-site
power plant and water supply system (MNEC, 2014).
22.4.2 Baganuur
The Baganuur mine is a surface coal mine owned and operated by Baganuur Joint Stock Company
(Baganuur JSC), located outside of Ulaanbaatar. The mine is 75 percent state owned and 25 percent
privately owned. Baganuur mines 3.5 Mmt of coal per year, with plans to increase production to
over 6 Mmt per year by 2020. It is estimated that there are 248.97 Mmt of coal within the Baganuur
mining area. The expected service life of Baganuur is 60 years (USEPA, 2013a). Baganuur hosted a
United States Environmental Protection Agency study entitled Pre-feasibility Study for Coal Mine
Methane Recovery and Utilization at Baganuur Mine, available at
http://epa.gov/cmop/docs/2013%20Coal%20Mongolia%20Baganuur%20PFS.pdf.
22.4.3 Naryn Sukhait
The Naryn Sukhait coal deposit is located in remote southwestern Mongolia in Omnogovi Province,
approximately 850 km southwest of Ulaanbaatar, and just 57 kilometers north of the Mongolian -
Chinese border. Presently there are three large scaled surface coal mines operating at the Naryn
Sukhait deposit: Naryn Sukhait Mine-1 operated by Mongolyn Alt (MAK) Corporation, Naryn
Sukhait Mine-2 operated by the Mongolian-Chinese joint venture company, Qinhua-MAK, and the
Ovoot Tolgoi mine operated by the Australian company, South Gobi Sands. Projected production of
the Naryn Sukhait Mine-1 for 2013 was 10 Mmt The projected production of the Naryn Sukhait
Mine-2 was 1.5 Mmt, while the OvootTolgoi Mine was projected to produce 4 Mmtin 2013 (MNEC,
2014; USEPA, 2013b). MAK hosted a United States Environmental Protection Agency study entitled
Pre-feasibility Study for Coal Mine Methane Recovery and Utilization at Naryn Sukhait Mine, available
at
http://epa.gov/cmop/docs/Mongolia %20Naryn%20Sukhait%20Prefeasibility%20Study FINAL.p
df.
22.4.4 Khotgor
The Nuurst Khotgor coal deposit is located in Uvs Province, approximately 110 km west, southwest
of the province center Ulaan Gom. The Nuurst Khotgor Coal Mine began operating as an open cut
mine in the Khotgor field in 1963. The mine has produced a total of 4.2 Mmt of coal until it ceased
operations in 2013. The coal was utilized by local consumers of the Bayan-Olgii and Uvs Provinces.
Presently, mine operations are undertaken in three coal fields (Khotgor, Khotgor Shanaga and
Erchim) by different companies. Korea Coal Corporation (KOCOAL), a state-run coal mine
developer, purchased a 51 percent stake in the Khotgor Shanaga coal mine for $10 million US and
will invest an additional $18.1 million US in mine operations. The mine has a soft coal reserve of 79
Mmt and plans to produce up to 1 Mmt of coal annually. The mine, operated by Mongolian-Korean
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Joint Venture Company, was scheduled to produce 410 thousand tonnes of coal in 2013. A portion
of that production was planned for export to Russia. KOCOAL was established in 1950 as a
government-owned coal company to manage coal mines. Its mission has been further increased
with coal export and import businesses, including foreign coal mine development. The company
currently operates three domestic coal mines, producing approximately 1.2 Mmt annually. The
oldest Khotgor mine will have produced 120 thousand tonnes of coal in 2013 while the Erchim
Mine forecasted production of 25 thousand tonnes (MNEC, 2014).
22.4.5 Sharyn Gol
The Sharyn Gol coal deposit is located in the territory of Darkhan Soum in Darkhan - Uul Province.
The deposit sits approximately 70 km east of Darkhan city, one of the main stations along the
Trans-Mongolian Railway. The Sharyn Gol mine is the oldest coal mine in Mongolia, with over 45
years of continuous production history. The mine began its open pit operation in 1965. Produced
coal has been utilized mainly by power plants in Ulaanbaatar, Darkhan and Erdenet. Although the
original production capacity was 2.5 Mmt per year, the recent annual production has been on the
decline, with 465 thousand tonnes produced in 2012, and a production plan for 2013 of 900
thousand tonnes. The Sharyn Gol mine was privatized on the Mongolian Stock Exchange in 2003.
Firebird acquired a controlling position in 2010 and led a complete overhaul of the company,
including a 17,000 meter drilling program, resulting in the identification of 374 Mmt of coal
resources in a JORC-compliant resource statement. Recently, Sharyn Gol JSC received the
government approval required for the launch of operations at its planned new open pit. Sharyn Gol
is strategically situated on a rail spur connecting to the Trans-Mongolian Railway. As the only
significant supplier of high quality thermal coal, Sharyn Gol can take advantage of growing domestic
demand in the Darkhan province and throughout the region. The rail connection also offers the
company the option to consider exports to Russia and into the international market through
Russian ports. Laboratory tests demonstrated that Sharyn Gol coal can be washed efficiently into a
premium export quality coal (MNEC, 2014).
Although the Sharyn Gol mine is principally an opencast mine, the mining company began some
underground exploration and development in 2005. Since thattime, between 60 and 70,000 tonnes
of coal have been mined underground. Maximum annual underground production has been 20,000
tonnes. At times, gas build up in the underground workings has been serious enough to cause work
to stop until methane concentrations were reduced. Previously the mine carried out initial research
on CBM resources to identify the best extraction technology and how to best transition from surface
to underground mining.
22.4.6 Others
The Aduunchuluun mine is located in Dornod Province in eastern Mongolia. The mine is owned by
Mongolyn Alt (MAK) Corporation. Small-scale extraction began in 1955 and the mine has produced
600 thousand tonnes of brown coal per year since 1979. It is economically unprofitable to transport
thermal coal from Aduunchuluun to local and foreign markets because the coal is high in moisture
and low in calorific value, thus MAK has investigated construction of a coal briquette plant
Aduunchuluun has also been considered as a site for coal gasification (Ariuntuya, 2012; MAK,
2014a).
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The Baruun Naran mine is located in Omnogovi Province. Commissioning of the mine took place in
January 2012 and commercial coal mining operations started in February 2012. The mine produced
800 thousand tonnes of coal in 2012 and 500 thousand tonnes in 2013 (MMC, 2013b).
The Ulaan Ovoo mine is located in Selenge aimag, 17 km from the Russian border, 430 km from
Ulaanbaatar, and 120 km from both Mongolian and Russian rail links. Prophecy Coal Company is
the sole owner of the mine and commenced operations in 2010. The mine has an estimated 174
Mmt of measured and 34 Mmt of indicated coal resources (Prophecy 2014c). The mine's annual
capacity is estimated to be 6 Mmt (Ariuntuya, 2012).
The Bayanteeg mine is located in Ovorkhangai Province in southern Mongolia. Bayanteeg
Shareholding Company established the mine in 1962 with an annual output capacity of 25,000
tonnes of coal and has been supplying nearby towns with coal since then. Bayanteeg mine has
estimated reserves of 29.6 Mmt, of which 4.6 Mmt have so far been extracted. Bayanteeg has been
considered as the site of a medium-size coal-to-gas plant (Ariuntuya, 2012).
The Tevshiin Govi mine is located in Dundgovi Province and was established in 1990 by the
Mongolian government The mine has since been privatized and produces 50 thousand tonnes of
coal annually. The mine has large reserves but is limited by its isolated location (Ariuntuya, 2012).
The Chandgana deposit consists of two properties, Chandgana Tal and Khavtgai Uul. The
ChandganaTal mine opened in 1967 and consists of 124.4 Mmt of measured resource and produces
20 thousand tonnes of coal annually. Khavtgai Uul consists of 509 Mmt measured and 539 Mmt
indicated resource and will meet the needs of the planned 600-MW Chandgana Power Plant
(Prophecy, 2014b; Ariuntuya, 2012).
The OvootTolgoi mine is located in Omnogovi Province and is owned by South Gobi Resources. The
mine has operated since 2008, shutting down for nine months in 2012-2013 due to lowered coal
prices and demand. The mine had planned production of 3.2 Mmt in 2013 (Mining Journal, 2013).
The Eldev mine, owned by MAK, is located in Dornogovi Province. The mine produces 500,000
tonnes per year and sells to both domestic customers including Erdenet Mining Corporation, Khutul
Cement & Lime Plant, Darkhan Power Plant, Ulaanbaatar Railway, and Darkhan Metallurgical Plant
as well as export markets (MAK, 2014b).
22.5 References
Ariuntuya (2012): Strategy on strategic mineral missing, N. Ariuntuya in Mongolian Mining Journal, 27
September 2012. http:IIen.mongolianminingi ournal.com/content /34867.shtml
Asia Coal Limited (2014): Saikhan Ovoo Coal Project, Asia Coal Limited, 2014.
http:// www.asiacoallimited.com/en/projects /
Chimiddorj (1995): Coal Resources in Mongolia and Some Probably Potential Areas for Coalbed Methane,
presented by Ayurzana Chimiddorj, International Conference on Coalbed Methane Development and
Utilization, Proceedings - Beijing, China, 17-21 October 1995.
Chimiddorj (2006): Petroleum Potential of Mongolia and Government Policy on Petroleum Exploration,
presented by Battumur Chimiddorj, Head, Production Sharing Contracts and New Ventures Department,
Mineral Resources and Petroleum Authority of Mongolia (MRPAM), presented at the Mongolia Investors
Forum, 14-15 September 2006.
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Daly (2008): Mongolia, coal, and inflation, John C. K. Daly, United Press International, 14 May 2008.
http://www.upi.com/Business News/Energy-Resources/2008/05/14/Mongolia-coal-and-inflation/UPI-
16541210809363/
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed April 2014. http: //www.eia.gov/cfapps /ipdbproiect/IEDIndex3.cfm
Els (2013): Mongolia opens new door to world's richest coking coal fields, Frik Els, Mining.com, 15 September
2013. http: //www.mining.com/a-new-wav-to-own-the-globes-richest-coking-coal-fields-42503/
Ganbaatar (2005): Energy Policy and Coal Policy of Mongolian Government, presented by B. Ganbaatar,
Department of Fuel Regulation Policy at Mongolia Ministry of Fuel and Energy, at JAPAC (Japanese
Committee for Pacific Coal Flow) International Symposium, 26 September 2005.
Ganbaatar (2008): Current Status and Prospects for Energy Resources and Infrastructure Development of
South Gobi in Mongolia, presented by Mr. Ganbaatar Badgaa, Department of Fuel Policy and Regulation,
Mongolia Ministry of Fuel and Energy at International Symposium on Energy Resources Cooperation and
Corporate Strategy in Northeast and Central Asia, 3 July 2008.
http://www.keei.re.kr/keei/download/seminar/080703/sl-4.pdf
Gobi Coal and Energy (2014): Zeegt Project, Gobi Coal and Energy, 2014. http://www.gobicoal.com/?page=55
IEEJ (2012): Country Presentation: Mongolia, The Institute of Energy Economics - Japan, Energy Policy (B)
Training Course, Japan International Cooperation Agency, June 2012.
http://eneken.ieei.or.ip/data/4480.pdf
InfoMongolia (2014): Ministries of Mongolia, InfoMongolia.com, 2014.
http://www.infomongolia.com/ct/ci/169/138/Ministries%20of%20Mongolia
KOGAS (2010): Global KOGAS Newsletter 2010, Korean Gas, Vol 4, No 3, 25 August 2010.
http://www.kogas.or.kr/kogas eng/down/news 201008.pdf
Kohn (2013): Mongolia raises electricity prices for miners as much as 30%, Michael Kohn, Bloomberg, 19 July
2013. http: //www.bloomberg.eom/news/2013-07-19/mongolia-raises-electricity-prices-for-miners-by-
as-much-as-30-.html
Liu (2012): Ethical Coal: Mongolia's Sparkling Potential Amidst Regional Energy Demand, Leo Liu, Prophecy
Coal Corp., February 2012. http://www.mining.com/ethical-coal-mongolia%E2%80%99s-sparkling-
potential-amidst-regional-energy-demand/
MAK (2010): Mongolyn Alt (MAK) Corporation, website accessed February 2010. http://www.mak.mn/
MAK (2014a): Aduunchuluun brown coal project, Mongolyn Alt (MAK) Corporation, 2014.
http://www.mak.mn/Backup/eng/index.php?option=com content&view=article&id=85&Itemid=213
MAK (2014b): Eldev coal mine, Mongolyn Alt (MAK) Corporation, 2014.
http://www.mak.mn/Backup/eng/index.php?option=com content&view=article&id=87&Itemid=214
MCS (2013): South Region is Connected to Central Electricity System, MCS International Co. Ltd., 2013.
http://international.mcs.mn/eng/pages/news/?menuld=33
MIF (2006): Introduction of the Petroleum Sector of Mongolia, Government Investment Project Brief Profiles,
presented at the Mongolia Investors Forum, 14-15 September 2006.
Mining Journal (2013): South Gobi restarts Ovoot Tolgoi coking coal mine, Mining Journal Online, 22 March
2013. http: //www.mining-iournal.com/production-and-markets/southgobi-restarts-ovoot-tolgoi-
coking-coal-mine
MMC (2013a): Mongolian and Chinese Enterprises Agreed to Collaborate to Develop Coal Transportation
Infrastructure and Promote Bilateral Coal Trade, Mongolia Mining Corporation, 29 October 2013.
http://www.mmc.mn/admin/wp-content/uploads/2013/10/MMC MOU-to-Build-Port-Railway- Eng-
final.pdf
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MMC (2013b): Baruun Naran mine, Mongolia Mining Corporation, 2013. http://www.mmc.mn/proiects-
mining-baruun.html
MNEC (2010): Final Technical Report of a Pre-Feasibility Study of Methane Recovery and Utilization in the
Nalaikh Mine Area, Mongolia, Mongolia Nature and Environment Consortium under Cooperative
Agreement XA-833970 with U.S. Environmental Protection Agency, January 2010.
MNEC (2014): Coal Mine Methane (CMM) Resource Assessment and Emissions Inventory Development in
Mongolia, Mongolian Nature and Environment Consortium, 2014.
https://www.glohalmethane.org/Data/MNEC-CMM-Grant-Final-Report FINALpdf
Mongolian Mining Directory (2013): Mongolian Mining Directory, provided by Mining.mn, 2013.
MRAM (2009): Brief History (in Mongolian only), Mineral Resources Authority of Mongolia, Ulaanbaatar,
Mongolia, 2009.
http://www.mram.gov.mn/index.php?option=com content&view=category&layout=blog&id=5&Itemid=
24&lang=en
MRAM (2013): Main coal deposits of Mongolia, presented by the Mineral Resources Authority of Mongolia,
Ulaanbaatar, Mongolia, April 2013.
Ng (2013): Mongolia pins coal export ranking hopes on railway, Eric Ng, South China Morning Post, 29 August
2013. http: //www.scmp.com/business/commodities/article/1300243/mongolia-pins-coal-export-
ranking-hopes-railwav
Oxford (2013): New uses for coal in Mongolia, Oxford Business Group, 14 October 2013.
http://www.oxfordbusinessgroup.com/economic updates/new-uses-coal-mongolia#english
Proactive (2014): Aspire Mining to supply Ovoot coking coal to Sainshand Industrial Park, Proactive Investors
Australia, 9 April 2014. http: //www.proactiveinvestors.com.au/companies/news/54229/aspire-mining-
to-supply-ovoot-coking-coal-to-sainshand-industrial-park-54229.html
Prophecy (2013a): Prophecy Provides Update on Tugalgatai Transaction, Prophecy Coal Corp., 1 March 2013.
http://prophecycoal.com/prophecy-provides-update-on-tugalgatai-transaction/
Prophecy (2013b): Executive Summary, Prophecy Coal Corp., July 2013.
http://www.prophecvcoal.com/pdf/lulv 2013 - Executive summarv.pdf
Prophecy (2014a): Prophecy Coal Corp. Announces Annual Results and Outlook for 2014, Prophecy Coal
Corp., 8 April 2014. http: //prophecvcoal.com/prophecv-coal-corp-announces-annual-results-and-
outlook-for-2014/
Prophecy (2014b): Chandgana Coal Project, Prophecy Coal Corp., 2014.
http: II prophecy coal, com /pr oi ects / pr oi ect chandgana/
Prophecy (2014c): Ulaan Ovoo, Prophecy Coal Corp., 2014.
http://prophecvcoal.com/proiects/proiect ulaan ovoo/
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Stephen Schwochow,
chief editor, 1997.
SEC (2005): Storm Cat Energy Form 6-K Report of Foreign Issuer Pursuant to Rule 13a-16 and 15d-16 Under
the Securities Exchange Act of 1934, United States Securities and Exchange Commission, July 2005.
http : / / www.sec.gov / Archives / edgar / data /1178818/000121716005000124/ stormcat6kfori ulv2 005,ht
JH
South Gobi (2014): Development Projects, South Gobi Resources, 2014.
http://www.southgobi.eom/s/development-proiects.asp
Sproule (2010): Sproule Projects Asia, accessed February 2010. http: IIwww.sproule.com/Asia#title
Storm Cat (2005): Storm Cat Energy Corporation News Room Press Release, 13 July 2005.
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Tserenpurev (2008): Energy Development in the South Gobi Region, presented by Tserenpurev T., State
Secretary of the Ministry of Fuel and Energy, at the Infrastructure Strategy for Southern Mongolia Round
Table Discussion of the World Bank, 15 May 2008. http://go.worldbank.org/GLOKP2589Q
Tumurbaatar and Altanchimeg (2009): Law and Regulation for Coal Mine Methane Utilization and Expect, Z.
Tumurbaatar and D. Altanchimeg Ph.D., Mongolia Ministry of Fuel and Energy, Methane Recovery and
Utilization Opportunities, Methane to Markets Partnership, Ulaanbaatar, 2009.
http://www.globalmethane.org/documents/partners mongolia methane opportunity.pdf
UNFCCC (2001): Mongolia's First National Communication, National Agency for Meteorology, Hydrology, and
Environment Monitoring, 1 November 2001.
http://unfccc.int/essential background/library/items/3599.php?rec=i&priref=3195
UNFCCC (2014): Ratification Status - Mongolia, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=MN
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USEPA (2013a): Pre-feasibility Study for Coal Mine Methane Recovery and Utilization at Baganuur Mine, U.S.
Environmental Protection Agency, December 2013.
http://epa.gov/cmop/docs/2013%20Coal%20Mongolia%20Baganuur%20PFS.pdf
USEPA (2013b): Pre-feasibility Study for Coal Mine Methane Recovery and Utilization at Naryn Sukhait Mine,
U.S. Environmental Protection Agency, March 2013.
http://epa.gov/cmop/docs/Mongolia %20Naryn%20Sukhait%20Prefeasihility%20Study FINAL.pdf
World Bank (2004): Mongolia Mining Sector Sources of Growth Study, prepared by the World Bank East Asia
and Pacific Region, April 2004. http: //go.worldbank.org/EXUFR17XZl
World Bank (2014): Mining: Sector Results Profile, World Bank, 14 April 2013.
http://www.worldbank.org/en/results/2013/04/14/mining-results-profile
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23 New Zealand
23.1 Summary of Coal Industry
23.1.1 Role of Coal in New Zealand
Coal is New Zealand's most abundant fossil fuel and has been an important energy source since the
late nineteenth century. Today the majority of New Zealand's coal is used for electricity generation
(40 percent) and industrial processes (33 percent), with dairy and non-metallic mineral product
manufacturing (cement, lime, and plaster) being the largest industrial consumers of coal (MBIE,
2013). In 2013, New Zealand consumed approximately 2.9 million tonnes (Mmt) of coal, with a
significant portion used to generate electricity at Huntly, New Zealand's only coal-fired power
station (MBIE, 2013; Coal Association, 2012). Further, exportation of New Zealand's premium
bituminous coal has been a major growth area since about 1990 and is likely to continue being a
good prospect for the future as their coal is valued internationally for its low ash, sulfur content,
and other characteristics that allow blending with other coals for use in the steel industry (MBIE,
2013).
Table 23-1 indicates New Zealand's recoverable coal reserves to be about 570 Mmt The resource
itself is far more extensive and may offer greater recovery, ultimately. The total known in-ground
resource is estimated to exceed 15 billion tonnes, of which more than half is potentially recoverable
(MBIE, 2013).
Table 23-1. New Zealand's Coal Reserves and Production
Anthracite &
Sub-
Indicator
Bituminous
bituminous
Total
Global Rank
(million
tonnes)
& Lignite
(million tonnes)
(million tonnes)
(# and %)
EstimatedprovedCoalReserves 33 Q ^ 57L0 31(0.064%)
Annual Coal Production (2012] 4.6 0.33 4.93 33(0.06%]
Source: EIA (2014]
New Zealand is divided up in to North Island and South Island (Figure 23-1). Coal is found in the
Northland, Waikato, and Taranaki Coal Regions of the North Island. On the South Island, coal is
found in the Nelson, West Coast, Canterbury, Otago, and Southland Coal Regions (USGS, 2004). At
least 6.2 billion tonnes of lignite is technically and economically recoverable in 10 major deposits in
the South Island regions of Otago and Southland (P&M, 2014). The North Island in-ground resource
is about 2.4 billion tonnes and consists of almost entirely sub-bituminous coal (P&M, 2014).
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Figure 23-1. New Zealand's Coal Fields
LOCATION OF NZ COALFIELDS
AND RESOURCES
WEST COAST
resources:
SB 0.1 Bt
B0.9Bt
Legend
Northland
¦
Waikato
Tamneki
m
Nelson -Weslland
m
Canterbuiy
m
Otago
Southland
B~
Bitumincue
SB
Sub-Bituminous
L_
Lignite
OTAGO-SOUTHLAND
resources:
SB 0.2 Bt
Lignite 11 Bt
Source: MOED [2010]
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23.1.2 Stakeholders
Only a handful of companies operate coal mines in New Zealand. Most of New Zealand's coal is
produced by Solid Energy NZ Limited (P&M, 2014).
Key stakeholders involved in New Zealand's coal and the coal mine methane (CMM) development
industries are outlined in Table 23-2.
Table 23-2. Key Stakeholders in New Zealand's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
¦ Birchfield Coal
Project hosts
¦ Canterbury Coal
¦ Cascade Coal
¦ Crusader Coal
¦ Francis Mining
¦ Glencoal
¦ Harliwich Carrying Co.
¦ Heaphy Mining
¦ Kai Point Coal
¦ New Creek Mining
¦ O'Reilly's Opencast
¦ Puke Coal
¦ RJ Banks
¦ Rockies Mining
¦ Solid Energy
¦ Takitimu Coal
Developers
¦ See
Project opportunity
http://www.epa.gov/coalbed/networkcontacts.html
identification and
planning
Universities and Research
¦ Commonwealth Scientific and Industrial Research
Technical assistance
Centers
Organisation (CSIRO]
¦ University of Auckland
Government Groups
¦ Ministry of Commerce - Energy and Resources Division
Licensing
Source: P&M (2014]
23.1.3 Status of Coal and the Coal Mining industry
New Zealand's coal industry is vested in 22 surface and underground mines. Roughly 60 percent of
national production was from two large opencast operations, located at Rotowaro and Stockton
(P&M, 2014). Coal production statistics for 2012 by mine type are presented in Table 23-3. The
total number of mines has steadily decreased, and surface mining methods have become more
popular.
Table 23-3. New Zealand's Production and Mine Statistics (million tonnes)
Type of Mine
2012 Production
Number of Mines
Underground (active]
0.60
4
Surface (active]
4.33
18
Total
4.93
22
Sources: MBIE (2013]; P&M (2014]
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Despite increasing competition from hydroelectric power and from imported oil, annual coal
production has been sustained at or above the 1.8 Mmt level since 1907. Production has exceeded
3 Mmt since 1992, and it reached a peak of almost 5.7 Mmt in 2006 (MBIE, 2013).
Table 23-4 lists all major coal mines in operation in New Zealand.
Table 23-4. New Zealand's Major Operating Coal Mines
Coal Field
Mine
Coal Rank
Mine Type
Waikato
¦ Huntly
¦
Huntly East
sub-bituminous
underground
¦
O'Reilly's
sub-bituminous
surface
¦ Maramarua
¦
Kopako
sub-bituminous
surface
¦ Rotowaro
¦
¦
Awaroa
Pukemiro
sub-bituminous
sub-bituminous
surface
surface
West Coast
¦
Stockton
bituminous
surface
¦ Buller
¦
Cascade
bituminous
surface
¦
New Creek
bituminous
surface
¦
Rockies
bituminous
surface
¦ Garvey Creek
¦
Echo
bituminous
surface
¦ Greymouth
¦
¦
Roa
Strongman
bituminous
bituminous
underground
surface
¦ Inangahua
¦
Berlins Creek
sub-bituminous
surface
¦
Giles Creek
sub-bituminous
surface
¦
Burkes Creek
sub-bituminous
underground
¦ Reefton
¦
Reddale Valley
sub-bituminous
surface
¦
Terrace
sub-bituminous
underground
¦ Canterbury
¦ Canterbury
¦
Malvern Hills
sub-bituminous
surface
¦ Otago
¦ Kaitangata
¦
Castle Hill
sub-bituminous
surface
¦ Roxburgh
¦
Harliwich
lignite
surface
Southland
¦ Ohai
¦
Takitimu
sub-bituminous
surface
¦ Waimumu
¦
Newvale
lignite
surface
Source: P&M (2014]
Currently, little exploration for new reserves is taking place, and the industry is concentrating on
improving knowledge of reserves within the existing license areas. New Zealand's coal exports will
continue to grow—although there has been demand for premium-quality bituminous coal, there is
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also a growing international market for thermal coals, such as New Zealand's lower-grade
bituminous and sub-bituminous coals (USGS, 2004).
23.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
CMM recovery projects for New Zealand, in operation or under development (GMI, 2014). Updates
on future CMM projects in New Zealand can be found at https://www.globalmethane.org/coal-
mines/cmm/index.aspx.
23.2.1 CMM Emissions from Operating Mines
Most New Zealand coal production is from surface mines producing low rank coals at shallow
depths with low methane concentrations. Methane emissions from these coals are vented. The few
deep underground mines have high methane concentrations and are generally degasified with
ventilation and surface gob wells. To date, no current projects have been identified in surface or
underground mines where captured gas is utilized or marketed rather than vented.
Methane emissions in New Zealand totaled 23.8 million cubic meters (m3) in 2000, but are expected
to increase to 29.4 million m3 by 2015, and then anticipated to further increase to 36.4 million m3
by 2030 (see Table 23-5).
Table 23-5. New Zealand's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
23.8
23.1
27.3
29.4
Source: USEPA (2012]
23.2.2 CMM Emissions from Abandoned Coal Mines
No data about methane emissions from abandoned mines in New Zealand are available at this time.
23.2.3 CBM from Virgin Coal Seams
Estimates indicate New Zealand has a total of more than 2,000 petajoules or 53 billion m3 of CBM
reserves (Clark, 2008). No commercial wells are in production, but numerous exploratory and test
wells have been drilled.
At least 16 licenses had been issued for exploratory drilling and development of coal seam gas in
New Zealand (L&M, 2009), but as of 2014, the permits had either been surrendered or were about
to expire (SourceWatch, 2014). L&M Coal Seam Gas Ltd. (L&M CSG) previously held numerous
licenses, which covered coal resources ranging in rank from lignite to bituminous, with the bulk
being in the low rank coals. L&M CSG had drilled 52 exploratory wells and started their first pilot
project In 2009, L&M estimated they had about 1,500 petajoules (40 billion m3) of CBM reserves
(L&M, 2009). However, in 2012, the Director's report stated that although work had continued on
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the Ohai CSG pilot project, the results had been "disappointing" and commercial gas flow rates had
not been achieved (SourceWatch, 2014).
Other CSG explorers/permit holders include Solid Energy (and its U.S. CSG developer partner,
Resource Development Technology) and Macdonald-Chartwell, as well as Bridge Petroleum Ltd in
partnership with Transworld Exploration Ltd and Westech Energy, (Clark, 2008: RigZone, 2004).
23.3 Opportunities and Challenges to Greater CMM Recovery
and Use
As reflected in Table 23-6, New Zealand is a signatory to both the UNFCCC and the Kyoto Protocol.
New Zealand is an Annex I Party, and its emissions target under the Kyoto Protocol is to achieve
1990 levels by 2010.
Table 23-6. New Zealand's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 4,1992
September 16,1993
Kyoto Protocol
May 22,1998
December 19,2002
Source: UNFCCC (2014]
In 2013, the Government announced three national targets for reducing New Zealand's greenhouse
gas (GHG) emissions that cover both the medium and long term:
¦ An unconditional target of 5percent below 1990 GHG emissions levels by 2020.
¦ A conditional target range of 10 to 20 percent below 1990 GHG emissions levels by 2020, if
there is a comprehensive global agreement (e.g., post-Kyoto).
¦ A long-term target of 50 percent below 1990 GHG emissions levels by 2050 (MFE, 2014).
New Zealand also has an Emission Trading Scheme (ETS), which places a price on GHG emissions
(including methane) to provide an incentive to reduce emissions, invest in clean technology and
renewable power generation, and plant forests to absorb carbon dioxide. The stationary energy
sector (e.g., coal, natural gas, geothermal energy), for example, has obligations to report their
methane emissions, then acquire and surrender New Zealand Units (NZUs) or equivalent overseas
emission to offset these emissions.
23.3.1 Market and Infrastructure factors
New Zealand gas demand is projected to continue to increase significantly as domestic conventional
gas supplies decline more rapidly than expected. New domestic production from CBM/CMM is
therefore encouraged. New Zealand has considered imposing a carbon tax, however, in 2005, the
government decided to abandon their plans because emission savings were not justified by the cost
CMM and CBM infrastructure in New Zealand is not well developed; gas gathering, compression,
and transmission infrastructure will require significant investments.
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Any methane recovered in the future could be utilized by the power generation, heating, and
transportation sectors, as well as by the industrial sector for boilers, but it would have to compete
against gas suppliers and importers. The University of Auckland, the Commonwealth Scientific and
Industrial Research Organization (CSIRO), and other technology organizations are helping to
address technology issues associated with recovery of CMM and CBM resources.
23.3.2 Regulatory Information
The New Zealand coal mining industry has undergone major changes over the last 25 years. State-
owned coal mines were converted into a government-owned corporation. Natural gas regulations
are governed by the "Gas Act," which can be found at www.le gislation.govt.nz.
23.4 Profiles of Individual Mines
See P&M (2014) for links to available mine production data. Updates on future CMM projects in
New Zealand can be found at http: //www.globalmethane.org/coal-mines/cmm.index.aspx.
23.5 References
Clark (2008): "Gas Riches from our Coal," Lindsay Clark, Contrafed Publishing, Energy NZ No. 7, Summer
2008.
http://www.contrafedpublishing.co.nz/Energy+NZ/Issue+7+Summer+2008/Gas+riches+from+our+coal.
html
Coal Association (2012): World Coal Association Country Profile - New Zealand, Coal Association of New
Zealand, updated June 2012. http: //www.coalassociation.org/profile.htm
EIA (2014): International Energy Statistics. U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http: IIwww.eia.gov /cfapps /ipdbproi ect/1ED Index3.cfm
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
L&M (2009): L&M Coal Seam Gas Ltd - Presentation, L&M Coal Seam Gas Ltd, October 2009.
MBIE (2013): Coal Summary and Energy in New Zealand: Coal data tables for 2013, Ministry of Business,
Innovation & Employment, website accessed September 2014. http: IIwww.med.govt.nz /sectors-
industries / energy/ energv-modelling/data / coal
MFE (2014): New Zealand's greenhouse gas emissions reduction targets, Ministry for the Environment,
website accessed November 2014. http: //www.mfe.govt.nz/climate-change/reducing-greenhouse-gas-
emissions/emissions-reduction-targets
MOED (2010): New Zealand Coal Deposits, Ministry of Economic Development, 2010.
P&M (2014): Coal Resources, Petroleum & Minerals (P&M), website accessed September 2014.
RigZone (2004): "Bridge Awarded Three Drilling Permits in New Zealand," RigZone, 27 July 2004.
https://www.rigzone.com/news/oil gas/a/15086/Bridge Awarded Three Drilling Permits in New Zea
land
SourceWatch (2014): L&M Group, website accessed November 2014.
http://www.sourcewatch.org/index.php/L%26M Group
UNFCCC (2014): Ratification Status - New Zealand, United Nations Framework Convention on Climate
Change, website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=NZ
A
Methane Stive CMM Country Profiles 214
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NEW ZEALAND
USEPA (2012): Global Anthropogenic N011-CO2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2004): New Zealand Coal Resources Fact Sheet, U.S. Geological Survey, September 2004.
http://pubs.usgs.gOv/fs/2004/3089/fs2004-3089.html
CMM Country Profiles 215
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24 Nigeria
24.1 Summary of Coal Industry
24.1.1 Role of Coal in Nigeria
Nigeria ranks low in worldwide coal production, with less than 30 thousand tonnes of coal
production in 2012 (Table 22-1). Nigeria estimated its coal reserves at more than 2 billion tonnes,
with approximately 650 million tonnes (Mmt) as proven (OnlineNigeria, 2014). Other sources cite
different estimates, however, as shown in Table 22-1. Although coal was the first energy resource to
be exploited by Nigeria, a transition to diesel fuel for rail transport and to gas for electricity
generation led to a decrease in coal production. Coal production has dropped significantly from its
high of almost 1 Mmt in 1959.
Table 24-1. Nigeria's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million
tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
21.0
169.0
190.0
50 (0.021%]
(2011]
Annual Coal Production (2012]
0.03
0
0.03
65 (0.0004%]
Source: EIA (2014]
Nigeria's coal resources are located in the Cretaceous Anambra and Makurdi Basins, and Afikpo
Syncline (see Figure 24-1) and occur in two levels: the lower Mamu Formation and the upper
Nsukka Formation. Coal seams occur in three main stratigraphic levels (Ogunsola, 2008):
¦ The brown coals (lignite) of Ogwashi-Asaba Formation of Miocene to Pliocene ages
¦ The upper and lower sub-bituminous coal measures of Maastrichtian age
¦ The bituminous coals of the Awgu shales of Coniacian age
Its sub-bituminous coal is low in sulfur and ash content, making it attractive for export to Ghana
and Egypt and by European nations as well. Nigeria has Africa's largest deposits of lignite.
According to a 1987 Federal Republic of Nigeria document, reserves from coal seams in excess of 1
meter thick are: Ogboyoga (100 Mmt) in the north, and Okaba (70 Mmt), Orupka (60 Mmt), Ezimo
(50 Mmt), and Enugo (50 Mmt) in the south (OnlineNigeria, 2014).
\ /Global
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CMM Country Profiles 216
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NIGERIA
Figure 24-1. Nigeria's Coal Fields
• Ogbomosd
„ #Qshogbo
lbadan Benin
Lagosx,
Sight of
Benin
Ojjar .
yi Calabqr J Q.ukas>
Harcourt
Guff of GtifrtOQ q~/ \
equatorial'
6 GJINfcA
/"I Anambra Basin*
* Coal Deposits"'
Source: CIA (2010], *EarthByte [2008]
Table 24-2 identifies potential stakeholders in Nigerian coal mine methane (CMM) development
Table 24-2. Key Stakeholders in Nigeria's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies/Equity
¦ Kogi State Government*
Owner/operator
Owners
¦ Nigerian Coal Corporation (NCC]
Owner/operator
¦ Behre Dolbear and Company Inc.
Technical Expertise
Developers, Engineers,
¦ See
Project opportunity
Consultancy and Related
http://www.epa.20v/coalbed/networkcontacts.html
identification, planning
Services
and assistance
Natural Gas Transmission
¦ British Gas
Gas distribution
& Distribution Companies
¦ BP
¦ Chevron
¦ Conoco
¦ Deminex
¦ ENI/Agip
¦ ExxonMobil
A
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Table 24-2. Key Stakeholders in Nigeria's CMM Industry
Stakeholder Category
Stakeholder
Role
Regulatory Agencies
¦ Nigerian National Petroleum Corporation - Department
CMM project promotion.
of Petroleum Resources
registration of exploration
and development
companies
Government Groups
¦ Ministry of Mines and Steel Development
Granting and approval of
¦ National Chamber of Commerce, Industries - Mining and
leases
Agriculture
¦ Federal Ministry of the Environment
¦ Mining Cadastre Office
Responsible for mineral
titles
¦ Mines Inspectorate Department
Health and Safety
administration and
enforcement
¦ Small Scale Mining Department
Organization, support and
assistance to small scale
miners
Sources: EIA (2013]; *USGS (2014]
24.1.2 Status of Coal and the Coal Mining Industry
The Nigerian government is seeking to increase the country's level of coal utilization to help stem
the loss of its forests to domestic fuel-wood harvesting and to help reduce its overdependence on
oil. At present, however, coal remains the smallest contributor to the overall fuel mix. As per the
International Energy Agency (IEA), coal is not part of Nigeria's total primary energy supply in 2011
(IEA, 2013).
Current uses for coal in the country are in cement production, brick factories, foundries, laundries
and bakeries, tire manufacture, battery manufacture, and domestic cooking fuel (i.e., smokeless coal
briquettes). Nigerian coal can be blended with imported coals for coke production, and it is
projected that as much as 200,000 tonnes per year of Nigerian coal could be directed to supply coke
to the Ajaokuta Steel Plant once it begins full operation. Using coal to manufacture smokeless
briquettes for home cooking fuel has the added benefit of producing by-products such as gases,
ammonia, tar oils, and various aromatics that can be used as chemical feedstocks. Nigeria has also
determined that its coal is suitable fuel for use at the abandoned Oji Power Station, as well as at
other proposed power generation facilities.
Nigeria's generation capacity was 6,000 MW in 2012, of which 79 percent was fired by fossil fuels,
principally natural gas. Generation capacity is projected to increase to 25,000 MW by 2020, and
fossil fuels are expected to account for 20,000 MW of the total capacity (EIA, 2013; Essien &
Igweonu, 2014). Plans call for coal to provide for a significant portion of the projected electric
power demand due to Nigeria's large reserve base. By 2020, almost 14 percent of generation
capacity is expected to be coal-fired growing to 15.6 percent by 2030 (Sambo, 2008). Consequently,
coal demand is projected to increase. In addition to such domestic uses, Nigeria estimates that
export demand for its coal could reach 15 Mmtper year (M2M, 2006).
Table 24-3 provides an overview of coal mines and mining methods used in Nigeria.
<
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Table 24-3. Nigeria's Coal Mines
Estimated
Proven
Mine
Coal Type
Reserves
Reserves
Depth of
Mining
(million
tonnes)
(million
tonnes)
Coal(m)
Method(s)
Okpara
¦ Sub-bituminous
100
24
180
Underground
Onyeama
¦ Sub-bituminous
150
40
Underground
Ihioma
¦ Lignite
40
N/A
20-80
Surface
Ogboyoga
¦ Sub-bituminous
427
107
20-100
Surface and
underground
Ogwashi
¦ Lignite
250
63
15-100
Surface and
Azagba/Obomkpa
underground
Ezimo
¦ Sub-bituminous
156
56
30-45
Surface and
underground
Inyi
¦ Sub-bituminous
50
20
25-78
Surface and
underground
Lafia/Obi
¦ Bituminous
(cokable]
156
21.42
80
Underground
Oba/Nnewi
¦ Lignite
30
N/A
18-38
Underground
Afikpo/Okigwe
¦ Sub-bituminous
50
N/A
20-100
Underground
Amasiodo
¦ Bituminous
1,000
N/A
563
Underground
Okaba
¦ Sub-bituminous
250
73
20-100
Surface and
underground
Owukpa
¦ Sub-bituminous
75
57
20-100
Surface and
underground
Ogugu/Awgu
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Afuji
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Ute
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Duho
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Kurumu
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Lamja
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Garin Maigunga
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Gindi Akwati
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Janata Koji
¦ Sub-bituminous
N/A
N/A
N/A
Underground
Sources: M2M (2006]; Ogunsola (2008]
24.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
CMM recovery projects in Nigeria (GMI, 2014). Updates on future CMM projects in Nigeria can be
found at https://www.globalmethane.org/coal-mines/cmm/index.aspx.
24.2.1 CMM Emissions from Operating Coal Mines
Table 24-4 reports Nigeria's historical and projected CMM emissions.
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Table 24-4. Nigeria's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
23.8
63.7
67.2
70.7
Source: USEPA (2012]
24.2.2 CMM Emissions from Abandoned Coal Mines
No data quantifying methane emissions from abandoned mines were found.
24.2.3 CBM from Virgin Coal Seams
No data quantifying methane production from virgin coal seams were found.
24.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Nigeria has signed and ratified the UNFCCC and has ratified the Kyoto Protocol (see Table 24-5). As
a non-Annex 1 country, Nigeria is eligible to host Clean Development Mechanism (CDM) projects
that can earn revenue from the sale of carbon credits. While there are some CDM projects related to
landfill gas and fugitive emissions (e.g., oil and gas systems) in Nigeria, there are presently no CDM
projects related to coalbed/mine methane (UNEP, 2014).
Table 24-5. Nigeria's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 13,1992
August 29,1994
Kyoto Protocol
—
December 10,2004 (Acceptance]
Source: UNFCCC (2014]
The Government of Nigeria acknowledged the importance of developing a national response to
climate change, and took steps to build a governance structure to manage the issue. The
Government first created a national focal point: the Special Climate Change Unit (SCCU) within the
Federal Ministry of Environment and also mobilized the Inter-ministerial Coordinating Committee
on Climate Change (BNRCC, 2011). In 2010, the National Assembly passed a bill to create a National
Climate Change Commission, which facilitated coordination and support for the multi-level and
cross-sectoral adaptation responses, development of a National Climate Change Policy for Nigeria,
and of a Nationally Appropriate Mitigation Action (NAMA) programme. In 2011, the Government of
Nigeria and a number of civil society organizations embarked upon the development of an initial
adaptation strategy and climate change action plan for Nigeria. In September 2012, the Federal
Executive Council approved the adoption of the National Policy on Climate Change and Response
Strategy (NPCC-RS) as a national document for implementing climate activities in Nigeria (Daily
Independent, 2012).
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NIGERIA
24.3.1 Market and Infrastructure Factors
Nigeria's robust natural gas industry provides a market conducive to CMM development. The
expected increase in gas infrastructure will enhance the ability to move drained CMM from the
wellhead to market. On the other hand, Nigeria has such substantial gas resources that
supplemental streams captured at coal fields may appear relatively insignificant in comparison,
thereby diluting interest in CMM development. Also, the amount of CMM that can be recovered in
conjunction with coal mining has been reduced over time.
24.3.2 Regulatory Information
Nigeria has the largest natural gas reserves in Africa and is among the top 10 holders of natural gas
proven reserves in the world. However, due to inadequate gas infrastructure, Nigeria has flared as
much as 75 percent of the gas it produces, accounting for about 10 percent of all gas flared
worldwide in 2011 (EIA, 2013). New Nigerian policy seeks to reduce gas flaring by using the gas as
feedstock in liquefied natural gas (LNG) processing facilities.
The national government, specifically the Nigerian Coal Corporation (NCC), owns 100 percent of the
Nigerian coal industry, but the government's monopoly of coal mining is being relaxed. Beginning in
1990, the NCC initiated efforts to privatize the coal industry by entering into several different joint
venture arrangements. While the initial joint ventures have not been successful, the privatization
efforts are still being pursued (Ogunsola, 2008).
As part of Nigeria's general privatization plan for the energy sector, the NCC is itself being putup
for sale by the Bureau of Public Enterprises (BPE), with some assets being sold individually to pay
off accumulated debt (Compass, 2009a; Compass, 2009b). Also, as part of the privatization plans,
the coal resources of Nigeria have been divided into 10 prospective blocks and putup for auction.
Nine of the blocks were bid for and won by four companies - one Nigerian and three foreign - with
the expertise and finances to make use of the resources (Africa, 2010). These sales to capable
companies should improve the investment and development climate.
The government also regulates and supervises natural gas production through the Nigerian
National Petroleum Corporation (NNPC), formed in 1977. In 1988, the NNPC was commercialized
into 12 strategic business units (or subsidiaries), covering the entire spectrum of oil industry
operations: exploration and production, gas development, refining distribution, petrochemicals,
engineering, and commercial investments. In addition to these subsidiaries, the industry is also
regulated by the Department of Petroleum Resources (DPR), a department within the Ministry of
Petroleum Resources, that ensures compliance with industry regulations, processes applications for
licenses, distributes leases and permits, and establishes and enforces environmental regulations
(NNPC, 2014). The Nigerian Gas Company Limited (NGC), one of the 11 NNPC subsidiaries, is
charged with the responsibility of developing an efficient gas industry to fully serve Nigeria's
energy and industrial feedstock needs through an integrated gas pipeline network (NGC, 2014).
Currently, there exist two types of gas operator agreements in Nigeria: joint operating agreements
and production sharing agreements. Coal mining leases can be obtained either through an approved
(by the Ministry of Mines and Steel Development) acquisition of an existing mining property or by
applying for a Prospecting Right or License. Gas producers must perform gas field optimization
analyses on their concessions and the government is responsible for optimization of gas field
development overall.
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Nigeria's efforts to wean its population away from harvesting timber for cooking fuel may stimulate
coal production and CMM development. As mentioned above, however, the current low level of coal
production in the country is not conducive to a robust CMM development industry.
24.4 Profiles of Individual Mines
Adequate data to profile individual mines is not available.
24.5 References
Africa (2010): Nigeria's Coal Deposits Identified, How We Made It In Africa, 19 May 2010.
http://www.howwemadeitinafrica.com/nigerian-coal-deposits-identified
BNRCC (2011): National Adaptation Strategy and Plan of Action on Climate Change for Nigeria (NASPA-CCN),
Building Nigeria's Response to Climate Change project, November 2011.
http://nigeriaclimatechange.org/naspa.pdf
CIA (2010): The World Factbook - Nigeria, Central Intelligence Agency, June 2010.
https://www.cia.gov/library/publications/the-world-factbook/geos/ni.htinl
Compass (2009a): New Lease of Life for Coal Corporation, Nigerian Compass Newspaper, 7 April 2009.
Compass (2009b): Nigerian Coal Corporation not for winding up, says BPE, Nigerian Compass Newspaper, 8
October 2009.
Daily Independent (2012): "Nigeria adopts climate change policy document," September 2012.
http://dailyindependentnig.eom/2012/09/nigeria-adopts-climate-change-policy-document/
EarthByte (2008): ICONS atlas: AFR - Anambra Basin, EarthByte.org, 8 March 2008.
http://www.earthbyte.org/Resources/ICONS/AFR/AnambraBasin/AFR.AnambraBasin.html
EIA (2013): Country Analysis Brief - Nigeria, U.S. Energy Information Administration, Washington, DC, last
updated 30 December 2013. http://www.eia.gov/countries/country-data.cfm?fips=NI
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC, data
accessed July 2014. http: //www.eia.gov/cfapps/ipdhproiect/IEDIndex3.cfm
Essien, A.U and Igweonu, E.I (2014): Coal Based Generation: A Solution to Nigeria's Electricity Problem,
International Archive of Applied Sciences and Technology, 2014.
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed in July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
IEA (2013): Energy Statistics: Share of total primary energy supply in 2011 - Nigeria, International Energy
Agency, Paris, France, 2013. http://www.iea.org/stats/WebGraphs/NIGERIA4.pdf
M2M (2006): Nigeria's Country Report on Coal Mine Methane Recovery and Use, presented at the Methane to
Markets Regional Workshop, Tuscaloosa, Alabama, USA, 25 May 2006.
https://www.glohalmethane.org/documents/events coal 20060525 nigeria.pdf
NNPC (2014): Nigerian National Petroleum Corporation - Corporate Info, website accessed July 2014.
http://www.nnpcgroup.com/AboutNNPC/CorporateInfo.aspx
NGC (2014): Nigerian Gas Company Limited (NGC), website accessed July 2014.
http://www.nnpcgroup.com/nnpchusiness/suhsidiaries/ngc.aspx
Ogunsola (2008): Personal communication with Dr. Olubunmi Ogunsola, TEMEC, 7 July 2008.
OnlineNigeria (2014): Coal and Lignite, OnlineNigeria, webpage accessed July 2014.
http://www.onlinenigeria.com/geology/?blurb=510
CMM Country Profiles 222
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Sambo (2008): Matching Electricity Supply with Demand in Nigeria, A.S. Sambo, A. S. Sambo, Director General
of the Energy Commission of Nigeria, International Association for Energy Economics, Fourth Quarter
2008. https://www.iaee.org/documents/newsletterarticles/408sambo.pdf
UNEP (2014): CDM/JI Pipeline Analysis and Database, United Nations Environment Programme Danish
Technical University Partnership, accessed July 2014. http: IIcdmpipeline.org/index.htm
UNFCCC (2014): Ratification Status - Nigeria, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=NG
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2014): 2012 Minerals Yearbook - Nigeria [Advance Release], U.S. Geological Survey, U.S. Department of
the Interior, February 2014. http: //minerals.usgs.gov/minerals/pubs/country/2012 /myb3-2012-ni.pdf
CMM Country Profiles 223
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25 Pakistan
25.1 Summary of Coal Industry
25.1.1 Role of Coal in PAKISTAN
Coal had historically been the primary fossil fuel for Pakistan with the major consumers being
railways, cement, fertilizer, and power plants. This held true until large deposits of oil and natural
gas were discovered in the 1960s (PakistanEcon, 2001). As of 2011, coal provided for only 6
percent of Pakistan's total primary energy consumption, compared to natural gas at 47 percent and
petroleum at 35 percent (EIA, 2014). Pakistan is facing an unprecedented energy crisis due to a
surging demand and supply gap. Its current energy needs are heavily dependent on oil and gas and
the demand far exceeds its indigenous resources such as coal, hydro, and renewable sources
(PakMinPlan, 2014). The current demand and supply gap of 5,000-8,000 MW and demand growing
at 8 percent per year ensures guaranteed uptake of power produced by independent power
producer projects at market competitive prices (BOI, 2014).
Pakistan has one of the world's largest lignite reserves in the Tharparkar district of Sindh, found in
the early 1990s and estimated at more than 185 billion tonnes (PakTribune, 2010). Table 25-1
indicates Pakistan's recoverable coal reserves to be 2,070 million tonnes (Mmt). Total estimated
resources are far more extensive and may offer greater recovery ultimately. The total in-ground
resource is estimated to be 185,000 Mmt, of which about 2,000 Mmt are presently mineable and
3,400 Mmt are measured (PakGeoSurvey, 2014).
Table 25-1. Pakistan's Coal Reserves and Production
Anthracite &
Sub-bituminous
Total
Global
Indicator
Bituminous
& Lignite
(million
Rank
(million tonnes)
(million tonnes)
tonnes)
(# and %)
Estimatedprovedc°alReserves Q 2,070 2,070 21(0.2
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PAKISTAN
Figure 25-1. Pakistan's Coal Fields
Source: PakGeoSurvey (2004)
Geological Survey of Pakistan
2004
Prepared by M.lshaq Ghaznavl & Tahir Karlm
© copyright Geological Survey o(Pekis?an
MAP SHOWING THE LOCATIONS OF COAL FIELD
AND COAL OCCURRENCES OF PAKISTAN
Coal Fields
1. Indus East 11. Duki
2. Sonda-Thatta-Jherruck 12. Chamalang
-Ongar -|3 Makarwal-Kurd-Sho
3. Meting-Jhimpir 14 Sa|t Range
4. Lakhra 15. Hangu
5. Badin 16. Cherat -S,*"
6. Thar (Northern & Southern)! 7. Kotli
7. Mach-Abegum
8. Pir Ismail Ziarat
9. Sor Range-Dighari
10.
Coal Occurrences
18. Dureji
19. Balgor
20. Johan
21. Margat
22. Kach
23. Badizai
24. Choi
25. Rashit
25.1.2 Stakeholders
State-owned companies control the production and marketing of coal. The Mineral Department of
the Ministry of Petroleum and Natural Resources is responsible for the exploration, planning,
development, and operation of mining ventures that are controlled by the state-owned companies
(USGS, 2014). The Government of Sindh and the Thar Coal Development Authority are other
governmental bodies that claim ownership and/or control over the resources.
Key stakeholders involved in Pakistan's coal and the coal mine methane (CMM) development
industries are outlined in Table 25-2.
Table 25-2. Key Stakeholders in Pakistan's CMM Industry
Stakeholder Category
Stakeholder
Role
Developer
¦ Cathay Oil & Gas Ltd.
Holds rights to CBM and
groundwater in Sindh
* M/s Rheinbraun Engineering
Mining feasibility studies
¦ Lakhra Coal Development Authority [LCDC]
Project development
¦ Pakistan Mineral Development Corporation (PMDC)
Project development
¦ Deep Rock Drilling (pvt) Ltd.
Mining feasibility studies
Mining Companies
¦ Kathwai Coal Mines Pvt Ltd
Project hosts
¦ Habibullah Mines Ltd.
¦ United Musakhel Mining Company (Pvt) Limited
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PAKISTAN
Table 25-2. Key Stakeholders in Pakistan's CMM Industry
Stakeholder Category
Stakeholder
Role
Universities and Research
¦ Pakistan Institute of Engineering and Applied
Technical assistance
Centers
Sciences, Islamabad
¦ National University of Sciences & Technology
Rawalpindi
¦ Ghulam Ishaq Khan Institute of Engineering, Swabi
¦ University of Eng. & Technology (UET), Lahore
Energy Companies
¦ Habibullah Energy Limited (HEL]
¦ Pak Energy (Pvt] Ltd
¦ Pakistan Electric Power Company (PEPCO]
Investment, energy
production
Investment Groups
¦ A1 Abbas Group
Investment
Government Groups
¦ Ministiy of Petroleum and Natural Resources
Licensing, exploration,
production
¦ Thar Coal Development Authority, Government of
Licensing, exploration.
Sindh,
production
¦ Geological Survey of Pakistan
Technical assistance
¦ Hydrocarbon Development Institute of Pakistan
Technical assistance
(HDIP]
25.1.3 Status of Coal and the Coal Mining industry
The contest between the national and provincial governments over the energy resources of
Pakistan has stalled some development efforts. As part of a larger government plan to boost private
sector ownership and involvement in industry and energy sectors, some government-created
entities like the Lakhra Coal Development Authority (LCDC) have been transitioned to public-
private entities. The goal is to encourage development and take advantage of market efficiencies,
but these efforts have not been entirely successful. In 2007, the LCDC had 44 mines fully developed
and capable of each producing 40 to 50 tonnes of coal per day, with another 39 mines under
development (PakMinPet, 2007). After 17 years of operation, LCDC had developed less than 30
percent of the potential 149 mines in the Lakhra field and is able to meet only 60 percent of the coal
requirements of the associated Lakhra power plant, which is often forced to operate below capacity
(Siddiqui, 2008).
Additionally, American, Chinese, and German companies, among others, have been brought in to
provide mining feasibility studies to encourage international investment, but questions over coal
quality, infrastructure, and government support have caused many potential international
investors to pull out of major projects (Haider, 2007; PakTribune, 2010).
Pakistan is still in the process of drafting a national coal policy. There have been repeated attempts
to draft a policy since at least 2001, but they have not been successful as yet (Bhutta, 2010;
Siddiqui, 2008). This lack of policy has hurt the development of the Thar deposits found in the
1990s and has impeded Pakistan's progress in developing mining technologies and attracting CMM
investments (Chaudhry, 2007).
Table 25-3 lists some of the major coal mines in operation in Pakistan.
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PAKISTAN
Table 25-3. Operating Coal Mines in Pakistan
Coal Field
Mine
Coal Rank
Mine Type
Operator
¦ Lakhra* ¦
1 Lakhra Collieries
Sub-bituminous to
lignite
underground
PMDC
¦ Degari- Sor-Range* ¦
1 Degari Collieries
Sub-bituminous-A to
high volatile B-
bituminous
underground
PMDC
¦ Degari- Sor-Range* ¦
1 Sor- Range
Sub-bituminous-A to
high volatile B-
bituminous
underground
PMDC
¦ Shahrig- Khost- Harnai* ¦
1 Shahrig
Sub-bituminous-A to
high volatile B-
bituminous
underground
PMDC
¦ Lakhra Coal Field ¦
1 Multiple
Sub-bituminous to
lignite
underground
LCDC
Sources: *PMDC (2014]; **MBendi (2014]
25.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
projects in Pakistan, in operation or under development (GMI, 2014). Updates on future CMM
projects in Pakistan can be found at https: //www.globalmethane.org/coal-mines/cmm/index.aspx.
25.2.1 CMM Emissions from Operating Mines
Methane emissions in Pakistan totaled 66.5 million cubic meters (m3) in 2000, but are projected to
increase to 86.8 million m3 by 2015, and then anticipated to further increase to 119 million m3 by
2030 (see Table 25-4).
Table 25-4. Pakistan's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
66.5
105.0
79.1
86.8
Source: USEPA (2012]
25.2.2 CMM Emissions from Abandoned Coal Mines
No data about methane emissions from abandoned mines in Pakistan are available at this time.
25.2.3 CBM from Virgin Coal Seams
In 2007, Cathay Oil & Gas Ltd. (a Canada-based company) acquired sole rights to coal bed methane
(CBM) and groundwater in Sindh, including the Thar coal field. The field has an estimated 1.0
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trillion m3 of CBM resource and up to 0.6 trillion m3 of recoverable gas (USEPA, 2007). In 2013,
Cathay obtained the go-ahead to explore and develop the CBM resources under the "Thar Coal
Methane project" that aims to produce 0.14 trillion m3 of methane gas over a 30-year period
(Business Recorder, 2013).
25.3 Opportunities and Challenges to Greater CMM Recovery
and Use
As reflected in Table 25-5, Pakistan is a signatory to both the UNFCCC and the Kyoto Protocol.
Pakistan is a Non-Annex I Party.
Table 25-5. Pakistan's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 13,1992
June 1,1994
Kyoto Protocol
-
January 11,2005
Source: UNFCCC (2014]
In 2013, Pakistan's Ministry of Climate Change in Islamabad launched its first National Climate
Change Policy. The policy was approved in September 2012 and provides a framework for coping
with the impacts of climate change through adaptation and mitigation measures. Promotion of
renewable energy sources and efficient mass transport systems are in the lineup of policy measures
and financing options for projects include the Green Climate Fund and formation of a National
Climate Change Fund (Express Tribune, 2013).
25.3.1 Market and Infrastructure factors
Pakistan has experienced low domestic demand for coal resources, though this is beginning to
change as domestic oil and natural gas suppliers reach production limits and as international
energy prices increase. Despite this improving environment, conflicts between the various
controlling interests within the Pakistani government have prevented a unified approach to coal
resources and coal mining and thus to CMM/CBM utilization. Until there is a national coal policy
and strong government interest in and focus on developing coal resources, there will not be a
strong domestic market for development, nor strong international interest or confidence for
investment.
Further, CMM and CBM infrastructure in Pakistan is practically non-existent currently; gas
gathering compression, and transmission infrastructure will be needed before any significant
production is viable. Significant investment in coal mining infrastructure including basic resource
survey and access to key supporting resources like water, roads, and electrical transmission lines
will be needed before there is sufficient capability and potential for CMM/CBM development
25.3.2 Regulatory Information
Pakistan is transitioning many of the minerals and natural gas entities from government ownership
and control to private ownership or public-private ownership. This is part of a larger effort toward
deregulation, reducing government debt burden, and taking advantage of the improved efficiency of
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market forces. The Privatization Commission (http://www.privatisation.gov.pk/) is responsible for
the transition.
The Ministry of Petroleum and Natural Resources governs the activities and regulations for the coal
mining industry and CMM/CBM industry. The ministry recently released a National Petroleum
Policy (PakMinPet, 2009) and is drafting a National Coal Policy.
25.4 Profiles of Individual Mines
Individual mine profiles are unavailable.
25.5 References
Bhutta (2010): New refinery, oil storage facility planned in 2010-11, Zafar Bhutta, Business Recorder, 13 June
2010. http://www.hrecorder.eom/top-stories/single/595/0/1069334
BOI (2014): Investment Sectors: Power & Energy, Pakistan Board of Investment, accessed July 2014.
http://boi.gov.pk/Sector/SectorDetail.aspx?sid=2
Business Recorder (2013): CM Sindh gives go ahead to Canadian oil & gas firm for MoU, Business Recorder, 7
September 2013. http://www.brecorder.com/pakistan/business-a-economy/134841-cm-sindh-gives-
go-ahead-to-canadian-oil-.html?-gas-firm-for-mou=
Chaudhry (2007): EOIs for National Coal Policy, Muhammad Bashir Chaudhry, DAWN, 29 October 2007.
http://www.dawn.coin/2007/10/29/ebrl O.htm
EIA (2014): International Energy Statistics. U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http: IIwww.eia.gov /cfapps /ipdbproi ect/1ED Index3.cfm
Express Tribune (2013): Pakistan launches first National Climate Change Policy, The Express Tribune, 27
February 2013. http://tribune.com.pk/story/513157/paradigm-shift-pakistan-launches-first-national-
climate-change-policv
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
Haider (2007): China Quits $1.5bn Pakistan Coal Project, Syed Fazl-e-Haider, Asia Times, 18 May 2007.
http: //www.atimes.com/atimes/South Asia/IE18Df04.html
MBendi (2014): Coal Mining in Pakistan - Overview, MBendi, website accessed November 2014.
http://www.mbendi.eom/indy/ming/coal/as/pk/p0005.htm
PakGeoSurvey (2004): Map Showing the Locations of Coal Field and Coal Occurrences of Pakistan, Pakistan
Geological Survey, 2004.
PakGeoSurvey (2014): Quality and Coal Resources of Pakistan, Geological Survey of Pakistan, accessed July
2014. http://www.gsp.gov.pk/images/qualityandcoalresourcesofpakistan.pdf
PakistanEcon (2001): Coal, Pakistan & Gulf Economist, July 2001.
http://www.pakistaneconomist.com/database2/cover/c20Ql-41.asp
PakMinPet (2007). Year Book 2006-2007, Pakistan Ministry of Petroleum & Natural Resources, 2007.
PakMinPet (2009): Petroleum Policy 2009, Pakistan Ministry of Petroleum & Natural Resources, 2009.
PakMinPlan (2014): Chapter 10 - Energy Security and Affordability, Annual Plan 2013/14, Pakistan Ministry
of Planning, Development & Reform, 2014. http: / /pc.gov.pk/annual%20plans /2013-14/10-Energy.pdf
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PakTribune (2010): World Bank Not to Fund Thar Coal Project, PakTribune, 29 May 2010.
http://paktribune.com/news/World-Bank-not-to-fund-Thar-coal-proiect-spokesperson-228032.html
PMDC (2014): Projects - Coal Mines, Pakistan Mineral Development Corporation, accessed July 2014.
http: II www.pmdc. gov.pk/?p=Pr oi ects
Siddiqui (2008): Viability of Thar Coal Mining Company, Hussain Ahmad Siddiqui, Business Recorder, 27
March 2008. http: //www.defence.pk/forums/economy-development/10639-viahility-thar-coal-mining-
companv.html
UNFCCC (2014): Ratification Status - Pakistan, United Nations Framework Convention on Climate Change,
accessed November 2014. http: //maindb.unfccc.int/public/country.pl?country=PK
USEPA (2007): Coalbed Methane Extra, Fall 2007, U.S. Environmental Protection Agency, Coalbed Methane
Outreach Program, 2007. http: //www.epa.gov/cmop/docs/fall 2007.pdf
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2014): 2012 Minerals Yearbook - Pakistan, United States Geological Survey, March 2014.
http://minerals.usgs.gov/minerals/pubs/country/2012/myb3-2012-pk.pdf
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26 Philippines
26.1 Summary of Coal Industry
26.1.1 Role of Coal in the Republic of the Philippines
Currently, coal-fired thermal power plants remain the number one producer of electricity and
accounted for a total of 5,568 megawatts (MW), or 33 percent, of the Republic of the Philippines'
total installed power generating capacity in 2012 (PDOE, 2014a). The Philippines consumed 16.3
million tonnes (Mmt) of coal in 2012, around 75 percent of which was for power generation (EIA,
2014; Ocampo, 2012). The Philippines relies on imports to meet coal demand, importing 10.6 Mmt
from Indonesia and 277 thousand tonnes from Vietnam in 2011 (Ocampo, 2012). The Philippine
Energy Plan 2012-2030 (PEP) projects coal demand to increase by more than 70 percent between
2012 and 2030 (PDOE, 2014b).
The country's recoverable coal reserves, as shown in Table 26-1, are estimated at 315 Mmt, with
most reserves as lignite. Total coal resources compiled by the Geothermal and Coal Resources
Development Division (GCRDD) of the Department of Energy of the Philippines, are estimated at a
minimum of 2,268.4 Mmt (USGS, 2006).
The Philippines produced 8.0 Mmt of coal in 2012, the highest annual production to date. Coal
production is increasing rapidly, more than doubling between 2008 and 2012 (EIA, 2014). The PEP
projects domestic coal production to continue to increase, reaching more than 11 Mmt in 2015 and
more than 12.5 Mmt in 2020 (PDOE, 2014b).
Table 26-1. Philippines' Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
41
275
315
41 (0.04%]
(2011]
Annual Coal Production (2012]
8.0
0.0
8.0
29 (0.10%]
Source: EIA (2014]
The combined lignite and sub-bituminous coal reserves of the Philippines, including indicated and
inferred reserves, are about 1,899.2 Mmt, which make up about 84 percent of the total coal reserves
of the Philippines. The remaining reserves are composed of bituminous and semi-anthracite coal
(USGS, 2006).
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The Philippines has 19 coal districts. The largest total coal resource is estimated at 570 Mmt of sub-
bituminous coal and is located in the Semirara coal district located on Semirara Island, which is
located approximately 280 kilometers to the south of Manila and can be seen in Figure 26-1 below,
just south of Mindoro (Ocampo, 2012). The northern part of Semirara Island is dominated by the
Panian coalfield, the largest of three coalfields on the island. Other coalfields on Semirara include
the East Panian, and Himalian coalfields (USGS, 2006). A fourth coalfield, the Unong coalfield, has
been mined out Other coal districts with large reserves include Cagayan-Isabella of northern Luzon
and Sultan-Kudarat of Mindanao. Reserves and coal rank for all of the Philippines' coal districts are
shown in Table 26-2 below.
Figure 26-1. Philippines' Coal Resources
Philippine Sea
) isapena
T TT7HM )
PHILIPPINES
l.ManilaV
a t—fii > r\T i tj j
OjCATANDUANES L
S-JrPanganiban
Sources: Modified from Schwochow (1997]; USGS (2006]
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Table 26-2. Philippines' Coal Districts
Coal District
Coal Rank
Coal Reserves
(million tonnes)
Samar-Leyte
Lignite
27.0
Cotabato
Sub-bituminous/Lignite
230.4
Quirino
Sub-bituminous/Lignite
0.7
Cagayan-Isabella
Sub-bituminous/Lignite
336.0
Sarangani
Sub-bituminous/Lignite
120.0
Sultan-Kudarat
Sub-bituminous/Lignite
300.3
Sorsogon
Sub-bituminous
1.0
Negros
Sub-bituminous
4.5
Davao
Sub-bituminous
100.0
Batan Island
Sub-bituminous
11.8
Masbate
Sub-bituminous
2.5
Quezon-Polilio
Sub-bituminous
6.0
Semirara
Sub-bituminous/Bituminous
570.0
Surigao
Sub-bituminous/Bituminous
209.0
Zamboanga-Sibugay (Malangas]
Sub-bituminous/Bituminous
45.0
Cebu
Sub-bituminous/Bituminous
165.0
Catanduanes
Bituminous/Anthracite
1.2
Bukidnon
Unknown
50.0
Maguindanao
Unknown
108.0
Sources: USGS (2006]; Ocampo (2012]
26.1.2 Stakeholders
Table 26-3 identifies potential key stakeholders in the Philippines' coal mine methane (CMM)
development
Table 26-3. Key Stakeholders in the Philippines' CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies
¦ 3 Kings Sunrise Mining Corp.
Project hosts
¦ A Blackstone Energy Corp.
¦ Abacus Coal Exploration & Development Corp.
¦ Adlaon Energy Development Corp.
¦ Agusan Petroleum & Mineral Corp.
¦ Aragorn Coal Resources, Inc.
¦ ASK Mining & Energy Corp.
¦ Batan Coal Resources Corp.
¦ Benguet Corp.
¦ Bislig Ventures Construction & Development Corp.
¦ Blackgem Resources & Energy, Inc.
¦ Bonanza Energy Resources, Inc.
¦ Brixton Energy & Mining Corp.
¦ Calatrava Coal Corp.
¦ Cedaphil Mining Corp.
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Table 26-3. Key Stakeholders in the Philippines' CMM Industry
Stakeholder Category
Stakeholder Role
Mining companies (con't]
¦ Coal Mountain Ventures, Inc. Project hosts
¦ Core8 Mining Corp.
¦ D.M. Consunji-Construction Equipment Resources, Inc.
¦ D.M. Wenceslao & Associates, Inc.
¦ Daguma Agro-Minerals, Inc.
¦ Dell Equipment & Construction Corp.
¦ E-Oil & Gas Company, Inc.
¦ Filsystems, Inc.
¦ First Asian Resources & Mining Corp.
¦ Forum Cebu Coal Corp.
¦ Great Wall Mining & Power Corp.
¦ Guidance Management Corp.
¦ Ibalong Resources & Development Corp.
¦ 11 Rey'c Exploration & Mining Corp.
¦ Lebach Mining Corp.
¦ LIMA Coal Development Corp.
¦ Monte Oro Resources & Energy, Inc.
¦ MS-SK Coal Corp.
¦ Oriental Energy & Power Generation Corp.
¦ Philippine National Oil Company
¦ Rock Energy International Corp.
¦ Samaju Corp.
¦ SERI
¦ Semirara Mining Corp.
¦ SKI Energy Resources, Inc.
¦ Sultan Energy Philippines Corp.
¦ Titan Mining & Energy Corp.
¦ Visayas Multi-Minerals & Trading Corp.
Engineering, consultancy.
¦ R.M.B. Earth Science Consultants Ltd. Technical assistance
and related services
Universities, Research
¦ Philippine Council for Industiy and Energy R&D Technical assistance
Establishments
¦ Cebu Institute of Technology
Regulatory Agencies and
¦ Philippine Department of Energy Project identification
Government Groups
¦ Philippine National Oil Company and assessment support
¦ Philippine Department of Environment and Natural
Resources - Mines and Geosciences Bureau
Sources: PDOE (nd]; PMEA (nd]; TFL (2009]; USGS (2006]; Ocampo (2012]
26.1.3 Status of Coal and the Coal Mining Industry
The Philippines' largest coal producer is Semirara Mining Corp., which accounts for about 94
percent of domestic coal production (Ocampo, 2012). Additional resources are being mined in
Cebu, Zamboanga Sibugay, Albay, Surigao del Norte, and Negros provinces as shown in Table 26-4.
Currently most of the coal mined in the Philippines is from the large surface mine at Semirara;
however, the remainder is produced from small underground mines (Flores, 2014). The Integrated
Little Baguio colliery is the Philippines' largest semi-mechanized underground mine and is located
in Malangas, Zamboanga-Sibugay (PNOC-EC, 2012).
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Table 26-4. Coal Production by Area 2011
Area
Production
(million tonnes)
Percent of Total
Production
Coal Operator
Semirara Island, Antique
7,190,363
94.47
¦ Semirara Mining
Corporation
¦ PNOC-EC
Zamboanga Sibugay
168,951
2.22
¦ Filsystems
¦ Brixton Energy & Mining
Corp.
¦ Adlaon Development Corp.
¦ SERI
Cebu
85,063
1.12
¦ Ibalong Resources Dev.
Corp.
¦ 11 Rey'c Exploration &
Mining Corp.
Surigao del Sur
26,980
0.35
¦ Bislig Venture & Dev. Corp.
¦ Batan Coal Corp.
¦ Samaju Corp.
Alb ay
18,395
0.24
¦ Lima Coal Mining Corp.
¦ Ibalong Resources Dev.
Corp.
Negros
2,060
0.03
¦ Calatrava Coal Miners'
Cooperative
Small-scale Coal Mining
119,521
1.57
Source: Ocampo (2012]
The Philippines consumes all domestically-produced coal and relies on imports to meet power
generation, cement production, and industrial process demand (Ocampo, 2012). As of 2013, the
country was operating 14 coal-fired power plants with combined capacity of 5,568 MW (PDOE,
2014c) as shown in Table 26-5.
Table 26-5. Coal-fired Power Plants as of 2013
Facility Name
Capacity (MW)
Number
Location
Owner
Year
Installed
Dependable
of Units
Commissioned
Pagbilao
764.0
764.0
2
Pagbilao,
Quezon
TeaM
Pagbilao
1996
Calaca
600.0
510.0
2
Calaca,
Batangas
SEM Calaca
Power Corp.
1984
Masinloc
630.0
630.0
2
Masinloc,
Zambales
Masinloc-
Power
1998
Sual
1,294.0
1,294.0
2
Sual,
Pangasinan
TeaM Sual
Corporation
1999
Quezon Power
511.0
460.0
1
Mauban,
Quezon
Quezon
Power Phils.
2000
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Table 26-5. Coal-fired Power Plants as of 2013
Facility Name
APEC
UPPC
Mariveles Coal
Mindanao Coal
PEDC Coal
Toledo Power
Corp.
Cebu TPP
(Salcon]
CEDC Coal
Capacity (MW)
Installed Dependable
Number
of Units
50.0
30.0
651.6
232.0
164.0
88.8
106.8
246.0
42.0
24.0
495.0
210.0
164.0
60.0
106.8
246.0
Location
Mabalacat,
Pampanga
Calumpit,
Bulacan
Marveles,
Bataan
Villanueva,
Misamis
Iloilo City,
Pa nay
Toledo City,
Cebu
Owner
Asia Pacific
Energy Corp.
United Pulp
& Paper Co.,
GN Power
Mariveles
Coal Plant
STEAG State
Power Inc.
Panay Energy
Development
Corporation
Global
Business
Power Corp.
Naga, Cebu Salcon Phils.
Year
Commissioned
2006
1998
2013
2006
2011
1993
1981
Toledo City,
Cebu
Cebu Energy Testing and
Development commissioning as
Corporation of 2013
Korea Electric
Power Corp. Coal
200.0
200.0
Naga, Cebu KepCo-Salcon
2011
Total
5,568.2
4,995.8
Source: PDOE (2014c]
There are also 10 cement plants operating on coal as well as six industrial plants, including
smelting, and phosphate, alcohol, and rubber production (Ocampo, 2012).
26.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
CMM recovery projects in the Philippines.
A CMM project was planned by Semirara Mining Corp. which signed a memorandum of agreement
in late 2009 with Endesa Carbono S.L. to implement a CMM extraction, flaring and power
generation project on Semirara Island (Gatdula, 2011); however, the project was abandoned. The
proposed project would have captured methane released by the open pit mining operations
through pre-mining drainage. The captured methane and the electricity generated were expected to
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reduce greenhouse gas emissions by an average of 385,478 tonnes of carbon dioxide equivalent per
year (UNFCCC, 2011).
A 2008 report indicated that a preliminary evaluation of CMM in the Visayan and Zamboanga
Basins suggests a potential for gas drainage development during mining (Flores et al, 2008).
26.2.1 CMM Emissions from Operating Mines
Table 26-6 summarizes the Philippines' CMM emissions.
Table 26-6. Philippines' CMM Emissions (million cubic meters)
Emission Category
2000
2005
2010
2015
(projected)
Total CH4 Emitted
14.2
30.2
26.5
29.0
Source: USEPA(2012)
The Philippines has a number of gassy coal mines, as indicated by a number of methane-related
mine accidents. An explosion in the town of Imelda in Zamboanga Sibugay province caused the
death of a worker and injured four others in December 2009. In 1995, a coal mine tunnel in
Malangas was destroyed by a massive methane gas explosion, which killed more than 100 people
(Mining-Technology.com, 2009).
26.2.2 CMM Emissions from Abandoned Mines
No information relating to recovery or use of CMM from abandoned mines was found.
26.2.3 CBM from Virgin Coal Seams
The United States Geological Survey (USGS) and the Philippines Department of Energy (PDOE)
launched a collaboration to determine the methane gas content and adsorptive capacity of
Philippine coal. The study entitled "Assessment of Philippine Coal Bed Methane" identified several
coals, from lignite to semi-anthracite, in the country that possess large gas storage capacity. In
Table 26-7 below, the results of the study are summarized. Total potential minimum coal bed
methane (CBM) in-place resources in the Philippines are estimated at 16,416 million cubic meters
(m3).
Table 26-7. Philippines' Potential CBM In-Place Resources
Coal District Area
Coal Rank
Potential CBM In-Place
Resources
(million cubic meters)
Samar-Leyte
Lignite
183
Cotabato
1,037
Cagayan-Isabella
652 - 2,400
Negros
Sub-bituminous
5
Semirara
3,361
Surigao
1,120
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Table 26-7. Philippines' Potential CBM In-Place Resources
Coal District Area
Coal Rank
Potential CBM In-Place
Resources
(million cubic meters)
Bataan Island
Bituminous
119
Catanduanes
36
Cebu
2,670- 3,530
Zamboanga - Sibuguey (Malangas]
Semi-Anthracite
580- 1,033
The potential minimum CBM in-place resources (in million m3) estimated for Philippines coal districts based on ideal gas
storage capacity (100 percent gas saturation].
Source: USGS (2006]
There are currently no CBM projects in the Philippines.
26.3 Opportunities and Challenges to Greater CMM Recovery
and Use
The Philippines is a signatory to both the UNFCCC and the Kyoto Protocol (see Table 26-8). As a
Non-Annex I Party to the Kyoto Protocol, it has no national emissions targets and was eligible to
host mitigation projects under the Clean Development Mechanism (CDM). The Semirara CMM
Project was stopped during validation as a CDM project
Table 26-8. Philippines' Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 12,1992
August 2,1994
Kyoto Protocol
April 15,1998
November 20,2003
Source: UNFCCC (2014]
26.3.1 Market and Infrastructure Factors
As mentioned in section 26.1.1, the PEP projects coal demand to grow by 70 percent between 2012
and 2030. With the increase in power demand, coal mining is expected to remain a steady source
for power plants. Additionally, natural gas demand is expected to grow in the Philippines, opening
up opportunities for CMM and CBM. As of 2013, installed natural gas power generation capacity
was 3,537 MW including 675 MW of gas turbine capacity, or a 20 percent share of overall
generating capacity (PDOE, 2014c). In 2013, the Philippines produced 3.5 billion m3 of natural gas,
consuming 3.3 billion m3 for power production and 75 million m3 for industrial use, including the
Pilipinas Shell Refinery (PDOE, 2014d). During 2013, an average of 19 compressed natural gas
(CNG) buses were loaded daily.
Total natural gas demand for the year 2014 is projected to reach 3.8 billion m3, reflecting a
projected increase in consumption of 13 percent in the power generating sector, 24 percent in the
industrial sector and 74 percent in the transport sector. The transportation sector will see large
gains as additional buses are expected to be brought online in 2014, and bidding for equipment and
civil works for two additional CNG stations was completed in late 2013 (PDOE, 2014e).
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26.3.2 Regulatory Information
The Philippine Department of Energy (PDOE) is the primary regulatory entity involved with CMM
development The PDOE regulates mine safety and sets limits for methane concentration in mine
workings and ventilation air (PDOE, 1981). In 2007, atthe Association of Southeast Asian Nations
Forum on Coal, the Philippines discussed modifying the contracts and licenses for CBM
development under coal operating contracts instead of service petroleum contracts (ASEAN, 2007).
No guidelines or circulars concerning CBM development are available from the PDOE.
26.4 Profiles of Individual Mines
26.4.1 Panian Mine, Semirara Mining Corporation
Semirara Mining Corporation (Semirara) is the largest coal producer in the Philippines and is
engaged in surface mining of thermal coal from the Panian mine on Semirara Island, in Antique
province. Semirara Island covers an area of 55 square kilometers (km) and is located 350 km south
of Manila. Coal resources have been discovered at four separate sites on Semirara Island, namely
Panian, Bobog, Himalian and Unong; however, Semirara operates one mine atthe Panian site.
Operations at Unong mine ceased in 2000 after 17 years of extraction. Coal produced at the Panian
mine is sold domestically to power plants, cement plants, paper mills, textile dying plants,
canneries, food factories, a sugar mill, and a fertilizer plant. In 2007, Semirara commenced export to
China and is now selling coal to China, India, Japan, Taiwan, and Thailand. In 2010, remaining
recoverable reserves at Panian mine were estimated at 42.41 million metric tonnes (Semirara,
2014).
26.5 References
ASEAN (2007): Report of the Fifth Meeting of the ASEAN Forum on Coal (AFOC) Council, Association of
Southeast Asian Nations, July 2007.
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed April 2014. http: //www.eia.gov/cfapps /ipdbproiect/IEDIndex3.cfm
Flores (2014): Coal and Coalbed Gas: Fueling the Future, Elsevier, Romeo M. Flores, Washington DC, 2014.
Flores et al (2008): Untapped coalbed methane resources in the Philippines (abstract), Romeo Flores, R.R.
Pendon, G.D. Strieker, A.R. Rasdas, 33rd International Geological Congress, Oslo, Norway, 6-14 August
2008. http://www.cprm.gov.br/33IGC/1352972.html
Gatdula (2011): Semirara to build 1st coalbed methane power plant in Asia, Donnabelle L. Gatdula, The
Philippine Star, 3 October 2012. http://www.philstar.com/business/732919/semirara-build-lst-
coalbed-methane-power-plant-asia
Mining-Technology.com (2009): Philippine coal mine explosion kills one, injures four, Mining-
Technology.com, December 2009. http: //www.mining-technology.com/news/news71946.html
Ocampo (2012): Coal Supply Demand and Outlook in the Philippines, Ismael Campo, presented atthe 2012
APEC Clean Fossil Energy Technical and Policy Seminar, Gold Coast, Australia, 22-23 February 2012.
http://www.egcfe.ewg.apec.org/publications/proceedings/CFE/Austrailia 2012/4A-2 0campo.pdf
PDOE (nd): Energy Resources - Coal, Philippine Department of Energy, not dated.
http://www.doe.gov.ph/ER/Coal.htm
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PDOE (1981): BED Circular No. 81-11-10 "Guidelines for Coal Operations in the Philippines," Philippine
Department of Energy, November 1981. http: //www.doe.gov.ph/PECR/Coal/Laws&Issuances /Text%20-
%2 0Guidelines%2 0for%2 0RP%2 0Coal%2 OOperation.pdf
PDOE (2014a): 2012 Philippine Power Statistics, Philippine Department of Energy, 2014.
https://www.doe.gov.ph/electric-power-statistics/philippine-power-statistics
PDOE (2014b): Philippine Energy Plan 2012-2030, Philippine Department of Energy, 2014.
https://www.doe.gov.ph/policv-and-planning/philippine-energv-plan
PDOE (2014c): List of Existing Power Plants, 2014. https: //www.doe.gov.ph/power-and-electrification/list-
of-existing-power-plants
PDOE (2014d): Natural Gas Production and Consumption, Philippine Department of Energy, 20 May 2014.
https://www.doe.gov.ph/microsites/ngmd%20website/Historical Natgas Prod Cons.pdf
PDOE (2014e): Natural Gas Situationer Report Full Year 2013, Philippine Department of Energy, 2014.
https://www.doe.gov.ph/microsites/ngmd%20wehsite/NGas Situationer FY 2013 Final.pdf
PMEA (nd): PMEA Blog, Philippine Mineral Exploration Association, not dated.
PNOC-EC (2012): Coal Operating Contract No. 41 - Malangas Project Operations, Philippine National Oil
Company Exploration Corporation, 2012. http://www.pnoc-ec.com/business.php?sub=l&id=17
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
Semirara (2014): About Semirara, Semirara Mining Corporation, accessed July 2014.
http://www.semiraramining.com/AboutSemirara.php
UNFCCC (2011): Semirara Coalbed Methane Generation Project Design Document, United Nations Framework
Convention on Climate Change, 14 January 2011.
http://cdm.unfccc.int/Proiects/Validation/DB/YCCWHT4l05P2A4OSN6LGDGK9RYEBXO/view.html
UNFCCC (2014): Ratification Status - Philippines, United Nations Framework Convention on Climate Change,
accessed June 2014. http: //maindb.unfccc.int/public/country.pl?country=PH
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2006): The Republic of the Philippines Coalbed Methane Assessment: Based on Seventeen High
Pressure Methane Adsorption Isotherms, United States Geological Survey and Philippine Department of
Energy, Open File Report 2006-1063, 2006. http://pubs.usgs.gOv/of/2006/1063/pdf/OFR-2006-
1063.pdf
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27 Poland
27.1 Summary of Coal Industry
27.1.1 Role of Coal in Poland
Poland ranks ninth globally in coal production and produced 143.5 million tonnes (Mmt) in 2012,
accounting for 1.82 percent of global production (EIA, 2013). Hosting the second largest coal
reserves in the European Union, coal provides for two-thirds of Poland's energy demand and more
than 75 percent (inclusive of peat) of its primary energy production (EIA, 2013).
Table 27-1. Poland's Coal Reserves and Production
Anthracite &
Sub-bituminous
Total
Global
Indicator
Bituminous
and Lignite
(million
Rank
(million tonnes)
(million tonnes)
tonnes)
(# and %)
Estimated Proved Coal Reserves
4,178
1,287
5465
16 (0.615%]
(2011]
Annual Coal Production (2012]
79.2
64.3
143.5
9 (1.82%]
Sources: EIA (2013]
The World Energy Council estimates similar proven Polish coal reserves for anthracite and
bituminous in 2011 at 4,178 Mmt, and reserves for lignite and sub-bituminous of 1, 287 Mmt (EIA,
2011). An in-country estimate from 2002 estimates reserves of 63,000 Mmt and 14,000 Mmt, for
hard coal and lignite, respectively (Palarski, 2003).
As seen in Figure 27-1, Poland's hard coal reserves are located in three fields: the Upper and Lower
Silesian Basins, and the Lublin Basin. The Upper Silesian Basin (USB) is currently the major coal
producer, while the Lower Silesian Basin is completely abandoned, and only one mine is
operational at the Lublin Basin. Lignite basins are located in central and western Poland, with four
of them currently in production (WEC, 2014).
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Figure 27-1. Poland's Major Coal Basins
Source: Volkmer, 2008
Location of Hard Coal Basins
27.1.2 Stakeholders
Table 27-2 lists potential stakeholders in coal mine methane (CMM) development in Poland.
Table 27-2. Key Stakeholders in Poland's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
Kompania Weglowa, S.A.
Project hosts
Katowki Holding Weglowy
Jastrzebska Spolka Weglowa, S.A. Company (JSW)
Independent Mines: Budryk, Bogdanka and Jaworzno
Siltech
Regulatory Agencies
Polish Geological Institute
Project identification
and assessment
support
Natural Gas Transmission
¦ Polish Oil and Gas Company or PGNiG
Gas distribution and
& Distribution Companies
Chttp://www.penis.pl/?s.main.lansuase=ENT. OGP GAZ- stm-asTe
SYSTEM fhttp: / /en.eaz-svstem.pl/"I
Government Groups
¦ Ministry of Natural Resources
Licensing
¦ Ministry of Economy
¦ Central Mining Institute
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Table 27-2. Key Stakeholders in Poland's CMM Industry
Stakeholder Category
Stakeholder
Role
Other
U.S. Trade and Development Agency
Metanel S.A.
World Bank
U.S. Environmental Protection Agency,
www.epa.qov/coalbed /networkcontacts.html
European Investment Bank
European Union's PHARE Program
Institute for Ecology of Industrial Areas (IETU]
Strata Mechanics
LNG Silesia
Project identification
and assessment
support
27.1.3 Status of Coal and the Coal Mining Industry
Coal is one of Poland's largest industries and employers, but inefficiencies resulted in large annual
losses, spurring the government to reform the sector. In 1998, the government introduced a five-
year (1998-2002) Hard Coal Sector Reform Program, which reduced employment from 248,000 to
140,000 by the end of 2002. In February 2003, the Polish government consolidated several failing coal
firms to form Kompania Weglowa, which is now one of Europe's largest coal companies. Kompania
Weglowa includes mines from five firms: Bytomska, Rudzka, Gliwicka, Nadwislanska, and Rybnicka.
Table 27-3 illustrates Poland's declining mine statistics from 2004 to 2008. In November 2003, the
government introduced a second program to further consolidate and reform Poland's coal sector -
Program of Restructuring of the Hard Coal Mining Sector for 2003 to 2006 (World Bank, 2004).
Poland received a World Bank loan of $100 million in 2004 to support the restructuring program,
requiring a workforce reduction of 25,500 mining sector jobs from 2004 to 2006 and for voluntary
closure of inefficient mines (World Bank, 2007).
The restructuring program also planned to privatize the country's coal industry by 2006.
Privatization of Polish coal mines began with a sale of 45 percent of the Bogdanka mine to
Management Bogdanka, a private company of investors. Other privatizations followed, with
PricewaterhouseCoopers advising the Ministry of the Economy. Privatization of the coal industry
was, however, halted by the Polish government in 2006. The World-Bank-supported restructuring
program had been suspended by the Polish government in 2006 because the coal industry had become
more profitable and only two mines had been closed through the project The Polish government decided
that any further mine closures would be handled by the mine companies and not by the Mine
Restructuring Company (SRK). The loan balance was returned (World Bank, 2007).
The restructuring program has led to substantial changes in Poland's three major coal basins.
Specifically, the Lower Silesian Coal Basin was closed leaving only the Upper Silesian Basin and the
efficient Lublin Coal basin open for production and subsequent expansion. Post restructuring the
Polish coal industry has experienced "periods of profitability". However, market forces and
increasing foreign coal imports have acted to threaten its domestic coal industry. Poland's goal of
commercializing and privatizing the mining companies was completed by 2009 (Suwala, 2010).
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Table 27-3. Poland's Coal Mines, 2004 versus 2008
Company
Number of Mines,
2004*
Number of Mines,
2008**
Kompania Weglowa (KW]
23 (51 Mmt/yr]
16
Katowki Holding Weglowy (KHW]
9 (19 Mmt/yr]
6
Jastrzebska Coking Coal Company (JSW]
5 (14 Mmt/yr]
6
Independent Mines: Bogdanka, Budiyk,
and Jaworzno
3 (11 Mmt/yr]
NA
Source: *World Bank (2004], **DOC (2008]
As per Poland's Central Mining Institute of Katowice, there were 33 coal mines in operation, with
29 of them classified as gassy, 20 of them employing degasification systems and 14 of them utilizing
the drained methane as of 2008 (IEA, 2008).
27.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies three
active CMM recovery projects in Poland, in addition to four proposed projects (GMI, 2014). Poland
has extensive experience in CMM recovery and utilization as demonstrated by JSW's unique project
at Pniowek mine that implements three onsite end uses: electricity, heating and cooling. A
Cogeneration Power-Cooling System supplies power to the central air conditioning system and was
the first of its kind upon its launch (UNECE, 2009). In addition to JSW, Kompania Weglowa has
implemented a power project using CMM at the Knurow-Szcyglowice mine and is planning for a
VAM project at the Brzeszcze Mine.
27.2.1 CMM Emissions from Active Mines
In 2010, coal mining was the source of 22.6 percent of the country's overall methane emissions
(USEPA, 2012), with total emissions equaling 2,364 million cubic meters (m3). Table 27-4
summarizes Poland's CMM emissions by mining category. The data in this table may vary from the
USEPA data presented in the Executive Summary due to differences in inventory methodology and
rounding of digits.
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Table 27-4. Poland's CMM Emissions (million cubic meters)
Emission Category
2000
2005
2010
2015
(projected)*
Underground coal mines - mining
activities
690.26
600.71
446.87
Underground coal mines - post-mining
activities
49.38
45.43
35.08
Surface coal mines-mining activities
1.08
1.11
1.02
Solid Fuel Transformation
6.37
5.96
6.91
Emission from coke oven gas subsystem
4.43
3.92
6.14
Total emitted
740.73
647.25
482.97
530.39
Sources: UNFCCC (2013]; *USEPA (2012]
As of 1997, about 300 million m3 was being drained from Polish coal mines annually, with 65 to 70
percent of drainage being used at the mine sites or sold to outside consumers, and the rest vented
(Schwochow, 1997). Methane recovery, however, has declined over the years, mainly due to the
closure of numerous mines. Of an estimated 870 million m3 of methane emissions in 2006, less than
30 percent was removed through degasification (IEA, 2008). In 2008, 269 million m3 was removed
through degasification, with about 166 million m3 utilized and 103 million m3 released into the
atmosphere (Skiba, 2009). In 2011, about 268.97 million m3 was removed through degasification
systems, which comprised approximately 13 percent of methane emissions for 2011 (UNFCC,
2013). Skiba reports that 259.7 million m3, or 31 percent of total methane emissions was captured
by degasification systems in 2013, and drained gas volumes are expected to increase in 2014 Of this
total, 187.8 million m3 was used in 2013 (Skiba, 2014).
A 2005 study by Kwarcinski showed that in 2003, venting systems resulted in emissions equal to
3.8868 Gg CFU/Mg of extracted coal. Methane capture systems resulted in 0.6651 Gg CFU/Mg of
extracted coal. The post-mining processes led to 0.2873 Gg CFU/Mg of extracted coal, and
production waste contributed 0.0194 Gg CFU/Mg of extracted coal (KOBiZE, 2011).
Although the number of gassy mines has decreased in Poland by 48 percent from 1989 - 2005,
absolute gassiness has dropped by only 19 percent over the period, indicating an increasing share
of gassy coal mines in the country. This scenario represents an opportunity for CMM recovery and
utilization projects (IEA, 2008). CMM capture is forecasted to increase to 320.5 million m3 by 2015,
with an estimated utilization potential of 1068 GWh (Skiba, 2009).
Poland has an open, emerging market economy that should be conducive to CMM project
implementation, and Polish mining authorities are supportive of CMM development initiatives (IRG,
2003). Actions similar to the World Bank's industry restructuring loan should also constitute
positive factors favoring project development
GMI awarded a grant in 2008 to the Central Mining Institute of Katowice, Poland to provide
"Detailed Characteristics of the Ventilation Air Methane Emissions from Ten Gassy Underground
Coal Mines in Poland," and another in 2009 to perform a "Pre-feasibility Study for Degasification
and Methane Capture Before Mining at the Pawlowice I Coal Field.," A third grant was awarded to
the Institute for Ecology of Industrial Areas in 2008 to perform an "Abandoned Mine Feasibility
Study and Coal Mine Methane to Liquefied Natural Gas Assessment" at the Zoiy coal mine in the
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Silesian region (M2M Agreements, 2008; M2M Agreements, 2009). Most recently, U.S. EPA initiated
a pre-feasibility study to examine the use of in-mine horizontal wells to degasify seams in advance
of mining, as well as for developing horizontal GOB wells.
The Ministry of Environment has launched a project to further investigate surface directional
drilling in advance of mining as an effective degasification tool. If successful, then the volume and
quality of CMM could increase providing additional gas for utilization (Skiba, 2014).
27.2.2 CMM Emissions from Abandoned Coal Mines
No data quantifying emissions from abandoned Polish mines are currently available, though the
methane volume in abandoned coal mines in the USB was estimated in 2006 to range from 150 to
200 billion m3 (Nagy, 2006).
27.2.3 CBM from Virgin Coal Seams
Estimated in-place coal seam gas resources in Poland are summarized in Table 27-5. One estimate
of resources in actively mined and undeveloped coals in the USB yields 1,300 billion m3 of coal bed
methane (CBM) to a depth of 1,500 m. A different method used by the Polish Geological Institute
yields a more conservative estimate of 350 billion m3, of which 210 billion m3 exists in virgin coal.
Including the Lower Silesian and Lublin basins, total in-place CBM resources range from 425 to
1,450 billion m3 (Schwochow, 1997).
Table 27-5. Poland's In-Place CBM Resources
Gas Content Gas in Place
Coal Basin
m3/Mg m3/t billion m3 Tcf
Upper Silesian, first estimate*
Active mines to 1,000 m (3,280 ft]
Undeveloped coal to 1,000 m (3,280 ft]
Coal at 1,000-1,5000 m (3,280-4,920 ft]
Subtotal
Upper Silesian, second estimatef
Coal to 1,500 m (4,920 ft]
Lower Silesiant
Lublint
<22
<20
< 30
25
< 20
< 18.1
<27.2
22.7
370
340
590
1,300
350
25-50
50-100
13.1
12.0
20.8
45.9
12.4
0.9-1.8
1.8-3.5
Total
£97
£88
425-1,450
15-51
Sources: *Hoffman and Weil (1993]; tSurowka (1993]; +Grzybek (1996], as presented in Schwochow (1997]
The USB first attracted CBM developers in early 1990s. Several CBM concessions were granted from
1991 - 1997, but none of these could establish commercial production of CBM. CBM production in
Poland is contingent on the availability of highly specialized equipment, as well as expertise (Hadro,
2008).
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27.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Poland has signed and ratified the UNFCCC and Kyoto
Protocol, as indicated in Table 27-6. As an Annex 1
country, Poland is eligible to host Joint
Implementation (JI) projects that can acquire revenue
from the sale of carbon credits. In February 2008, the
first JI project in Poland was initiated to capture and
utilize CMM at the KWK Borynia Coal Mine (JI, 2008).
Subsequent to the Borynia Mine project, Kompania
Weglowa implemented a JI project in 2009 at the
Knurow-Szczyglowice Mine in cooperation with
Chugoko Electric Power of Japan to produce
electricity from CMM.
Table 27-6. Poland's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 5,1992
July 28,1994
Kyoto Protocol
July 15,1998
December 13,2002
Source: UNFCCC (2014]
27.3.1 Market and Infrastructure Factors
Polish companies have been very innovative at utilizing CMM at mine sites in a variety of ways
including heat, power, LNG, and coal drying. Poland is also working toward ventilation air methane
(VAM) utilization and recovery through the use of advanced technologies and creating market
conditions that can spur VAM project development. The Central Mining Institute of Katowice is
researching VAM emissions from 10 gassy hard coal mines in Poland and their potential end use
(Skiba, 2009) and Kompania Weglowa is exploring the use of VAM as well.
The transmission network of the Polish Oil and Gas Company (PGNiG) could also play a favorable
role for CMM. It is extensive, with 17.9 thousand km of pipes covering almost all of Poland. PGNiG
has two main gas transmission networks - one for low-methane gas and another for high-methane
gas. The distribution networks include approximately 105 thousand km of gas pipelines that cover
the urban areas of the country. PGNiG also has seven underground gas storage facilities (PGNiG,
2006). PGNiG is thus well-situated to make use of CMM projects.
27.3.2 Regulatory Information
The Geological and Mining Law of February 4,1994 regulates the ownership of natural resources,
including the right to explore for and extract them. The Energy Law requires energy enterprises to
supply and connect customers, meet demands, and initiate actions for reducing consumption. There
are 27 licenses for exploration fields reported in the USB and 68 licenses for coal mines.
Polish Licensing Authority
The Ministry of Natural Resources
Ul. Wawelska 52/54
00-922 Warszawa
Contact: Jacek Wroblewski
Phone: 48 22 251503, 48 22 250001
int. 335
Fax: 48 22 251503, 48 22 253972
Email iwroble@mos.gov.pl
Website http://www.mos.gov.pl/
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Poland is currently providing support for methane use by promoting the use of Combined Heat and
Power (CHP) systems through the "CHP Certificates" mechanism and is also providing excise tax
exemptions for electricity generation (Skiba, 2009).
27.4 Profiles of Individual Mines
Detailed profiles of gassy Polish mines are available through the GMI website at
https://www.globalmethane.org/partners/poland.aspx.
27.5 References
DOC (2008): Poland Coal Mining Industry, U.S. Commercial Service, Warsaw, Poland, 2008.
EIA (2008): Data obtained from International Energy Annual 2006, U.S. Energy Information Administration,
Washington, DC, table posted October 2008.
EIA (2013): Country Analysis Note - Poland, Energy Information Administration, last updated 30 May 2013.
http://www.eia.gov/countries/country-data. cfm?fips=PL#coal
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed
September 2014. https: //www.globalmethane.org/coal-mines/cmm/index.aspx
Hadro (2008): "A New Approach to Coalbed Methane Exploration in the Upper Silesian Coal Basin," Jerzy
Hadro, Eurenergy Resources Corporation, 2008
IEA (2008): New Trends in CMM Recovery and Utilization - Workshop Report, Szczyrk, Poland, supported by
International Energy Agency, February 2008.
https://www.iea.org/publications/freepublications/publication/methane recoverv.pdf
IRG (2003): Information obtained in performing a CMM project feasibility assessment for a confidential
commercial client, International Resources Group, 2003.
JI (2008):_CDM/JI Pipeline Analysis and Database, United Nations Environmental Programme, 1 February
2008. http://www.cdmpipeline.org/ii-proiects.htm
KOBiZE (2011): Poland's National Inventory Report; UNFCCC Communication, May 2011.
http://www.kobize.pl/materialy/Inwentaryzacie kraiowe/2014/NIR-2014-PL-en-vl.2.pdf
M2M Agreements (2008): 2008 EPA Methane to Markets Cooperative Agreement Awards, Methane to
Markets Partnership, 2008. http: //www.epa.g0v/methanetomarkets/grantsO8.htm#
M2M Agreements (2009): 2009 EPA Methane to Markets Cooperative Agreement Awards, Methane to
Markets Partnership, 2009. http: //www.epa.gov/methanetomarkets/grants09.htm
Nagy (2006): Impact of inactive hard-coal mines processes in Silesian Coal Basin on greenhouse gases
pollution, Stanilaw Nagy, Stanis Awrychlicki, and Jakub Siemek, Acta Geologica Polonica, vol. 25, no. 2, pp.
221-228, Warsaw, Poland, 2006.
Palarski (2003): The Mineral Sector and Sustainable Development: a Polish Perspective, Jan Palarski,
Technical University of Silesia in Gliwice, Poland, 2003.
PGNiG (2006): PGNiG Annual Report, Polish Oil and Gas Company, 2006.
http://en.pgnig.pl/documents/182 52/376035/Annual+Report+2006+%28full+version+of+the+report%
29.pdf/c05612df-2e98-4fdf-b636-dcb7d5e23d91
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
Skiba (2009): Methane to Markets Subcommittee Report Poland, Jacek Skiba and Rafal Wojciechowski,
January 2009. https://www.globalmethane.org/documents/events coal 20090127 suhcom poland.pdf
MethaneiSiL CMM Country Profiles 248
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Skiba (2014): Poland Coal Sector Update to the 19th Session of the Global Methane Initiative Coal
Subcommittee, Jacek Skiba, Geneva, Switzerland, 22 October 2014.
http://www.unece.org/fileadmin/DAM/energy/se/pp/coal/cmm/9cmm gmi ws/6 POLAND.pdf
Suwala (2010): Lessons Learned from the Restructuring of Poland's Coal-Mining Industry, Wojciech Suwala,
Global Subsidies Initiative of the International Sustainable Development, March 2010.
http://www.glohalsuhsidies.org/files/assets/poland casestudv ffs.pdf
UNECE (2009): Spolka Energetyczna "Jastrz^bie" S.A., 5th Session of the United Nations Economic
Commission for Europe Ad Hoc Group of Experts on Coal Mine Methane, 12-13 October 2009.
http://www.unece.org/energy/se/pp/coal/cmm/Scmm oct09/ll matysiak sei e.pdf
UNFCCC (2013): 2013 Annex I Party GHG Inventory Submissions, United Nations Framework Convention on
Climate Change, 26 November 2013.
https: / /unfccc.int/national reports /annex i ghg inventories/national inventories submissions /items /7
383.php
UNFCCC (2014): Ratification Status - Poland, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=PL
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990 - 2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
Volkmer (2008): Coal deposits of Poland, including discussion about the degree of peat consolidation during
lignite formation, TU Bergakademie Freiberg, 2008. www.geo.tu-
freiberg.de/oberseminar/os07 08/Gerald Volkmer.pdf
WEC (2014): Energy Resources - Poland, World Energy Council, website accessed September 2014.
http: / /www.worldenergy.org/data/resources /country/poland/coal /
World Bank (2004): PROJECT INFORMATION DOCUMENT (PID) - APPRAISAL STAGE, Report No.: AB883, 26
April 2004. http: //www-
wds.worldbank.org/servlet/WDSContentServer/WDSP/IB/2004/06/08/000104615 20040608110157/
Original/PIDOlOasOforOapprlnegs.doc
World Bank (2007): Implementation Completion and Results Report: Hard Coal Mine Closure Project, 14 May
2007. http://www-
wds.worldbank.org/servlet/WDSContentServer/IW3P/IB/2007/07/18//000020953 20070718104822
/Rendered/PDF/ICR0000494.pdf
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28 Republic of Korea
28.1 Summary of Coal Industry
28.1.1 The Role of Coal in Korea
The Republic of Korea (Korea) relies on imports for 97 percent of its energy needs because of its
severely limited domestic resources (EIA, 2014a). Coal supplies about 28 percent of the country's
total energy, amounting to an estimated coal consumption of 125 million tonnes (Mmt) in 2012
(EIA, 2014a). However, only about 2.1 Mmt of anthracite coal was produced domestically in 2012,
as shown in Table 28-1 (EIA, 2014b; USGS, 2013). Rising coal consumption and a negligible
production level have caused the country to rely heavily on imports over the past several years,
making Korea the fourth-largest importer of coal in the world, mainly from Australia, Indonesia,
and Russia (EIA, 2014a). Indigenous coal reserves were estimated at 126 Mmt in 2011 (EIA,
2014b).
Table 28-1. Korea's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
0
126
126
57 (0.01%]
Annual Coal Production (2012]
2.1
0
2.1
42 (0.03%]
Source: EIA (2014b]
Figure 28-1 illustrates the locations of coal basins and mines in Korea. As seen, Korea's coal is
concentrated in four of its nine provinces: North and South Chungcheong, Gangwon (location of
Samcheok, the largest coalfield in Korea), and to a small extent in South Jeolla (NationMaster, nd).
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Figure 28-1. Korea's Coal Fields and Major Coal Terminals
28.1.2 Stakeholders
Table 28-2 lists potential stakeholders in the development of Korea's coal mine methane (CMM)
industry.
Table 28-2. Key Stakeholders in the Republic of Korea's CMM Industry
Stakeholder Category
Stakeholder
Role
Engineering, Consultancy,
¦ See http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
and Related Services
Mining Companies and CBM
¦ Korea Resources Corporation
Project
Developers
¦ Korean Coal Corporation
¦ See http://www.epa.gov/coalbed/networkcontacts.html
hosts/promoters
Universities, Research
¦ Korea Institute of Energy Research
Technical assistance
Establishments
¦ Korea Electrotechnology Research Institute
¦ Korea Institute of Science and Technology
¦ Korea Institute of Geoscience and Mineral Resources
¦ Korea Electric Power Research Institute
Government Groups
¦ Ministry of Education, Science, and Technology
Licensing, Monitoring
¦ Ministry of Knowledge Economy
and Control
¦ Global Green Growth Institute
Other
¦ Korea Energy Management Corporation
¦ Korea Energy Economics Institute
Policy
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28.1.3 Status of Coal and the Coal Mining Industry
As seen in Figure 28-2, Korean coal production has declined drastically in the last 25 years, with
many coal mines closing. Coal production has declined 91 percent from its peak in the late 1980s
(EIA, 2014b). Currently, Korea produces only anthracite, importing all its bituminous requirements.
Figure 28-2. Korea's Coal Production (million tonnes)
30
25 -
20
15
10
5
0
^ ^ ^ ^ ^4?
Source: EIA (2014b]
Korea has five anthracite coal mines, three of which are operated by the state-owned Korea Coal
Corporation (KCC). The company is also examining production opportunities abroad and
developing a mine in the Uvs province of Mongolia. This represents a significant decrease from the
347 mines in operation in 1988, a result of the government's policy of rationalizing domestic coal
production. Production of coal in Korea is subsidized by the government and the cost of production
is higher than the cost of imports. Nevertheless, the government intends to stabilize supply and
demand for anthracite coal, maintaining a minimum annual production volume, given that it is the
nation's only natural energy resource (IEA, 2012).
According to the Korean government's green growth policy (see page XX) and the G-20 initiative to
abolish fossil fuel subsidies, the government has gradually reduced subsidies in the coal sector.
They will come to an end in 2020. The main subsidy was for the production of coal and its use in the
form of charcoal briquettes by low-income households. The subsidy covers subsidies for briquette
manufacturers, industrial accident insurance premiums, and school expenses for children of mine
workers.
Coal consumption in Korea increased by 55 percent between 2005 and 2012, driven primarily by
growing demand from the electric power sector, which accounts for 62 percent of the country's coal
consumption (EIA, 2014a). Although the share of liquefied natural gas (LNG) in power generation in
Korea has increased rapidly, gas is a relatively expensive energy source for power generation. This
gives coal a relative cost advantage over gas in the power generation sector. However, expected
additions to the coal-fired power plant fleet are modest in the midterm and thus much of the
growth in coal imports is expected to come from the industry sector, largely iron and steel
production, which consumed approximately 12 percent of coal in 2010 (IEA, 2012).
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28.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
projects in Korea, in operation or under development (GMI, 2014). Updates on future CMM projects
in the Republic of Korea can be found at https://www.globalmethane.org/coal-
mines/cmm/index.aspx.
28.2.1 CMM Emissions from Operating Mines
Methane emissions in Korea totaled 81.2 million cubic meters (m3) in 2000, but are expected to
decrease to 61.6 million m3 by 2015, and then anticipated to increase again to 76.3 million m3 by
2030 (see Table 28-3).
Table 28-3. Korea's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
81.2
55.3
56.7
61.6
Source: USEPA(2012)
28.2.2 CMM Emissions from Abandoned Coal Mines
The number of operating coal mines has dwindled from 70 in 1993 to only 5 in 2012 (KEEI, 2009;
KEEI, 2013). Although the potential for methane to be found in so many abandoned mines may
likely be attractive, no specific data were found.
28.2.3 CBM from Virgin Coal Seams
No data were found for virgin coal seams.
28.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Rapid industrialization, growth in income and the resultant increase in cars on the road have led to
serious environmental concerns for Korea, such as acid rain and a rise in greenhouse gas (GHG)
emissions. After the Asian financial crisis of 1997-98, Korea began aligning itself with more secure
and environmentally sound energy development. It established goals for promoting green
development via its National Vision for Environmental Policies in the 21st Century.
Korea signed the Kyoto Protocol in September 1998 (see Table 28-4). Although Korea has no formal
Kyoto commitment to cap its GHG emissions, it announced in 2009 to unilaterally cut its emissions
4 percent below 2005 levels by 2020, which is a 30 percentcutin emissions under a business as
usual scenario.
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Table 28-4. Korea's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
Kyoto Protocol
UNFCCC
June 13,1992
September 25,1998
December 14,1993
November 8,2002
Source: UNFCCC (2014]
In 2010, Korea established the National Climate Change Adaptation Master Plan (Master Plan)
based on the Framework Act on Low Carbon, Green Growth (Green Law) and setup a committee
comprised of representatives from 13 ministries to implement the Master Plan successfully.
Adaptation of Industry/Energy is one of the ten sectors outlined in the Master Plan, striving to
create new business for adaptation, minimize damages in industry, and provide energy stability
(KACCC, 2014). Korea's Ministry of Environment (MOE) has conducted a national GHG inventory in
accordance with the Green Law since 2010. More than 450 Korean companies agreed upon the
GHGs and energy reduction goal for 2012 in October 2011, and submitted the implementation plan
using the National Greenhouse Gas Reporting System in December 2011 (MOE, 2014).
Alternative energy sources are still not commercially competitive with conventional fossil fuel
energy in Korea. The Korean government plays a central role in setting prices for the energy
market. With the country's push toward sustainable development, the government is taking
significant steps to improve market penetration of renewable energy (see "Regulatory
Information"). The Ministry of Knowledge Economy (MKE) is also concerned with regulating
economic policy, particularly in the industrial and energy sectors, and is involved in encouraging
foreign investment in Korea.
Several organizations are vested in energy-related research and development (R&D) besides MKE,
such as the Ministry of Education, Science and Technology. The Korea Institute of Energy Research
and the Korea Electrotechnology Research Institute are two more major public institutes for energy
technology research and are government funded. Other government-supported research institutes
include the Korea Institute of Science and Technology (KIST) and the Korea Institute of Geoscience
and Mineral Resources (KIGAM). KIST is the leading Korean institute for research in fundamental
and applied science, which plays an essential role in developing energy-efficient industrial
technologies. KIGAM seeks to boost sustainable development through advancement of science and
technology by conducting geological surveys and disseminating research outcomes in fields such as
mineral resources, geohazards, and climate change.
The Korea Energy Economics Institute (KEEI) is Korea's main energy policy research organization.
KEEI conducts basic research on energy policy options. It provides energy information and
statistics and produces energy balances; formulates policies for the government on reforms in the
electricity and gas supply industries, energy efficiency, and demand management; produces energy
supply and consumption forecasts; and is also involved in climate change studies. The Korea Energy
Management Corporation (KEMCO) plays a key role in implementing R&D policy objectives for
energy efficiency, energy conservation, and clean energy technologies.
No data are available on CMM operations in Korea. However, projects utilizing methane from
landfills are well under way and may help in drawing parallel to CMM projects (NREL, 2006). The
28.3.1 Market and Infrastructure Factors
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MKE has partnered with the U.S. Environmental Protection Agency to form the Climate Change
Technology Program to assist with implementing methane recovery and energy-efficient
technologies in Korea. The plan involves government-supported project development and
technology implementation through private sector collaboration between Korean and international
firms. Korea has also been at the forefront of green growth initiatives, issuing The National Strategy
for Green Growth (2009-2050) and the Five-Year Plan (2009-2013) to provide a comprehensive
policy framework for green growth (OECD, 2014). In the long term, the National Strategy aims to
promote eco-friendly new growth engines, enhance peoples' quality of life, and contribute to
international efforts to fight climate change. The Five-Year Plan outlines government actions for
National Strategy implementation and provides detailed tasks for ministries and local governments.
Under the plan, the government will spend approximately 2 percent of annual GDP on green growth
programs and projects, with initial investments geared towards infrastructure systems (OECD,
2014).
28.3.2 Regulatory Information
Although Korea initiated privatization of the natural gas companies, the Korea Gas Corporation
(KOGAS) and several other state-owned enterprises in 1999, the State still retains a 27 percent
direct equity share (EIA, 2014a). KOGAS was to be split into three competitive retail gas suppliers;
however, the government decided to revise its plans.
Under Korea's constitution, the land and natural resources are protected by the state and the
government plans for the best development and utilization of its resources. The State may grant
licenses for temporary periods to private companies for tapping into the natural wealth
(Constitution, nd).
The Korea Occupational Safety and Health Agency (KOSHA), which oversees the country's
Industrial Safety and Health Act that provides occupational safety measures for both employers and
employees, focuses on preventing workplace accidents, improving working environments, and
preventing occupational diseases such as pneumoconiosis, common in workers engaged in "dust
work" (KOSHA, 2014).
A renewable portfolio standard (RPS) for Korea became effective in 2012, with an anticipated
increase in renewable power generation to 10 percent of total power generation by 2022, up from
two percent in 2012 (EIA, 2014a). The RPS replaces previous feed-in tariff subsidizes for power
generated from alternative sources. Korea's ongoing R&D tax credit program still applies to
renewable energy technologies, and import duties are reduced by 50 percent for components
and/or equipment procured for renewable energy facilities (KPMG, 2014).
CMM recovery is justifiably a key element of energy conservancy and is environmentally crucial.
Therefore, although CMM projects have yet to develop in Korea and the government is pursuing
other clean technologies (e.g., green growth), it is possible that the Korean government would
contribute by providing incentives and tax breaks to encourage CMM use and ease its entry into the
energy market.
28.4 Profiles of Individual Mines
Information on active mines in Korea is currently unavailable.
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28.5 References
Constitution (nd): South Korean Constitution - Chapter IX, The Economy, Article 120, not dated.
EIA (2014a): Country Analysis Brief - South Korea, U.S. Energy Information Administration, Washington, DC,
last updated 1 April 2014. http://www.eia.gov/countries/cah.cfm?fips=KS
EIA (2014b): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http: //www.eia.gov/cfapps/ipdhproiect/IEDIndex3.cfm
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed in July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
IEA (2002): International Energy Agency, 2002.
IEA (2012): Energy Policies of IEA Countries-. The Republic of Korea 2012 Review, International Energy Agency,
2012. http: //www.iea.org/puhlications/freepuhlications/puhlication/Korea2012 free.pdf
KACCC (2014): The National Climate Change Adaptation Plan of Korea, Korea Adaptation Center for Climate
Change, accessed July 2014. http: //www.oecd.org/env/cc/S0426677.pdf
KEEI (2009): Yearbook of Energy Statistics 2009, Korea Energy Economics Institute, December 2009.
http://www.keei.re.kr/keei/download/YES2009.pdf
KEEI (2013): Yearbook of Energy Statistics 2013, Korea Energy Economics Institute, December 2013.
http://www.keei.re.kr/keei/download/YES2013.pdf
KOSHA (2014): About KOSHA - History, Korea Occupational Safety and Health Agency, accessed November
2014. http://english.kosha.or.kr/english/content.do?menuld=1201
KPMG (2014): Taxes and Incentives for renewable energy - South Korea, KPMG International Cooperative,
accessed November 2014.
http://www.kpmg.com/Global/en/IssuesAndInsights/ArticlesPublications/taxes-and-incentives-for-
renewable-energv/Pages/south-korea.aspx
MOE (2014): Climate Change Policy Overview - Private and Public Sectors, Ministry of Environment, accessed
July 2014. http: //eng.me.go.kr/eng/weh/index.do?menuld=l 09&findDepth=l
NationMaster (nd): Online compilation of data on countries from CIA World Factbook, United Nations, World
Bank, World Health Organization, and other sources, not dated.
NREL (2006): Case Studies from the Climate Technology Partnership: Landfill Gas Projects in South Korea
and Lessons Learned, U.S. National Renewable Energy Laboratory, Colorado, December 2006.
http://www.nrel.gov/docs/ly07osti/40428.pdf
OECD (2014): Green growth in action: Korea, Organisation for Economic Co-operation and Development,
accessed November 2014. http: //www.oecd.org/korea/greengrowthinactionkorea.htm
UNFCCC (2014): Ratification Status - Republic of Korea, United Nations Framework Convention on Climate
Change, accessed July 2014. http: //maindb.unfccc.int/public/country.pl?countrv=KR
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2013): 2011 Minerals Yearbook - Republic of Korea, United States Geological Survey, May 2013.
http://minerals.usgs.gOv/minerals/puhs/country/2011/myh3-2011-ks.pdf
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29 Romania
29.1 Summary of Coal Industry
29.1.1 Role of Coal in Romania
Coal accounts for 29 percent of energy production in Romania (EIA, 2014). Romania's proven coal
reserves are estimated at about 291 million tonnes (Mmt) and the country ranks 20th worldwide in
coal production (see Table 29-1). More than 80 percent of Romanian lignite reserves can be mined
profitably in opencast mines, while the remaining 20 percent require underground mining
(Euracoal, 2014; WEC, 2000).
Table 29-1. Romania's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
10.0
281.0
291.0
43 (0.033%]
Annual Coal Production (2012]
0.04
33.99
34.03
20 (0.43%]
Source: EIA (2014]
Figure 29-1 shows the distribution of lignite and hard coalfields in Romania. The coal deposits are
grouped into four zones:
Zone I, mainly located in the Southern Carpathian Mountains, includes all the high-grade coal such
as anthracite, pit coal (higher ranking than brown coal - bituminous and sub-bituminous), and
brown coal (lignite) from the Petrosani, Anina and Tebea-Brad basins.
Zone II, located within the Pre-Carpathian creep, between the Olt and Valea Buzaului rivers,
includes the lignite deposits of Campulung Sotanga, Filipestii de Padure, and Ceptura. The coal
basins of the Eastern Carpathian are also included within this zone: Baraolt-Virghis (lignite) and
Comanesti-Bacau (brown coal). More than 90 percent of Romanian coal reserves are located within
Zone II, namely in the mining basins of the Oltenia Region.
Zone III is located in the Sub-Carpathian creep of the Getic Plateau, between the river Olt and the
Danube, including the lignite deposits of Rovinari, Motru, Jilt, Berbesti-Alunu, and Mehedinti.
Zone IV is located in the Panonian creep in the northwestern part of Transylvania and includes the
brown coal and lignite deposits of Sarmasag Voievozi, Surduc, and Borod.
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Figure 29-1. Romania's Coalfields
Source: Euracoal (2014)
29.1.2 Stakeholders
Table 29-2 lists potential stakeholders in Romania's coal mine methane [CMM] industry.
Table 29-2. Key Stakeholders in Romania's CMM Industry
Stakeholder Category
Stakeholder
Role
Governmental Mining
Companies
¦ National Company of Lignite OLTENIA, Targu-Jiu
¦ National Hard Coal Company, Petrosani
¦ National Coal Company, Ploiesti
Project hosts
Other Mining
Companies/License
Holders
¦ Asociatia Mina Borod
¦ SC Complexul Energetic Craiova SA.
Project hosts
Developers
¦ See
http://www.epa.sov/coalbed/networkcontacts.html
Project opportunity
identification and
planning
Engineering, Consultancy,
and Related Services
¦ See
http://www.epa.sov/coalbed/networkcontacts.html
Technical assistance
Regulatory Agencies and
Government Groups
Ministry of Environment and Climate Change
Ministry of Economy
Management of mineral
resources, issue and
enforce government
policy
Source: USGS (2013}
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29.1.3 Status of Coal and the Coal Mining Industry
Three national companies are active in the Romanian coal industry: National Company of Lignite
OLTENIA, Targu-Jiu; National Hard Coal Company Petrosani; and National Coal Company Ploiesti
(USGS, 2013; WEC, 2000).
The National Company of Lignite OLTENIA (NCL), Targu-Jiu has nine main fields (estimated annual
capacities): Rovinari (8.0 Mmt/yr), Balteni (6.9 Mmt/yr), Udari (0.3 Mmt/yr), Matasari (7.6
Mmt/yr), Motru (6.6 Mmt/yr), Berbe^ti (2.0 Mmt/yr), Bolboce^ti (0.6 Mmt/yr), Zegujani (0.6
Mmt/yr), and Husnicioara (2.5 Mmt/yr). NCL has lignite reserves of around 820 Mmt and produces
34 Mmt of lignite annually (USGS, 2013; NCL, 2014).
The National Hard Coal Company (CNH), Petrosani operates seven coal mines: Lonea, Petrila,
Livezeni, Vulcan, Paroseni, Uricani, and Lupeni. Three of the mines are considered uncompetitive
and are expected to close - Petrila by the end of 2015 and Paroseni and Uricani by the end of 2017
(EUROPA, 2012). CNH has an estimated capacity of approximately 3.5 Mmt per year of bituminous
coal (USGS, 2013).
National Coal Company (NCC), Ploiesti operates mainly in seven small opencast pits and one
underground mine. The pits are located in the southeast, central, and northwest basins of the
country near Campulung Baraolt City, Sarmasag Popesti Commune, Comanesti Commune, Filipestii
de Padure Commune, Sotanga Commune, and the underground mine is in Borsec City. NCC has an
estimated annual capacity of 3 Mmt of lignite (USGS, 2013).
Romania has suffered from declines in production, outdated infrastructure, and labor unrest;
however, the Romanian government is hoping for a resurgence of the coal industry and for
increased output from existing mines. The first sign of improvement came in 2000, as Romanian
coal mine output improved over the previous year's total for the first time in several years. Since
then, average production has risen but fluctuated, as shown in Figure 29-2.
Figure 29-2. Romania's Annual Coal Production
Source: EIA (2014]
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29.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies two
CMM recovery projects in Romania: an operating boiler fuel project at Lupeni Mine, an active
surface mine in the Jui Valley coal basin, and a proposed combined heat and power (CHP) project at
an unnamed abandoned mine in the Caras-Severin region (GMI, 2014). Updates on future CMM
projects in Romania can be found at https://www.globalmethane.org/coal-mines/cmm/index.aspx
29.2.1 CMM Emissions from Operating Mines
Methane emissions in Romania totaled 187.0 million cubic meters (m3) in 2000, but are expected to
increase to 199.6 million m3 by 2015, and then anticipated to further increase to 201.0 million m3
by 2030 (see Table 29-3).
Table 29-3. Romania's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
187.0
174.4
191.2
199.6
Source: USEPA (2012]
All mines in the Jiu Valley have ventilations systems (UNECE, 2006), and the total amount of
methane emissions from the valley is estimated at 49 million cubic meters per year from ventilation
systems and another 4 million per year from other degasification systems (WEC, 2008).
As previously mentioned, Romania has one operating CMM utilization project at an active mine in
the Jiu Valley Coal Basin. At the Lupeni mine, two on-site boilers are fueled by methane from the
coal mine, generating a total of 35 MW of electric capacity and avoiding 478,800 metric tons of
carbon equivalent per year (GMI, 2014). The project is summarized below in Table 29-4. Romania is
seeking partners to develop other projects.
Table 29-4. Romania's CMM Utilization Projects
Site
Project
Operator
Mine Type
First Year of
Project
Operation
Use of
Methane
Output
Lupeni Mine
CNH Petrosani
Active
2008
Boiler Fuel
2 x 15 Gcal/hour
Source: GMI (2014]
29.2.2 CMM Emissions from Abandoned Coal Mines
The potential for CMM emission recovery from abandoned coal mines is unknown.
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29.2.3 CBM from Virgin Coal Seams
Proposed efforts to explore and/or evaluate coal bed methane (CBM) production were abandoned
in 2008; to date, the potential remain unknown.
29.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Romania ratified the Kyoto Protocol as an Annex 1 country and is eligible to host Joint
Implementation projects that reduce greenhouse gas (GHG) emissions. Table 29-5 summarizes
Romania's climate change commitment
Table 29-5. Romania's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 5,1992
June 8,1994
Kyoto Protocol
January 5,1999
March 19,2001
Source: UNFCCC (2014]
Romania's National Strategy on Climate Change (NSCC) 2005-5007 outlined the country's policies in
meeting the international obligations of the Kyoto Protocol and its own national priorities (RMO,
2008a), while the National Action Plan on Climate Change outlined the implementation
methodology for the NSCC (RMO, 2008b).
In recent years, Romania's climate change position is reflected in the overall position of the
European Union of committing unilaterally to reduce, by 2020, the emissions of GHGs by 20 percent
from the level recorded in 1990 (MFA, 2014). In this context, Romania's main objectives, alongside
the EU Member States, are the adoption of a comprehensive global climate change agreement,
subject to international law and applicable to all states after 2020, as well as increasing
commitments to reduce GHG emissions in the near future, with the ultimate long-term aim to limit
the average global temperature increase below 2° C (MFA, 2014).
29.3.1 Market and Infrastructure Factors
The natural gas transmission system is run by the state-owned company TRANSGAZ. Romania had
previously increased imports of Russian gas due to depletion of domestic sources (Transgaz, 2002);
however, more recently Romania is increasingly looking elsewhere to diversify it sources of gas to
avoid supply interruptions or price pressures (Upstream, 2010). Both of these situations indicate
favorability toward developing domestic alternative gas sources like CMM/CBM.
The Romanian government ended subsidies for lignite and metals mining in 2007, closed some
unprofitable mines, and privatized profitable mines. Key remaining challenges include the
continued closure of unprofitable mines, modernization of remaining mines, and reduction in
employment/manpower (Euracoal, 2014). Another major obstacle against further CMM
development, in the case of the Jiu Valley at least, has been the lack of investment (WEC, 2008).
Additionally, the EU's position on state aid (subsidies) mandates three hard coal extraction units
from the Jiu Valley—Petrila, Uricani and Paroseni—must be closed by 2018, which will result in job
losses totaling 3,500 employees (Euracoal, 2014).
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29.3.2 Regulatory Information
Romania instituted a national energy plan for 2007 through 2020 that includes the privatization of
the energy sector. The law requires that all mining activities be based on licenses for either
administration or specific concessions. All enterprises with ongoing mining exploitation and
exploration activities must apply for licenses in areas where they are active, and as part of the
restructuring process are required to relinquish all inactive areas to be reorganized and offered up
to competitive Romanian and foreign investment. The former National Agency for Mineral
Resources (NAMR), now Ministry of Environment and Climate Change, has been appointed as the
controlling authority for coal extraction in Romania. This Ministry has the power, on behalf of the
State, to manage the mineral resources of the country and to enforce the provisions of the
exploration and utilization of mineral resources. The Ministry of Economy (formerly the Ministry of
Industry and Trade) issues and enforces government policy in the mining field and administers and
monitors public property in the field of mineral resources (WEC, 2000).
Romania entered the European Union (EU) in 2007 and has to meet energy production and other
requirements of EU law. Romania's energy policy framework regulates the production of gas, coal,
lignite, oil, and nuclear energy, as well as power plant modernization (Euracoal, 2014). Romania
also passed a Renewable Energy Law (no. 220/2008) in 2008, in part to meet the EU regulatory
requirements, promote investment, and meet the goals of the national energy plan (EBRD, 2009).
29.4 Profiles of Individual Mines
Some basic capacity numbers can be found in the 2011 Minerals Yearbook for Romania (USGS,
2013) and in a 2006 report on Jiu Valley Mine Potential (Lupu, 2006). Updates on future CMM
projects in Romania can be found at https: //www.globalmethane.org/coal-mines/cmm/index.aspx.
29.5 References
EBRD (2009): Country Profiles - Romania, European Bank for Reconstruction and Development, 2009.
EUROPA (2012): State aid: Commission approves aid for closure of three coal mines in Romania, European
Commission, 22 February 2012. http://europa.eu/rapid/press-release IP-12-157 en.htm
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http://www.eia.gOv/countries/data.cfm#undefined
Euracoal (2014): Country Profiles: Romania, European Association for Coal and Lignite, website accessed
August 2014. http://www.euracoal.be/pages/layoutlsp.php?idpage=77
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed in July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
Lupu (2006): Methane Emissions from Hard Coal Mines of Jiu Valley - Romania - Use Possibilities, Constantin
Lupu and Emil Ghicioi, INSEMEX, Romania, 31 January - 1 February 2006.
http: //www.unece.org/energy/se/pdfs/cmm/sessfebdec06/Topicll /Lupu Ghicioi INSEMEX.pdf
MFA (2014): Key Policy Areas: Global Issues - Climate Change, Romania Ministry of Foreign Affairs, accessed
July 2014. http: IIwww.mae.ro/en /node /2134
NCL (2014): National Company of Lignite, OLTENIA, website accessed August 2014.
RMO (2008a): National Strategy on Climate Change of Romania (2005-2007), Ministry of Environment and
Water Management, 2008. http: //mmediu.ro/file/SNSC en.pdf
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RMO (2008b): National Action Plan on Climate Change of Romania (2005-2007), Ministry of Environment and
Water Management, 2008. http: //mmediu.ro/file/PNASC en.pdf
Transgaz (2002): Outlining the Role of Romania in the European Gas Transit Chain: Current Status and
Prospective, Transgaz/Gas Dispatch Centre of Romania, 2002.
UNECE (2006): Committee on Sustainable Energy - Report, United Nations Economic Commission for Europe,
12 April 2006. http: //www.unece.Org/ie/se/pdfs/cmm/cmm2 /ECE.ENERGY.GE.4.2006.2 e.pdf
UNFCCC (2014): Ratification Status - Romania, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindh.unfccc.int/puhlic/country.pl?country=RO
Upstream (2010): Romania Lowers Russian Gas Price, Upstreamonline.com, 17 June 2010.
http://www.upstreamonline.com/live/article218085.ece
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USGS (2013): 2011 Minerals Yearbook - Romania, U.S. Geological Survey, July 2013.
http://minerals.usgs.gOv/minerals/puhs/country/2011/myh3-2011-ro.pdf
WEC (2000): Restructuring and Privatizing the Coal Industries in Central and Eastern Europe and the CIS,
World Energy Council, August 2000. http: //www.worldenergy.org/wp-
content/uploads/2013/01/PUB Restructuring and privatizing coal in CIES 2004 WEC.pdf
WEC (2008): Possibilities for Using CMM in Jiu Valley Coal Basin, WEC Regional Energy Forum, World Energy
Council, 15-19 June 2008.
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30 Russia
30.1 Summary of Coal Industry
30.1.1 Role of Coal in Russia
Russia's coal industry became a principal sector of the country's economy at the end of the 1930s.
By 1950, coal accounted for 59 percent of Russia's fuel balance. The discovery of huge oil and
natural gas reserves in the 1960s along with the development of nuclear power, however, led to
decreasing dependence on coal. As of 2009,14.7 percent of Russia's total primary energy supply
came from coal/peat (IEA, 2009). More than 40 percent of coal consumed in Russia is used for heat
and power generation. Natural gas is the principal competitor with coal in these end uses.
Russia is ranked sixth in global coal production with 2012 production of 354 million tonnes (Mmt)
and has coal reserves of approximately 157 billion tonnes as of 2008, which is second worldwide
only to the United States (see Table 30-1). Russia exported 136.7 Mmt of coal in 2012 (EIA, 2014a).
The Russian Ministry of Energy estimates total coal exports will reach 140 Mmt in 2015, and
further anticipated growth in exports will reach 170 Mmt by 2030 (World Coal, 2013). Figure 30-1
illustrates historical Russian coal production, consumption, and exports. Table 30-2 shows Russia's
power generation by source.
Table 30-1. Russia's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
Estimated Proved Coal Reserves
(2011]
49,088
107,922
157,010
2 (17.6%]
Annual Coal Production (2012]
276.1
77.9
353.9
6 (4.5%]
Source: EIA (2014a]
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Figure 30-1. Historical Russian Coal Production, Consumption, and Exports
400
-50
(Nrorj-Lnt£»r^ooo^OrHr^ooo^OTHrsj
o^cno^cricricnicncnoooooooooorHrHrH
tj^cno^cncncncncnooooooooooooo
HHHHHHHHNNNNN(N(N(NNNNNN
Production Consumption Exports
Source: EIA (2013)
Table 30-2. Russia's Power Generation by Source, 2011
Power Source
Billion kWhr
%
Coal
164,348
15.6
Oil
27,362
2.6
Gas
519,202
49.4
Bio
35
0.0
Nuclear
172,941
16.4
Hydro
167,608
15.9
Geothermal
522
0.0
Solar PV
0
0.0
Solar Thermal
0
0.0
Wind
5
0.0
Total
1,052,023
100
Source: IEA (2011]
Russia's coal reserves are primarily concentrated in Siberia (80 percent), followed distantly by the
Far East region (10 percent), as seen in Figure 30-2. The main coal-producing basins in Siberia are
the Kuznetskiy and Kansko-Achinskiy, along with the South Yakutsly basin in the Far East region
(IEA, 2009). Table 30-3 shows Russia's coal production by region.
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Figure 30-2. Russia's Coal Reserves
South Yakutskiy basin
4.4/4.0
Siberia
Kansk-Achinskiy basin
79.6/0 (
Irkutskiy basii
7.3/0.7 /
Kuznetskiy basin
50.9/27.7 ^
D Hard coal ~ Lignite 1.0/0.5 Tbtal/Coklng coal, Gt
Note: The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.
Source: IEA (2009)
Table 30-3. Russia's Coal Production by Region, 2012
Region
Million
Tonnes
Kuzbass
198.9
East Siberia
48.2
Kansk Achinsk
40.7
Far East
32.4
Pechora
14.2
Yakutsk
12.2
Donbass (Rostov]
5.6
Moscow
0.3
Urals fields
0.1
Others
0.1
Total
352.7
Source: Eastern Bloc Energy [2012]
30.1.2 Stakeholders
Table 30-4 highlights a partial list of key stakeholders in coal mine methane (CMM) development in
Russia.
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Table 30-4. Key Stakeholders in Russia's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
¦ Severstal-Resource
¦ Evraz Holding
¦ MDM
¦ Ural Mining and Metallurgical Company
¦ Sibirsky Delovoy Soyuz
¦ Sibuglemet
¦ Belon
¦ Mechel
¦ Siberian Coal Energy Company
Project hosts
Equipment Manufacturers
¦ Kyshtym Machine Works
Power generation
¦ Druzhkov Machine Works
equipment supplier
¦ Artemovsk Machine Works
¦ VENTPROM
¦ Yurga Machine Works
Developers and
¦ Uglemetan
Project opportunity
Engineering/ Consultancy
¦ Green Gas International
identification, planning.
¦ Additional stakeholders:
technical assistance and
¦ http://www.epa.gov/coalbed/networkcontacts.html
design work
Universities/Research
¦ Institute of Coal of SB RAS Mining Institute ofthe Ural
Technical assistance
Establishments
Branch ofthe Russian Academy of Sciences
¦ National University of Science and Technology
"MISIS"/Mining Institute
¦ Promgas
¦ VostNII
¦ Skochinsky Institute of Mining (SIM]
Natural Gas Transmission
¦ Gazprom
Distribution and pipeline
& Distribution Companies
sales
Government Groups
¦ Federal Ministry of Natural Resources
¦ Licensing
¦ Russian Federation Ministry of Energy
¦ Project approval
¦ Russian Federal Mining and Industrial Inspectorate
¦ Safety standards for
(RosTechNadzor]
mines
¦ Regional administrations
¦ Regional
environmental and
safety rules and
requirements
30.1.3 Status of Coal and the Coal Mining Industry
Between 1996 and 2001, Russia worked with the World Bank to restructure the country's coal
industry, which is now privatized. As a result of the restructuring, nearly all of domestic coal
production comes from independent producers (EIA, 2014b). The Russian Energy Strategy to 2030
released in November 2009 focuses attention on the goal to have the Russian economy become one
based more on innovation as opposed to the export of energy resources. However, the energy
strategy 2009 projects a 100 percent increase in coal exports from 2008 to 2020 (World Coal,
2013). It also projects an almost three-fold increase in domestic capacity of hard coal processing
plants by 2020, reflecting an increase in the domestic use of coal for electricity production (IEA,
2009). Table 30-5 presents production statistics for Russian coal mining.
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Table 30-5. Russia's Coal Mining Statistics (2012)
Production
Type of Mine
Number of Mines
(million tonnes)
Underground (active] mines
99.6
91
Surface (active] mines
255.1
137
Total mines
354.7
228
Source: Coal Age (2013]
30.2 Overview of CMM Emissions and Development
Potential
In 2009, 57 underground coal mines were considered either "Category 3" mines, with methane
emissions of 10 to 15 cubic meters per ton (m3/t) of coal mined, or "Super Hazardous" mines, with
methane emissions greater than 15 m3/t (IEA, 2009). Of these mines, approximately 25 deployed
degasification systems in 2009. While underground mining represents 30 percent of Russia's total
coal production, forecasts predict an increasing share of coal production from deeper underground
mines, leading to increased methane emissions. The restructuring of Russia's coal mining industry
over the 1990s resulted in the closure of 188 uneconomic mines. Many of these mines were among
the gassiest, and this thereby led to a considerable drop in Russia's methane emissions at operating
mines (IEA, 2009).
30.2.1 CMM Emissions from Operating Mines
CMM in Russia is primarily located in three coal basins: Kuzbass, Pechora, and Donetsk (also known
as Donbass, the majority of which is situated in Ukraine). According to UNFCC's National Inventory
Submissions of greenhouse gases (GHGs), CMM from underground coal mines in Russia totaled 2.02
billion m3 in 2011 (UNFCC, 2013). The Kuzbass accounts for approximately 65 percent of CMM
emissions and the Pechora Basin accounts for 19 percentof CMM emissions (Tailakov, 2012).
Methane emissions from all Russian coal mines are summarized in Table 30-6. The Kuzbass had 47
active mines in 2003 (Tailakov, 2003) and their methane emissions are quantified in Table 30-7
(Tailakov, 2012). The data in these tables may vary from the USEPA data presented in the Executive
Summary due to differences in inventory methodology and rounding of digits. Figure 30-3 shows
the historical emissions based on reporting to the UNFCCC.
Table 30-6. Russia's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
2,942.8
3,183.8
3,424.9
3,575.5
Source: USEPA (2012]
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Table 30-7. Kuzbass CMM Emissions (million cubic meters)
Emission Category
2007
2008
2009
2010
2011
Coal Mines Ventilation and Gas Suction Systems
1,520
1,530
1,550
1,550
1,600
Source: Tailakov (2012]
Figure 30-3. Estimated Historical Methane Emissions
from Russia's Underground and Surface Coal Mines
60.00
50.00
HI
{N
o
40.00
u
c
30.00
o
IE
20.00
2
10.00
0.00
OrHrNjm^LOi£>r-oo
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Siberian Coal Energy Company (SUEK), which, in 2009, developed several CMM recovery and
utilization projects at up to five coal mines and submitted the projects for registration under the
UNFCCC Joint Implementation. According to the project's Monitoring Report, the CMM reductions
equated to 98,887 MTCC^e from 2009 to 2011 (SUEK, 2011). Another mining group,
Yuzhkuzbassugol United Coal Company, a division of the EVRAZ steel and mining group, is the
eighth largest underground coal producer in Russia, producing approximately 11 million tons in
2012. Two of Yuzhkuzbassugol's eight coal mines operating in the Kuzbass—Alardinskaya and
Uskovskaya coal mines—operate within the Kemerovo Oblast about 200 km apart, and both mine
high-grade thermal and coking coal from carboniferous strata and are highly gassy.
The following summarizes select CMM-related activities completed and/or underway in Russia:
¦ CMM project potential was studied by the not-for-profit organization Uglemetan and by ICF
Consulting Ltd. Their joint involvement resulted in a United Nations Development
Program/Global Environment Facility project titled "Russian Federation - Removing
Barriers for CMM Recovery & Utilization," which started in 2003 and ended in December
2010. The project financing amounted to 8.3 million USD. The project sought to mitigate
GHG emissions by removing barriers to implementing and financing CMM recovery and
utilization projects in Russia. Its initial focus was on the Kuzbass region, with replication
potential expected in other coal-producing areas in Russia and elsewhere (Uglemetan,
2010).
¦ Plans for a CMM project at active and abandoned underground mines in Prokopyevsk,
Kuzbass were initiated in 2010 and continue to date are in development The recovered
methane is intended for use in boilers for heat generation. The potential methane reduction
is estimated to be 2.0 million m3 or 29,346 Mmt C02e (GMI, 2010).
¦ A pre-feasibility study was conducted for two of Yuzhkuzbassugol's eight coal mines
operating in the Kuzbass—Alardinskaya and Uskovskaya coal mines in 2012 and 2013. This
study is now available from GMI, both in English (
http://www.epa.gov/cmop/docs/Yuzhkuzbassugol-Mines-PFS-Tan2014-ENG.pdfl and
Russian fhttp://www.epa.gov/cmop/docs/Yuzhkuzbassugol-Mines-PFS-Tan2014-RUS.pdf).
30.2.2 CMM Emissions from Abandoned Coal Mines
There are 43 abandoned mines in the Kuzbass, 39 of which are monitored for methane
concentrations. Methane is registered at 32 mines, 14 of which have dangerous levels of methane
gas and 5 with methane concentrations that could be explosive (Uglemetan, 2005).
30.2.3 CBM from Virgin Coal Seams
Russia is estimated to have significant CBM resources - more than 80 trillion m3 in coal seams, with
the Kuzbass basin providing possibly one of the largest CBM resource development opportunities in
the world. Gazprom estimates more than 13 trillion m3 of CBM in Kuzbass (see Figure 30-4),
accessible at 1,800 - 2,000 m depth (Gazprom, 2014). Another source estimates Kuzbass CBM
resources to be 94 billion m3 in active degasification areas and 120 billion m3 in areas where
degasification is expected to be conducted in the future, for a total of 214 billion m3 (M2M
Workshop - Russia, 2005). The Pechora basin's CBM resource is estimated at 2.26 to 3.40 trillion
m3, but the area's harsh climate may limit exploitation of this resource. Overall, CBM resource is
estimated at 48 trillion m3. The breakdown for individual basins is provided in Table 30-8 (M2M
Symposium - USA, 2006). It is estimated that if appropriate technology is deployed and if an
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economic environment favorable for CBM is created, Russian CBM production could increase to up
to 2 billion m3 per year (M2M Workshop - Russia, 2005).
Table 30-8. Estimate of CBM Resources
Basin
CBM Resources
(trillion cubic meters]
Kuzbass
13.085
Pechora
1.942
Eastern Donbass
0.097
South Yakutia
0.92
Ziryank
0.099
Tunguska
20.0
Lensk
6.0
Taymir
5.5
Total Resources
47.643
Source: M2M Symposium - USA (2006)
Figure 30-4. CBM Distribution in the Kuzbass Basin in Russia
83,700 billion cubic meters of methane
are concentrated in Russia's coal basins
These are:
Zyryansky basin
\ |Ik Taimyrsky basin
Peehorsky basin
1,942 billion cubic meters _
Tungussky
basin
Eastern Donbass
Kuzbass
13,100 billion cubic meters
Source: Gazprom [2014]
The following activities are advancing CBM development in Russia:
* Between 2008 and 2009, Gazprom initiated a pilot operation at eight exploratory wells in
Taldinskoye field in the Kuzbaas basin and by 2010, the recovered CBM was being supplied
to gas filling stations. In 2011, the daily gas production from the Taldinskaya area totaled 20
thousand cubic meters, and Gazprom aims to reach 4.0 billion m3 of CBM production from
expanded operations by 2021. Two CBM-fired reciprocating-engine power plants have also
been commissioned at the Taldinskoye field, which make it possible to supply electricity to
LensKy
basin . J ^
YuzhnoYakutsky
basin
IrKutsky
basin
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the Taldinsky coal strip mine. In February 2012, the Central Commission for Hydrocarbon
Fields Development under the Federal Subsurface Use Agency approved the Development
Plan by Gazprom Promgaz for the pilot commercial development of the southeastern part of
the Taldinskoye CBM field (Gazprom, 2014).
¦ In early 2005, the Rosnauka (Federal Agency for Science and Innovation or FASI), a federal
agency in the Ministry of Science and Higher Education, began an effort to accelerate
CBM/CMM development projects to improve mine safety and reduce GHG emissions. This
activity involved improving stimulation techniques to enhance methane desorption and
drainage, improving methane production and utilization technologies, organizing a
scientific and educational center for CBM/CMM development and coordinating same with
foreign experts, and developing a CBM/CMM business plan (M2M Workshop - Beijing,
2006). FASI was disbanded as an independent agency in March 2010, but its operations
were rolled back into the Ministry (ERAWATCH, 2013). One of FASI's projects, which
started in 2007, is a joint operation with private industry (Siberian Coal Energy Company)
and implemented by the IPKON RAN research institute. The project will develop operating
procedures for CMM recovery for use in gassy mines. The procedures will conform to the
Kyoto Protocol, increase productivity of coal seams with high gas content, and use CMM to
generate electricity, heat and emission reductions for carbon trading (IEA, 2009). The
project is on-going and will be used as a model for future projects.
¦ Uglemetan works actively to promote the development of CBM recovery in Russia by
providing information and assistance to interested companies and government agencies.
The non-profit organization was formed in 2002 expressly for this purpose. Under a 2011
GMI grant, Uglemetan has embarked on a project aimed at improving the measurement of
ventilation air methane (VAM) emissions in the Kuznetsk Coal Basin (Kuzbass) that will
lead to the use of VAM as a potential clean fuel for energy production. A forthcoming pre-
feasibility study will include definition of fuel gathering and delivery equipment plus
utilization equipment, along with energy delivery systems. The focus of this work will be to
perform an economic analysis showing the internal rate of return and net present value of
the technology option applied for a real mine situation.
30.3 Opportunities and Challenges to Greater CMM Recovery
and Use
The collapse of Soviet-era industry saw Russia's GHG emissions drop nearly 40 percent from 1990
to 1998 (Yale, 2011). Russia ratified the Kyoto Protocol in 2004, and accepted a GHG emission
reduction target of 15 - 25 percent by 2020, with 1990 as its baseline emissions (UNFCCC, 2010).
Russia is also a participant in Joint Implementation (JI) projects under Kyoto, the first of which— an
energy-efficient power plant near Moscow—was approved in 2010.
Table 30-9. Russia's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
Kyoto Protocol
June 13,1992
March 11,1999
December 28,1994
November 18,2004
Source: UNFCCC (2014]
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Russia saw a major shift in its climate policy in 2009, when the government released its "Climate
Doctrine" recognizing the anthropogenic nature of climate change and announcing long-term
emission reduction targets at least 50 percent below 1990 levels by 2050 (Yale, 2011). A 2009
government report was also the first to acknowledge the economic benefits from climate change
mitigation, (e.g., avoided floods, wildfires, permafrost melt) outweigh potential climate change-
induced gains (e.g., Arctic Shelf access, increased agricultural productivity). In 2011, then Prime
Minister Putin adopted the "Comprehensive Implementation Plan of the Climate Doctrine by 2020,"
which included adaptation and mitigation measures, as well as efforts on education and long-term
GHG scenarios. Though the Russian government continues to voice support for climate change
mitigation, many of these promises have yet to be translated into effective domestic laws and
policies.
30.3.1 Market and Infrastructure Factors
Table 30-10 lists total consumption by potential CMM markets in Kuzbass. According to a 2009
report, CMM recovery and utilization is a huge economic opportunity in Russia and estimates 130
million USD in revenue if all of its 1.9 billion m3 CMM were to be recovered and used (based on
2008 regulated wholesale natural gas prices in Russia) (IEA, 2009). However, safety concerns
would remain the principal driver for CMM projects.
Table 30-10. Total Consumption by Potential CMM Markets
Market
Electrical Power
(million kilowatt hours]
Thermal Power
Natural Gas
All sectors*
21,343
31,113
3,010
Industry
18,387
23,940
2,971
Fuel industiy
4,385
5,570
N/A
Source: *Tailakov (2004]
Russia has many barriers to expanded CMM/CBM development First, CMM and CBM must compete
with large, in-country proven gas resources with low-cost production capacity. Second, state
regulations keep the large gas supply at a low sale price, making it difficult for a CMM project to
achieve financial viability. Further, power generation projects are not usually financially viable due
to historically low power prices. Moreover, technological challenges continue from the extraction of
CBM economically from saturated, low-permeability coal seams.
However, there are many positive aspects that favor CMM development in Russia. Mining and
geological conditions are similar to those in Australia, Canada, and the United States. Further,
expected CBM production rates are promising and natural gas infrastructure and markets exist
within 20 to 100 km of high-priority CBM/CMM production areas (M2M Workshop - Russia, 2005).
Also, domestic power prices have doubled over the past 10 years and now appear to be in line with
global power prices. The power price in 2013 was expected to be $89/MWhr with inflation or
$62/MWhr without inflation (i.e., prices are trending upward). Russia is also working toward
establishing a favorable legislative climate for CMM development (see below).
30.3.2 Regulatory Information
The institutional oversight of CMM recovery and use in Russia is managed at the federal and
regional levels. However, no one institution at either the federal or regional level is directly charged
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with addressing the issue of CMM utilization. This lack of coordination or management within
government is a key challenge to the enhanced recovery and use of CMM in Russia. Regional
authorities (part of regional administrations) monitor activities of coal companies and issue
licenses for subsoil use (IEA, 2009).
CBM, like any other mineral resource in Russia, is owned by the state. A license is required for
methane extraction. There are three types of licenses: exploration license, production license, and
combined license. The license is applied for at the Territorial Authority representing the Federal
Ministry of Natural Resources, which publishes a tender announcement The tender is held with a
minimum starting price determined by the Federal Agency and it typically takes about a year to
obtain a license. As for CMM, licensing for ownership and use currently lacks clarity, which hinders
investments from third parties looking to utilize the recovered gas. Licensing processes for CMM
activities are also unclear. While an additional license is not required for CMM recovered from and
used within the mine, new mineral extraction licenses are needed if the recovered CMM is sold to
another party or used for heat and power generation which is sold to another party (IEA, 2009).
Russia offers significant opportunity for foreign investment in CMM projects because of its large
CMM resources and a significant market for clean energy. Although rules and regulations on foreign
investment in Russia are complex, the investment climate is improving (Tailakov, 2005). CMM
projects are expected to be pursued through Production Sharing Agreements (PSAs), which provide
exemptions from all federal taxes with the exception of certain payments for subsoil use, a modified
profits tax, VAT and excise on domestic purchases, and unified social tax during the period of PSA
validity (Uglemetan, 2004). Methane extraction from virgin seams and sale is taxed at 7 percent and
is subject to a single license fee. There are no royalties if methane is used for the mine's onsite
needs. Uglemetan, as an organization devoted to the promotion of CMM and CBM development
projects, provides investors with the latest information on the current investment climate in Russia.
Russian mines are subject to safety regulations but lack the resources to ensure their enforcement.
A "Guide for Safe Operation of CMM Energy Units" has been prepared by the local mine safety
institute in Kuzbass to provide guidelines to coal mines for the safe installation of CMM recovery
and utilization systems. According to the regulations, drained gas must have a minimum methane
concentration of 30 percent to ensure that it is not within the explosive range. In addition, the
regulations cover various aspects of flame safety (e.g., using flame arresters).
Russia's recent regulatory and energy market developments are poised to stimulate CMM
utilization on a larger scale. Initiatives such as a government decision on gradual price increases for
natural gas for industrial and residential users, liberalization of the electricity market, and
renewable energy targets inclusive of CMM, will facilitate the creation of a market where CMM
could become competitive with other energy sources. The Decree on Main State Policy Areas to
Increase the Energy Supply from Renewable Power Generation by 2020, passed in January 2009,
has specifically incentivized CMM recovery and use by setting targets for increased share of
renewable energy—inclusive of CMM—in the electric power supply. More supporting regulations
and clarity are needed, though, to further leverage this legislation for CMM development (IEA,
2009).
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30.4 Profiles of Individual Mines
Alardinskaya Mine, Kuzbass
Total no. of coal seams: 38, two of which are mined
Thickness of mined seams: Average - 7.6 m; Range 5.3 - 10.0 m
Overburden: Thickness - 700 m; No. of seams - #6 and #3a
Coal reserves: 160.9 million tonnes
Coal quality and rank: Ash (%]: 16 -19
Sulfur (%]: 0.04 - 0.40
Volatile Matter (%]: NA
Rank: high volatile bituminous
Heating Value (kcal/kg]: 8,600
Moisture (%]: NA
Yubileynaya Mine, Kuzbass
Total no. of coal seams: Six, one of which is currently mined
Thickness of mined seams: Average - 2.67 m; Range 1.85 - 3.55 m
Overburden: Thickness - 300 m; No. of seams - #50
Coal reserves: NA million tonnes
Coal quality and rank: Ash (%]: 6.9 Sulfur (%]: 0.54
Source: USEPA (2013]
Although mining and methane emissions and recovery data is outdated, geologic profiles on more
coal mines are available in "Reducing Methane Emissions from Coal Mines in Russia: A Handbook
for Expanding Coalbed Methane Recovery and Use in the Kuznetsk Coal Basin" at
http://www.epa.gov/cmop/docs/int005.pdf (USEPA. 1996).
Coal Age (2013): Russian Coal Producers Invest in Operations, Coal Age, 22 March 2013.
http://www.coalage.com/features/2595-russian-coal-producers-invest-in-
operations.html#.VLhaAP10zIU
EIA (2013): Russia Country Analysis Brief, U.S. Energy information Administration, Washington, DC,
November 2013. http: //www.eia.gov/countries/cab.cfm?fips=RS
EIA (2014a): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed May 2014. http: //www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm?tid=l&pid=l&aid=2#
EIA (2014b): Independent Statistics and Analysis, Russia, U.S. Energy Information Administration,
Washington, DC, last updated 26 November 2013, revised 12 March 2014.
http://www.eia.gov/countries/cab.cfm?fips=rs
ERAWATCH (2013): National Profile - Russian Federation, ERAWATCH, 2013.
http: //erawatch.irc.ec.europa.eu/erawatch/opencms/information/country pages/ru/country
IEA (2009): Coal Mine Methane in Russia: Capturing the safety and environmental benefits, International
Energy Agency, 2009. http: //www.iea.org/publications/freepublications/publication/cmm russia.pdf
Heating Value (kcal/kg]: 8,223
Moisture (%]: 5.5
Volatile Matter (%]: 37.1
Rank: high volatile bituminous
30.5 References
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IEA (2011): Russian Federation: Electricity and Heat in 2011, International Energy Agency, 2011.
http://www.iea.org/statistics/statisticssearch/report/?&country=RUSSIA&year=2011&product=Electric
ityandHeat
Gazprom (2014): Prospects for CBM production in Russia, Gazprom, accessed May 2014.
http://www.gazprom.com/about/production/extraction/metan/
GMI (2010): Project Tracking Database for Coal and Oil and Gas Sectors, Global Methane Initiative accessed
May 2014. https: //www.globalmethane.Org/activities/indexact2.aspx#
M2M Symposium - USA (2006): Methane Recovery and Utilization from Coal Seams in Russia - The Present
State of Affairs, Coal Mines Subcommittee Meeting and the International Coal Bed Methane (CBM)
Symposium, Tuscaloosa, Alabama, USA2006.
http://www.globalmethane.org/documents/events coal 20060525 russia.pdf
M2M Workshop - Beijing (2006): Report on Participation by Developing/Transitional Countries, Regional
Workshop Beijing, PRC, Methane To Markets Partnership, January 2006.
http://glohalmethane.org/documents/events coal 20060525 heiiing.pdf
M2M Workshop - Russia (2005): Current state and prospective of CMM/CBM production and utilization in
Russia, Nikolay M. Storonskiy, Ph.D., Deputy Director of PROMGAZ, Methane-to-Markets Partnership
Technical Workshop, Beijing, China, 2 December 2005.
RRR (2001): Data obtained during a visit to the Pechora Basin, Raven Ridge Resources, 11-13 September
2001.
SUEK (2011): Monitoring Report of the Project: Utilization of Degasification Methane at Coal Mines of JSC,
SUEK- Kuzbass, May 2011.
Tailakov (2003): Coal Mine Methane Emissions Reduction Projects in Kuzbass: Selection of Methane
Utilization Options, Economical Efficiency Assessments and Finance Sources, Oleg Tailakov, et al., Third
International Methane & Nitrous Oxide Mitigation Conference, Beijing, China, 17-21 November 2003.
http://www.coalinfo.net.cn/coalbed/meeting/2203/papers/coal-mining/CM053.pdf
Tailakov (2004): Opportunities and Barriers for CMM Development: A Perspective from Developing Countries
and Transition Economies (Part II), Oleg Tailakov, International Coal & Methane Research Center, 200.
https://www.glohalmethane.org/documents/events coal 20041115 tailakov.pdf
Tailakov (2005): Information provided by Oleg Tailakov, International Coal & Methane Research Center -
Uglemetan, 2005.
Tailakov (2012): Market for CMM and VAM in Russian Coal Mines, presentation delivered by Oleg Tailakov at
U.S. Coal Mine Methane Conference, Las Vegas, Nevada, USA, 2012.
http://www.epa.gov/cmop/docs/cmm conference sep!2/09 Oleg.pdf
Uglemetan (2004): White Paper - Russian Coal Mine Methane Foreign Investment Issues part 1, International
Coal & Methane Research Center - Uglemetan, 2004.
Uglemetan (2005): Report by Kuzbass Monitoring Center for Industrial and Ecological Safety (1 qtr 2005),
information compiled by Oleg Tailakov of NPO International Coal & Methane Research Center -
Uglemetan, 2005.
Uglemetan (2010): Russia - Removing Barriers to Coal Mine Methane Recovery and Utilization, International
Coal & Methane Research Center - Uglemetan, 2010. http: //www.uglemetan.ru/undp.htm
UNFCCC (2010): Quantified economy-wide emissions target, United Nations Framework Convention on
Climate Change, 2010. http://unfccc.int/meetings/copenhagen dec 2009/items/5264.php
UNFCCC (2014): Ratification Status - Russia, United Nations Framework Convention on Climate Change,
website accessed September 2014. http://maindb.unfccc.int/public/country.pl?countrv=RU
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USEPA (1996): Reducing Methane Emissions from Coal Mines in Russia: A Handbook for Expanding Coalbed
Methane Recovery and Use in the Kuznetsk Coal Basin, U.S. Environmental Protection Agency, Coalbed
Methane Outreach Program, September 1996. http: //www.epa.gov/cmop/docs/int005.pdf
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
USEPA (2013): Pre-feasibility Study for Coal Mine Methane Drainage and Utilization at the Alardinskaya and
Yubileynaya Coal Mines in Kuzbass Coal Basin, U.S. Environmental Protection Agency, Coalbed Methane
Outreach Program, November 2013. http://www.epa.gov/cmop/docs/Yuzhkuzhassugol-Mines-PFS-
lan2014-ENG.pdf [in English) or http://www.epa.gov/cmop/docs/Yuzhkuzbassugol-Mines-PFS-lan2014-
RUS.pdf [in Russian)
World Coal (2013): "The mining landscape (Part One)," published 17 October 2013.
http://www.worldcoal.com/news/coal/articles/The mining landscape Part One 140.aspx#.U4czR3ldX
he
Yale (2011). Yale Center for Environmental Law & Policy Webinar Series - "Climate Change Solutions:
Frontline Perspectives from Around the Globe," Climate Policy & Emissions Data Sheet: Russia, aired 17
November 2011. http://envirocenter.yale.edu/uploads/pdf/Russia Climate Policy Data Sheetpdf
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31 South Africa
31.1 Summary of Coal Industry
31.1.1 Role of Coal in South Africa
South Africa is the world's seventh largest coal producer and dominates the African coal industry,
producing 259 million tonnes (Mmt) of coal in 2012 (EIA, 2013). It is the seventh largest coal
exporter in the world (EIA, 2013), and responsible for about 97 percent of all coal production in
Africa (EIA, 2013). South Africa's coal resources are estimated at 115 billion tonnes, based on a
survey conducted in 1987 (DME, 2010a). As seen in Table 31-1, its reserves are estimated at about
30.1 billion tonnes which consist almost entirely of hard coals (i.e., anthracite and bituminous)
(EIA, 2013).
Table 31-1. South Africa's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
30,156
0
30,156
10 (3.39%]
(2011]
Annual Coal Production (2012]
259
0
259
7 (3.29%]
Source: EIA (2013]
Coal is the primary fuel produced and consumed in South Africa, accounting for 69.4 percent of
total primary energy supply in 2011 (IEA, 2013). Three quarters of its production is consumed
internally and one quarter is exported to the European Union and East Asia (EIA, 2014). Internal
consumption is primarily for electric power generation (about 53 percent of locally sold coal in
2013). The second most important use is conversion to synthetic liquid petrol and diesel fuels (33
percent). The metallurgical industries consumed 12 percent of South Africa's domestic coal
consumption and 2 percent was used for domestic heating and cooking coal (Figure 31-1) (ESK,
2014).
Figure 31-2 illustrates the distribution of coal deposits in the country. Seventy percent of South
Africa's recoverable coal reserves lie in the Highveld, Waterberg and Witbank fields. The great bulk
of the coal reserves are concentrated in 19 Karoo (Permian) coalfields in the Mpumalanga region of
the country and underlay an area of about 115,000 square miles (EIA, 2007).
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Figure 31-1. South Africa's Domestic Coal Consumption by Sector
Metallurgical
Industries
(Arcelor-Mittal)-
12%
Domestic
Heating and
Cooking
2%
Source: ESK(2014)
Figure 31-2. South Africa's Coal Basins
ZIMBABWE
BOTSWANA
Coalfields
Limpopo
Waterberg
Western Soutpansberg
Central Soutpansberg
Eastern Soutpansberg
Springbok Flats
Witbank
Kangwane
Free State
Vereeniging-Sasolburg
South Rand
Highveld
Eastern Mpumalanga
Kliprivier
Utrecht
Vryheid
Nongoma
Somkele
Molteno-lndwe
Waterberg Basin
MPUMALANGA
Springbok Flats Basin
Pretoria ~
•Belfast
Witbank •
Springs •
• Ermelo
Vereeniging O
SWAZILAND
Main Karoo Basin
Newcastle
Welkom
Vryheid
Richards Bay
LESOTHO
KWAZULU-NATAL
Durban •
CAPE
PROVINCE
INDIAN OCEAN
Source: Walker (2000)
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South Africa's production of bituminous coal increased by 6.54 Mmt (2.5 percent) and exports
increased by 5.5 Mmt (8.0 percent) from 2011 to 2012. In 2012, South African coal was mainly
exported to India (30 percent) and, in order of decreasing percentage, was exported to Europe (19
percent), China (17 percent), Other Asia and Oceania (14 percent), Middle East (10 percent), Africa
(7 percent), South America and Caribbean (2 percent), and North America (1 percent) (EIA, 2014).
Revenue from export sales increased from 2007 to 2012 by 46.8 percent and total revenue from the
sale of coal increased by 45.9 percent (DMR, 2013).
In 2012, 74 percent of the saleable coal production was supplied by mines controlled by the five
largest mining groups, including Anglo Coal, BHP Billiton, Exxaro, Sasol and Xstrata as shown in
Figure 31-3 (CM, 2013).
Figure 31-3. 2012 Saleable Coal Production by Mining Company
Source: CM (2013]
31.1.2 Stakeholders
The coal mine methane (CMM) industry has significant potential to develop as deeper, gassier
seams are targeted for mining. Table 31-2 lists potential stakeholders in CMM development in
South Africa.
Table 31-2. Key Stakeholders in South Africa's CMM Industry
Stakeholder Category Stakeholder Role
Mining companies ¦ BHP Billiton Project host
¦ Anglo Coal
¦ Continental Coal
¦ SASOL
¦ Exxaro Coal
Government Groups ¦ Department of Minerals and Energy Licensing
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Table 31-2. Key Stakeholders in South Africa's CMM Industry
Stakeholder Category
Stakeholder
Role
Developers and
Consultancy
Organizations
Universities, Research
Establishments
See http: //www.epa.gov/coalbed/networkcontacts.html
Chamber of Mines of South Africa
South African Mining Development Association
See Table 31-6
Project opportunity
identification,
planning and technical
assistance
Source: DME (2010a, 2010b]
31.1.3 Status of Coal and the Coal Mining Industry
There are about 90 operating coal mines as per recent statistics for coal mining in South Africa (see
Table 31-3). Forty operations are surface mines, 18 combine surface and underground mining
operations, and 35 are solely underground mining operations (DME, 2009). About 51 percent of
South Africa's coal production is from underground mines and about 49 percent is from surface
mines (GCIS, 2013).
Table 31-3. South Africa's Recent Production and Mine Statistics
Production
Type of mine
Number of mines
(million tonnes)
Underground NA 35 (2008]
Opencast / Surface NA 40 (2008]
Combined Opencast and NA 18(2008]
Underground
Total production 239.3 (2003) 93 (2008)
Source: DME (2009]
The coal mining industry is operated by private companies. Increasingly these companies are
consolidating and multinational coal mining companies are joining large domestic companies.
Forty-two companies currently operate coal mines in South Africa (DME, 2009), although five
companies—namely Anglo Coal, BHP Billiton, Exxaro (Kumba Resources and Eyesiswe), SASOL
Mining and Xstrata Coal—are responsible for about 74 percent of the country's saleable coal
production (CM, 2013). A majority of production (70 percent) is concentrated in 11 mines (GCIS,
2013).
Asset sales have been conducted to achieve government-set targets for black ownership under
South Africa's black economic empowerment program (BEE). For example, South Africa's
procurement policies for ESKOM, the parastatal electric utility, grant preferences to companies
owned by previously disadvantaged communities. In November 2000, Anglo Coal and Ingwe sold
assets for $222 million to the black empowerment group Eyesizwe Coal, creating what was at the
time, South Africa's fourth largest coal mining company. Subsequent deals included the splitting of
Kumba resources and the formation of Exxaro Resources, which contains assets from both Kumba
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and Eyesizwe (DME, 2008b). Exxaro is now the largest black mining firm and the fourth largest coal
producer in South Africa (DME, 2006).
Future new coal developments are expected to be located mainly in the northern provinces of
Limpopo and Mpumalanga. Anglo and Sasol began operation of the Kriel South coalfield,
Mpumalanga province in 2005 which produces about 5.0 Mmt/year (Anglo, 2005). Coal of Africa
(COA, 2009) is progressing with plans for two mines in the Limpopo province, which—at full
capacity—will produce a total of 10 Mmt/year (combined investment $755 million). ESKOM
estimates that 40 new mines will be necessary over the next decade to produce enough coal to fuel
future electricity demand (SAinfo, 2009).
Two new coal power stations with capacities of 4,800 MW each are under construction. The Medupi
power station is located near Lephalale in Limpopo and the Kusile power station in Mpumalanga.
The percentage of operating mines considered "gassy" is very low. It is estimated that in the
shallower fields, methane loss could have approached 80 percent of initial gas content in the
coalification process (UNFCCC, 2000). However, newer underground mines that may be developed
in deeper zones are likely to be gassier.
31.2 Overview of CMM Emissions and Development
Potential
In the mid-1990s, South Africa was ranked as one of the world's top five CMM emitters attributable
to its high coal production and estimates placed the gas content of South Africa's coals on a par with
Australia's. Since then, it has been shown that these original estimates were overstated. In 2010, its
rank in worldwide CMM emissions dropped to ninth with estimated emissions of approximately 8.2
million tonnes of carbon dioxide equivalent (MmtCChe) (EPA, 2012).
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies one
CMM recovery project in South Africa (GMI, 2014). The recovery project is a flaring project at Anglo
American Thermal Coal's New Denmark colliery near Standerton. The operation involves the
incorporation of two enclosed Swiss-designed mobile flares into the mine's methane drainage
system. A small diesel blower delivers the methane to four flaring nozzles where the gas is mixed
with air to a concentration that enables it to be safely burnt. The process can be monitored
remotely via the flare's solar-powered communication system. The project reportedly cost $1.2
million and the project developers are pursuing carbon credits under the Clean Development
Mechanism (Creamer, 2010a).
31.2.1 CMM Emissions from Operating Mines
A national greenhouse gas (GHG) inventory for South Africa was initially prepared for the years
1990-1994 for South Africa's First National Communication Report to the UNFCCC, published in
2000. Work is currently underway by the Climate Change Division of the Department of
Environmental Affairs and Tourism (DEAT) to design a process and approach for preparation of an
updated inventory (DEAT, 2010).
In the energy sector, fugitive emissions contributed 323 gigagrams (Gg) or 475 million cubic meters
(Mem) of methane in 1990 and 327 Gg (481 Mem) in 1994, which represents about 16 percent of
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the total methane emissions. In 1990, methane emissions from coal mining contributed almost 100
percent of the fugitive emissions and 97 percent in 1994 when emissions from natural gas
processing were included in the total. Of the coal mining fugitive emissions, 88 percent were from
underground mines (UNFCCC, 2000). Methane emissions for South Africa are summarized in Table
31-4.
Table 31-4. South Africa's CMM Emissions (million cubic meters)
2015
Emission Category
2000
2005
2010
(projected)
Total CH4 emitted 518 562 551 583
Source: USEPA (2012]
A detailed industry-funded study, Coal Tech 2020, was conducted in 2004, to more accurately assess
South Africa's CMM emissions. This study, conducted by the Council for Scientific and Industrial
Research (CSIR), measured ventilation air methane concentrations from most major mines (USEPA,
2004a). The final report is only available to CoalTech members, but a summary of its principal
results by study participants Alan Cooke and Philip Lloyd provides key insights as to South Africa's
likely CMM emissions levels. An excerpt from their findings is provided below in Figure 31-4.
Figure 31-4. Coal Tech 2020 Summary Results
During the course of this work most of the production shafts on underground mines have been sampled
repeatedly. In total there were 243 measurements of methane in the return air from 27 different shafts. As we
have seen, a wide scatter was observed, but taken as a whole the results give us some measure of the
quantities involved. For each shaft the average methane concentration was multiplied by the known
ventilation rate, which gave a contribution to the total methane emission of 40.8 Gg CH4/a (with an error of
±30.2 Gg).
Seam gas contents had been determined for about 72% of the coal production. Assuming 50% was lost
underground, and contributed to the methane in the return air, and that the mines for which data were
missing were represented by the mines for which there was data, then the total lost after leaving
underground mines was about 28.6 Gg CH4/a (with an error of about 24 Gg).
Thus the best present estimate of the release of methane from South African coalmines is:
¦ 40.8 Gg CH4/a in ventilation air from underground mines;
¦ 28.6 Gg CH4/a from coal after it has left the mine; and
¦ <3 Gg CH4/a from surface mining operations,
or approximately 72 Gg/a.
However, there are very large errors associated with these estimates. The source of these errors is largely the
physical processes responsible for the release of much of the methane from South African coalmines,
particularly the sporadic release of free methane. This causes huge fluctuations in the measurable
concentrations of methane in the return air. To improve the estimates will require effectively continuous
measurements over several weeks on each shaft. Further errors arise from the considerable variation in the
seam gas content of the coal, and it will require repeated measurements of the residual gas in coal coming
from underground in each mine before these errors can be reduced significantly.
Source: Excerpted from Lloyd and Cook (2004]
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The coal seams of the main Karoo coalfields being relatively shallow are generally not regarded as
being very gassy. Accordingly little attention has been paid to CMM recovery and end-use. There
are, however, several individual examples of gassy mines in South Africa. The most noted example
is the Majuba Colliery, which experienced higher than expected levels of methane in the mine
workings. Gas desorption tests showed that the coal contains up to 300 cubic feet per ton. In the
early 1990s, several in-mine horizontal wells were drilled to degasify the coal in advance of mining.
The mine operators were contemplating various CMM drainage and end-use scenarios, but the
mine was eventually closed due to other reasons (USEPA, 2004b).
Some South African mines have been known to drain methane prior to mining through surface
holes and the feasibility of recovering this methane for use in local heating has been widely
investigated (UNFCCC, 2000).
31.2.2 CMM Emissions from Abandoned Mines
South Africa has a number of abandoned coal mines; the number of operating mines having
declined by about one half between 1986 and 2004 (Limpitlaw and Aken, 2005). No data
quantifying emissions from abandoned mines in South Africa were found. However, the percentage
of gassy mines is thought to be low as most of the gassy areas of South Africa's coal resources have
not yet been developed. It does not appear that any company is currently extracting methane
resources from abandoned mines. Key barriers are legal and regulatory constraints; many
companies are concerned that once they have received a mine closure certificate, further work in
and around the mine could expose them to legal liabilities.
31.2.3 CBM from Virgin Coal Seams
The country's coal bed methane (CBM) resource is estimated to be 0.14 to 0.28 trillion m3.
Currently, there is no commercial CBM production reported for South Africa; however, there is
significant discussion about possible future projects, and several pilot wells have been installed and
are undergoing testing. Moreover, adoption of CBM/CMM technologies could become increasingly
likely as additional mines are expected to open in gassy coal fields.
The most promising areas for CBM are where the deeper, thicker, and gassier coal resources are
found. The Waterberg Basin in the northwest Mpumalanga region of the country and the southwest
portion of the Highveld coalfield near Paardekop-Amersfoort are deeper (> 1,000 feet) and gassier
(4-10 m3/tonne at 1000-1200 ft) and appear to have the best potential for CBM development (ARI,
1992).
Anglo Coal has been conducting a CBM exploration program in the Waterberg Basin for the past 15
years. As part of this program, a series of core wells were drilled and tested and a five-well pilot
production project was installed. Barriers to project progress include its remote location, delays in
rights conversions, lack of prior experience among government authorities, and lack of incentives
(DME, 2006; Merwe, 2007). Other CBM licenses are held by Badimo, NT Energy Africa,
Molopo/Highland Energy, and numerous smaller companies, but little work has been done to date.
While there is only one active CMM recovery and end-use activity in South Africa, there are several
reports, from the gold mining sector, of companies utilizing methane coming from gold mine shafts.
For example, at the Harmony Gold Mine in the Free State province, the kitchen stoves and bath
houses were fueled by captured mine methane for over 20 years (USEPA, 2004b). The Beatrix Gold
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Mine, also in the Free State province, has applied for a methane capture project under the Clean
Development Mechanism of the Kyoto Protocol (Le Roux, 2007). Methane emanates from faults and
fissures intersected during normal mining operations and a pipeline drainage system is currently
being installed to capture the methane at source underground and transport it to the surface where
the gas will be flared (Creamer, 2010b). The mine estimates that for an initial outlay of $5.5 million,
$27 million in carbon credits will be earned over 7 years through flaring alone, with resultant
emission reductions estimated to be 2.6 MmtCChe. Plans are also in place to begin construction of a
methane-fueled, 5-MW power plant in 2011.
31.3 Opportunities and Challenges to Greater CMM Recovery
and Use
As reflected in Table 31-5, South Africa is a signatoiy to both the UNFCCC and the Kyoto Protocol.
As a non-Annex 1 country, South Africa is eligible to host Clean Development Mechanism projects
that reduce GHG emissions. Carbon credits could be available if South Africa reduces total emissions
below 1990 levels (USEPA, 1998).
Table 31-5. South Africa's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 15,1993
August 8,1997
Kyoto Protocol
—
July 31,2002 (Accession]
Source: UNFCCC (2014]
31.3.1 Market and Infrastructure Factors
Significant R&D organizations exist in South Africa to assist in the assessment of CMM emissions,
recovery potential, and technology. Coaltech 2020 is an industry-led consortium of coal mine
research and technology organizations (see Table 31-6).
Table 31-6. Coaltech 2020 Consortium Members
Names ofCompanies/Organizations
Anglo Coal Kumba Resources
CSIR Mining Technology National Union of Mineworkers (NUM]
Department of Minerals and Energy (DME] National Research Foundation (NRF]
Department of Trade and Industry (DTI-THRIP] Sasol Coal
Xstrata (producer] The Chamber of Mines of South Africa
Eskom (state utility] University of Pretoria
Eyesizwe University of Witwatersrand*
*Note: The University of Witwatersrand has for more than a decade conducted research on coal seam gas content, gas
emission rates, permeability, and other coal properties (Schwochow, 1997].
The potential end uses for CMM in South Africa include electric power generation, boiler fuel,
transportation fuel, and petrochemical feedstocks. CMM could offset or reduce growing
requirements for gas imports to meet increasing gas demand. It could also provide an effective fuel
substitute for coal and firewood.
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Where mines are shallow and less gassy, collected CMM could be used for local heating purposes,
but infrastructure would be required. In new areas, where virgin seams are deeper and gassier,
CBM development could precede mining. Higher gas volumes from CBM and subsequent CMM in
commercial quantities would require infrastructure investments for development of deeper mines,
installation of gas collection technologies, and construction of gas pipelines to move the methane to
markets.
Evidence of the gas potential in South African coals has evolved from a long record of gas-related
mine explosions. Mines experience problems with gas and dust explosions and fires because the
coals are hard and highly prone to sparking as are the sandstone roof rocks. The proportion of
mine deaths related to explosions increased from 3 percentin 1955 to 21 percent in 1993
(Schwochow, 1997).
31.3.2 Regulatory Information
In South Africa, CBM is defined by law as a unique mineral, so rights to its exploration and
development can be separate from those of coal in the same seam. Under the latest Minerals Act, all
mineral rights are vested with the government Companies that held mineral rights under old
orders, however, can apply for an extension to retain those rights. Technically, development
licenses are required by law after commercially successful exploration, but many mines currently
operate under exploration licenses. Licensing requirements and applications are available for
review on the Department of Minerals and Energy's Web site (www.dme.gov.za).
Electricity, petroleum pipelines, and piped gas including CBM are regulated by the independent
National Energy Regulator of South Africa (NERSA), which, among other things, issues licenses for
construction and operation of gas transmission, storage, distribution, liquefaction, and re-
gasification facilities (Gas Act, 2001). The piped gas industry is regulated by the Gas Act as amended
by the National Energy Regulatory Act, which was brought into operation in 2005. Prior to 2005,
the gas industry was not regulated and companies had to negotiate a regulatory agreement with the
South African Government The Piped-Gas Regulations Act came into effect in 2007. The Act is
continuously reviewed by NERSA with the aim of suggesting possible amendments to the Minister
of Minerals and Energy should these be deemed necessary (NERSA, 2009).
31.4 Profiles of Individual Mines
A comprehensive inventory of coal mines and coal production in South Africa can be found on the
DME web site (DME, 2010c). Detailed spreadsheets of mines and contact information are also
available online at http://www.dme.gov.za. Profiles for individual mines are not available.
31.5 References
Anglo (2005): Production starts at Anglo American's Isibonelo coal mine in South Africa, AngloAmerican
press releases, July 2005. http: //www.angloamerican.eom/media/press-releases/2005/2005-07-04
ARI (1992): Coalbed Gas -2: Vast Resource Potential Exists in Many Countries, Kuuskraa, Velio A., and
Jonathan R. Kelafant., Oil & Gas Journal, 2 November 1992. (Reprint)
CM (2013): Facts and Figures 2012, Chamber of Mines of South Africa, 2013.
https://commondatastorage.googleapis.com/comsa/facts-and-figures-2013.pdf
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COA (2009): Coal of Africa Limited, Annual Report, 2009. http: / / www, coalofafrica. com / annual-
reports/Co AL AR 2009.pdf
Creamer (2010a): "Methane flaring mitigating climate change - Anglo Thermal Coal," Mining Weekly, 12 May
2010. http://www.miningweekly.com/article/methane-flaring-mitigating-climate-change-anglo-
thermal-coal-2 010-05-12
Creamer (2010b): "Gold Fields turns killer-gas methane curse into R200m Beatrix revenue stream," Mining
Weekly, 26 May 2010. http://www.miningweeklv.com/article/gold-fields-turns-killer-gas-methane-
curse-into-r200m-beatrix-revenue-stream-2 010-05-2 6
DEAT (2010): National Greenhouse Gas Inventory, Department of Environmental Affairs and Tourism climate
change web page, accessed July 2010.
http://www.environment.gov.za/ClimateChange2005/National Greenhouse Gas Inventory.htm
DME (2006): South Africa's Mineral Industry 2005/2006, South Africa Department of Minerals and Energy,
2006.
DME (2008): South Africa's Mineral Industry 2007/2008, South Africa Department of Minerals and Energy,
2008.
DME (2009): Operating Mines and Quarries and Minerals Processing Plants in the Republic of South Africa -
2009, South Africa Department of Minerals and Energy, Pretoria, South Africa, 2009.
DME (2010a): "Coal," South Africa Department of Minerals and Energy, accessed 2010.
DME (2010b): "Overview of the Minerals Industry," South Africa Department of Minerals and Energy,
accessed 2010.
DME (2010c): "Mineral Directories," South Africa Department of Minerals and Energy, accessed 2010.
DMR (2013): Stat Tables 2013, Department of Mineral Resources, 2013.
EIA (2007): Data obtained from International Energy Annual 2005, U.S. Energy Information Administration,
Washington, DC, table posted 21 June 2007.
EIA (2013): International Energy Statistics, U.S. Energy Information Administration, Washington, DC, data
accessed June 2014.
http://www.eia.gov/cfapps/ipdbproiect/iedindex3.cfin?tid=l&pid=7&aid=l&cid=regions&syid=1980&e
vid=2 007&unit=TST #
EIA (2014): South Africa Country Analysis Brief, U.S. Energy Information Administration, Washington, DC, 28
February 2014. http: //www.eia.gov/countries/analysisbriefs/South africa/south africa.pdf
ESK (2014): Coal Fact Sheet, Eskom, Johannesburg, South Africa, January 2014.
http://www.eskom.co.za/AboutElectricity/FactsFigures/Documents/C00007CoalSARevl2.pdf
Gas Act (2001): Act No. 48 of 2001, Published in the Government Gazette of the Republic of South Africa, 21
February 2002.
GCIS (2013): South Africa Yearbook2012/2013 - Minerals, Energy and Geology, Government Communication
and Information System, 2013.
http://www.gcis.gov.za/sites/www.gcis.gov.za/files/docs/resourcecentre/yearbook/2012/08%20Ener
gv%20.pdf
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed October
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
IEA (2013): Energy Statistics - Share of total primary energy supply in 2011, International Energy Agency,
Paris, France, accessed 10 June 2014. http://www.iea.org/stats/WehGraphs/SOUTHAFRIC4.pdf
Limpitlaw and Aken (2005): "Post Mining Rehabilitation, Land Use, and Pollution at Colliers in South Africa,"
presented at the Colloquium: Sustainable Development in the Life of Coal Mining, Boksburg, 13 July 2005.
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http://limpitlawconsulting.eom/05Limpitlaw%20et%20al%202005%20Post%20Mining%20Rehabilitat
ion%2 0Land%2 0Use%2 0and%2 0Pollution%2 0at%2 OCollieries.pdf
Le Roux (2007]:"Gold Mine Pursues Carbon Credits for Methane Capture," Mining Weekly Online, Helene Le
Roux, May 2007. http: //www.miningweekly.com/article/gold-mine-pursues-carbon-credits-for-
methane-capture-2 007-05-04
Lloyd and Cook (2004): Methane Release from South African Coal Mines, Lloyd, Philip and Alan Cook, 2004.
http://www.erc.uct.ac.za/Research/publications/05Llovd-Cook%20Methane%20release.pdf
Merwe (2007): "Interest in Coal Bed Methane on the Increase," Mining Weekly Online, Christy van der Merwe,
March 2007. http: //www.miningweekly.com/article/interest-in-coalbed-methane-on-the-increase-
2007-03-16
NERSA (2009): NERSA Annual Report for 2008/09, posted 2009.
http://www.nersa.org.za/Admin/Document/Editor/file/News%20and%20Publications/Publications/C
urrent%20Issues/NERSA%20Annual%20Report%2 02 009.pdf
SAinfo (2009): South Africa 'needs 40 new coal mines,' August 2009.
http://www.southafrica.info/news/business/832012.htm
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
UNFCCC (2000): South Africa "Initial National Communication to UN Framework Convention on Climate
Change," p.77, October 2000. http: //unfccc.int/resource/docs/natc/zafnc01.pdf
UNFCCC (2014): Ratification Status - South Africa, United Nations Framework Convention on Climate Change,
accessed September 2014. http: //maindb.unfccc.int/public/countrv.pl?countrv=ZA
USEPA (1998): "South Africa Country Fact Sheet" World Bank / U.S. EPA Seminar and Roundtable on Coalbed
Methane Development Potential, September 1998.
USEPA (2004a): Coalbed Methane Outreach Program South Africa Trip Report, 1-13 March 2004.
USEPA (2004b): International Activities - South Africa, U.S. Environmental Protection Agency, Coalbed
Methane Outreach Program, 2004.
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990 - 2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
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32 Spain
32.1 Summary of Coal Industry
32.1.1 Role of Coal in Spain
Spain has experienced significant industrialization since the 1970s, spurred on by its European
Union (EU) membership in 1986. These factors have contributed to a 100 percent increase in
energy demand since the mid-1970s. Spain is Europe's fifth largest energy consumer and has
virtually no domestic production of liquid fuels or natural gas, so it depends upon imports for the
bulk of its energy needs (EIA, 2014a). Coal represented more than 12 percent of the nation's
primary energy supply in 2012 (EURACOAL, 2013).
Coal is Spain's most plentiful indigenous energy source, with reserves estimated at 530 million
tonnes (Mmt). In 2012, Spain produced 6.15 Mmt of coal, while consuming 28.7Mmt, relying on
imports for the balance (EIA, 2014b). Table 32-1 summarizes Spain's coal reserves and production.
Table 32-1. Spain's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
200
330
530
33 (0.06%]
(2011]
Annual Coal Production (2012]
6.15
0.0
6.15
32 (0.08%]
Source: EIA (2014b]
Spain's hard coal mining occurs primarily in northwestern Spain in Asturias, Castilla-Leon, Aragon,
and Leon-Palencia, and also in the southern areas of Ciudad Real and Cordoba. The important
opencast operations are located in Aragon, Ciudad Real, and at the border between Asturias and
Leon. Teruel has the largest sub-bituminous coal reserves in the country, while most of the lignite is
located in Galicia (see Figure 32-1). In recent years, high extraction costs have led to the gradual
closure of mines, including the lignite mines in Galicia (EURACOAL, 2013).
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Figure 32-1. Spain's Coal Fields
Lignite Hard coal
Source: EURACOAL (2013)
32.1.2 Stakeholders
Table 32-2 lists Spain's key stakeholders in the development of coal mine methane (CMM] industry.
Table 32-2. Key Stakeholders in Spain's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
HIJNOSA (Huelleras del Norte S.A.J
Endesa, SA.
UMINSA (Union Minera del Norte S.A.]
Project host
Developers
See http://www.epa.gov/coalbed/networkcontacts.html
Project opportunity
identification and
planning
Engineering, Consultancy,
and Related Services
See http://www.epa.gov/coalbed/networkcontacts.html
Technical assistance
Universities/Research
Establishments
Geological and Mining Institute of Spain (Instituto Geologico
y Minero de Espagne)
Technical assistance
Government Groups
Ministry of Industry, Energy, and Tourism - Directorate of
Energy Policy and Mines
Regulatory
32.1.3 Status of Coal and the Coal Mining Industry
Government-owned companies produce most of the coal in Spain, One of the main public companies
is llulleras del Norte, S.A. (abbreviated as HUNOSA], which is 100 percent owned by the
government through the Sociedad Estatal de Participaciones Industrials (SEPI) holding company.
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HUNOSA, the major producer of hard coal in the central Asturian basin, was founded in 1967 to
direct most of Spain's coal mining, and it gradually took over the larger coal companies. There are a
few remaining private companies, however, the largest of which is Union Minera del Norte S.A.
(UMINSA) that resulted from a merger of 15 independent companies (OECD, nd). Endesa, the
leading lignite producer, is also the largest power generating and distributing company in Spain,
with nearly 40,000 megawatts (MW) of installed generating capacity (Endesa, 2014).
Similar to other EU members, Spain's coal industry has struggled to remain competitive vis-a-vis
imported coal and other energy sources. More than 60 percent of Spain's hard coal is mined in
opencast mines, making indigenous hard coal competitive compared with imported coal
(EURACOAL, 2013). The National Energy Plan (Plan Energetico Nacional or PEN), the basic
statement of official energy policy first formulated in 1978, was aimed at a rationalization of energy
consumption and a reduction in Spain's dependence on imported energy. In line with the energy
rationalization policies set by PEN, the government sought to increase the efficiency of the coal
mining sector by closing down high-cost mines and by providing financial aid for the industry's
modernization. To encourage the cement and other industries to convert from oil to coal, the
government allowed them to import duty-free coal. The government also made efforts to substitute
the use of oil for coal in urban areas.
Up until the 2008 economic recession, Spain was slowly phasing out its coal production subsidies in
accordance with EU requirements. However, coal production and consumption increased in 2011
after the Spanish government introduced domestic coal production subsidies and gave preferential
wholesale power market access to coal-powered generators in an attempt to reduce the country's
imported coal dependence. This caused electricity producers to move away from renewable energy
sources and back to coal. CARBUNION, the Spanish coal producers' federation, sought to maintain
competitive indigenous coal production but in 2012, the government reduced mining subsidies by
more than 80 percent, from 300 million Euros to 55 million Euros during 2011-2013. According to
Spain's Framework Plan for Coal Mines and Mining Communities 2013-2018, coal production
subsidies will end after 2018 (EIA, 2014a). The 2013-18 coal plan also aims to reduce coal
production to 5.9 Mmtby 2018.
32.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies no
projects in Spain, in operation or development (GMI, 2014). Updates on future CMM projects in
Spain can be found at https: //www.globalmethane.org/coal-mines/cmm/index.aspx.
32.2.1 CMM Emissions from Operating Mines
According to USEPA, methane emissions in Spain totaled 86.1 million cubic meters (m3) in 2000,
but are expected to decrease by nearly half to 44.1 million m3 by 2015, and then anticipated to
decrease slightly more to 42.7 million m3 by 2030. Table 32-3 summarizes Spain's CMM emissions.
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Table 32-3. Spain's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected)
Total CH4 Emitted
86.1
64.4
46.2
44.1
Source: USEPA(2012)
32.2.2 CMM Emissions from Abandoned Coal Mines
At least 100 underground coal mines have been abandoned since 1970, but emissions from none of
them are being exploited (Martinez, 2004).
32.2.3 CBM from Virgin Coal Seams
A "Spanish National Inventory of Coalbed Methane (CBM) Resources" was initiated in 2002
(Martinez, 2004). Although none of the CMM or abandoned mine methane emissions are being
exploited in any coal basin, either in active or abandoned mines, future projects may emerge.
32.3 Opportunities and Challenges to Greater CMM Recovery
and Use
As reflected in Table 32-4, Spain ratified the Kyoto Protocol as an Annex 1 country. The country's
Kyoto emission reduction target is no more than 15 percent of its baseline emissions. As an Annex 1
country, Spain is eligible to host Joint Implementation (JI) projects but to date, its three JI efforts are
focused on nitrous oxide abatement from nitric acid plants.
Table 32-4. Spain's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 13,1992
December 21,1993
Kyoto Protocol
April 29,1998
May 31,2002
Source: UNFCCC (2014]
The Spanish Strategy of Climate Change and Clean Energy (EECCEL), adopted in 2007 and running
through 2020, defines actions to fight climate change while achieving cleaner energy and is based
on the "Spanish Strategy for the fulfillment of the objectives under the Kyoto Protocol" framework
approved by Spain's National Climate Council in 2004 (Magrama, 2007). However, the 2007
Strategy was primarily based on promotion of renewable electricity generation via a feed-in tariff
scheme (e.g., subsidies) that has been mostly abandoned, so it is unclear how effective the climate
policy might be until the current situation is resolved (Ecologic Institute - eclareon, 2014).
32.3.1 Market and Infrastructure Factors
The 2008 economic crisis was particularly harsh in Spain, and the government was forced to
introduce austerity measures (i.e., deep subsidy cuts) that directly impacted the coal industry.
There are now coal mines operating without these subsidies, which represent a newly competitive
mining industry in Spain. In September 2013, the Spanish government sought review of the EU's
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directive on state aid to facilitate the closure of uncompetitive coal mines to allow those facilities
that have achieved competitiveness to continue coal production beyond 2018 without having to
repay past state aid (EURACOAL, 2013).
Spain's high levels and costs of gas imports ensure a significant market for any domestically
produced natural gas that can compete on a cost basis with LNG imports and other high cost gas
imports. Possible end uses for CMM in Spain include electric power generation and support for
mine operations.
32.3.2 Regulatory Information
Mineral resources (including gas) are owned by the state and licensed for production by quasi-
private enterprises and private operators.
Current subsidies for coal production are being phased out, and there are no current subsidies
known for coal bed methane or CMM production.
32.4 Profiles of Individual Mines
No individual mine profiles are available at this time for Spain.
32.5 References
Ecologic Institute - eclareon (2014): Assessment of climate change policies in the context of the European
Semester Country Report: Spain, Ecologic Institute - eclareon, Berlin, Germany, January 2014.
http://ec.europa.eu/clima/policies/g-gas/progress/docs/es 2014 en.pdf
EIA (2014a): Country Analysis Note - Spain, U.S. Energy Information Administration, Washington, DC, last
updated July 2014. http: //www.eia.gov/countries/country-data.cfm?fips=SP
EIA (2014b): International Energy Statistics, (data as of December 2013), U.S. Energy Information
Administration, Washington, DC, accessed July 2014.
http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
Endesa (2014): Key Figures, Endesa, website accessed September 2014.
http://www.endesa.com/en/ahoutRndesa/oiirStrategv/Kevfigiires
EURACOAL (2013): Annual Report 2013: Coal Industry across Europe 2013 (Spain), EURACOAL, 14
November 2013. http://www.euracoal.org/pages/medien.php?idpage=1410
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed in July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
Magrama (2007): Spanish Climate Change and Clean Energy Strategy - Horizon 2007-2012-2020, Spain
Ministry of Agriculture, Food, and Environment (Magrama), 4 July 2007.
http://www.magrama.gob.es/es/camhio-
climatico/publicaciones/documentation/cle ene pla urg mea tcm7-12478.pdf
Martinez (2004): Presentation to UNECE Ad Hoc Group of Experts on Coal Mine Methane, Martinez, Roberto,
Instituto Geologico y Minero de Espagne (IGME), 6 December 2004.
http://www.unece.org/ie/se/pdfs/cmm/ppp09dec/IGME Martinez UNECECMM.pdf
OECD (nd): "Spain: Inventory of Estimated Budgetary Support and Tax Expenditures for Fossil Fuels,"
Organisation for Economic Co-operation and Development, not dated.
http://www.oecd.org/site/tadffss/ESP.pdf
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UNFCCC (2014): Ratification Status - Spain, United Nations Framework Convention on Climate Change,
accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=ES
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
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33 Turkey
O
33.1 Summary of Coal Industry
33.1.1 Role of Coal in Turkey
Coal accounts for just over half of Turkey's total primary energy production from domestic
resources, but it is not clear what role coal will play in Turkey's future energy makeup. Coal
production and consumption has risen dramatically over the past few years, but so has the
country's natural gas use as Turkey is emerging as a major energy transport hub connecting central
Asia and Europe (EIA, 2009). The amount of natural gas in Turkey's total energy consumption
increased to 32 percent from 6 percent between 1990 and 2010. This consumption is reflected in
the share of electricity generated from gas between 1990 and 2010, which rose to 49 percent from
18 percent over the time period (MEU, 2013).
In 2010, coal represented about 53 percent of Turkey's primary energy production from domestic
resources, with low-quality lignite comprising 48 percent and hard coal 5 percent. The role of
domestic coal is projected to increase in Turkey's primary energy supply, but due to increasing total
energy consumption, dependency on foreign energy imports has increased to 70 percent in 2010
from 52 percent in 1990 (MEU, 2013). As of 2012, Turkey produced 69.51 million tonnes (Mmt) of
coal and imported 31.77 Mmt of mostly hard coal for thermal power plants, steel production, and
domestic heating mainly from Russia, Colombia, the United States, and South Africa (EURACOAL,
2014; EIA, 2014).
Table 33-1 summarizes Turkey's proved coal reserves and production.
Table 33-1. Turkey's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
(2011]
322
8,380
8,702
(13,0.98%]
Annual Coal Production (2012]
3.56
65.95
69.51
(12,0.88%]
Source: EIA (2013]
Figure 33-1 shows locations of coalfields in Turkey. Lignite deposits are widespread throughout the
country. BP's Statistical review of World Energy (2013) provides a somewhat lower estimate coal
reserves with estimated lignite, hard coal and total coal resources of 1,645, 479.9, and 2,125.53
Mmt, respectively. In-country estimates completed by the Turkish Ministry of Energy and Natural
Resources (MENR) increased total lignite reserves from 8.3 to 14.1 billion tonnes based on
exploratory work completed by the Mineral Research and Exploration (MTA) in 2014.
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Most of Turkey's reserves are considered by MENR as economically mineable, though about half of
the reserves have a low heating value that ranges between 1,000 and 1,500 kcal/kg. Approximately
46 percent of Turkey's lignite is in the Afsin-Elbistan Basin (MENR, 2014). Turkey's hard coal
deposits are mostly located in the western part of the country, in the Zonguldak Basin (see Figure
33-2}. MENR estimated hard coal resources in the basin at 1,316 billion tonnes; of which, 514 Mmt
are considered reserves.
Figure 33-1. Turkey's Coal Fields
Zonguldak^^ Mengen Karliova
Orta t
juiudK_ /V7e
I ^^0 Orta Basirh^ Kangal
• Istanbul
Orhaneli^R\
«, Alpum W
Beypazari
k«L
Seyitomei
Qan
Seyitomer Beyfehir„ KarsP'nar
• Izmir
Milas-
Antalya
Lignite
Source: EURACOAL (2014)
Figure 33-2. Turkey's Zonguldak Coal Basin
BULGAjtlA V
Black Sea
Zonguldai:
INSCT
^ GEORGIA
\Samsun
Zoneuldik " Jjjbf?".
%nbUl^= ¦ ISpir i^KMEMA
Bursa .Ankara „ Bayburt •
I ¦¦ •«¦ * Sorgun . v -v....
c' , T V R K E Y , !
>j <_^> Izmir - , « ^ . Hazro i IRAK
, ' . Diyarbakir .. — ...._ >
Amaly.Ccikiirboy
Mediterranean Sea
Cyprus I -• Haidcoal deposit
,r" J I / * Browncoal deposit
J_1
AmasraA'
- Amasra *
/% J
/ Xm
Zonguldak
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TURKEY
33.1.2 Stakeholders
The government-run companies, Turkish Coal Enterprise and Turkish Hard Coal Enterprise, are the
main coal companies. Table 33-2 lists all potential stakeholders in Turkey's coal mine methane
(CMM) industry.
Table 33-2. Key Stakeholders in Turkey's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
¦ Turkish Hard Coal Enterprise, TTK (Tiirk Ta§k6miiru
Project host
i§letmeleri]
¦ Turkish Coal Enterprise (TKI]
¦ HEMA Energi
Government Groups
¦ Ministry of Energy and Natural Resources
Preparation and
¦ Organization of Aegean Lignite
implementation of mining
¦ Turkey Hard Coal Authority
and energy policies, plans
¦ Representation of Turkish Coal Enterprises
and programs
Developers, Engineering,
¦ See
Technical assistance.
Consultancy, and Related
http://www.epa.gov/coalbed/networkcontacts.html
project opportunity
Services
identification and
planning
33.1.3 Status of Coal and the Coal Mining Industry
The Turkish government has complete ownership over the country's coal resources and these
rights are administered by two government-owned corporations, Turkish Coal Enterprises (TKI)
and Turkish Hard Coal Enterprises (TTK). In recent years, TKI and TTK have leased out coal
reserves to private companies and several private mines are in operation. TKI was established in
1957 to operate the coal mines of Turkey and it is the major brown coal producer in the country,
operating 30 opencast and nine deep mines, which produced a total of 33 Mmt of low quality lignite
in 2009. In addition to TKI, Elektrik Uretim A.§. (EUA§) and the private sector produced 36 and 7
Mmt, respectively (EURACOAL, 2010). TTK was established in 1983 to operate hard coal mines in
the Zonguldak basin and is operating five deep mines that produced approximately 2.8 Mmt in
2010 (EURACOAL, 2010). This enterprise carries out the exploration, production, and marketing of
domestic hard coal (TTK, 2010; EURACOAL, 2010). The private sector accounts for only about 8
percent of coal production, but about 35 percent of coal production reported by the state
enterprises is mined by private companies under subcontract (EURACOAL, 2010).
Turkey has both active surface and underground mines. However, about 90 percent of the country's
lignite production comes from surface mines (MBendi, 2010). More specific details about mines,
reserves, and location of Turkey's coal can be found on an interactive Google Map developed by the
MENR (MENR, 2010).
33.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies one
project currently underway for the optimization of degasification systems to reduce methane
emissions from Turkish coal mines (GMI, 2014). U.S. EPA's Coalbed Methane Outreach Program
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(CMOP) has funded two pre-feasibility studies for CMM development in the Zonguldak region,
awarded Virginia Tech a grant to study CMM and CBM potential in the country, and is currently
working on a project at the HEMA Energi Mine in Amasra, Turkey, that is focused on mine pre-
drainage and CMM utilization.
33.2.1 CMM Emissions from Operating Mines
CMM emissions from operating mines in Turkey are shown in Table 33-3.
Table 33-3. Turkey's CMM Emissions (million cubic meters)
Emissions
2000*
2005*
2010**
2015
(projected)1
Underground Mines
41.24
37.40
41.99
Post-Underground Mines
NA
NA
6.00
Surface Mines
71.96
66.40
80.85
Post-Surface Mines
NA
NA
6.74
Total emitted (= total liberated -
recovered &used)
113.20
103.80
135.58
127.68
Sources: *UNFCCC (2010 [converted from Ggand rounded to the hundredths]];
**UNFCCC (2013]; +USEPA (2012]
33.2.2 CMM Emissions from Abandoned Mines
No information was found on CMM emissions from abandoned mines in Turkey.
33.2.3 CBM from Virgin Coal Seams
Coal bed methane (CBM) from the Zonguldak hard coal region could play a very significant role in
Turkey's energy economy. The CBM in-place resources in two districts of the Zonguldak hard coal
region are presently estimated to be at least 3 trillion cubic meters (Mustafa and Balat, 2004). In
2012, the U.S. Trade and Development Agency funded a CBM feasibility study in support of HEMA's
CBM program in the Zonguldak coal region. HEMA has drilled a series of wells throughout their
license area and intends to initiate full-scale development in late 2014.
33.3 Opportunities and Challenges to Greater CMM Recovery
and Use
As indicated in Table 33-4, Turkey has acceded to the UNFCCC.
Table 33-4. Turkey's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
—
February 24,2004 (Accession]
Kyoto Protocol
—
—
Source: UNFCCC (2014]
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33.3.1 Market and Infrastructure Factors
In May 2001, Turkey enacted a new Natural Gas Law. Prior to this law, most of the natural gas
market and infrastructure was dominated by the Petroleum Pipeline Corporation (a.k.a., BOTAS, a
state-owned company). The new gas law requires that the natural gas transmission, storage, and
distribution networks be open to competition and monopolistic elements be unbundled. BOTAS still
owns the majority of the transmission infrastructure and most of the market, but distribution,
storage, and import is open to competition. BOTAS has begun transferring ownership of its import
contracts to private entities to comply with its mandated 20 percent of total market share.
Revisions to the Natural Gas Law are being debated to improve the privatization effort and to
further reduce dominance of BOTAS (MONDAQ, 2010).
Although Turkey has moved toward liberalizing its coal industry and no rules ban private sector
involvement, no foreign companies have made investments (Kayikfi, 2010). Seeking to increase its
domestic electricity generation, Turkey is looking to expand its domestic lignite production instead
of relying on external natural gas resources. With potential for thermal power generation, Turkey
has opened up six of its lignite fields to the private sector under a royalty model (MBendi, 2010).
Turkey has several international natural gas lines that bring the resource into the country, which
may make Turkey a major player in energy transit (EIA, 2009).
33.3.2 Regulatory Information
The Ministry of Energy and Natural Resources is the main body of the Turkish mining and energy
sector, responsible for the preparation and implementation of mining and energy policies, plans
and programs, in coordination with its dependent and related institutions, and other public and
private entities. The Ministry's duties related to the mining sector mainly include organizing and
controlling the mining license for production of in-country natural resources, in order to contribute
to the economy.
There have been several updates to laws regulating mining in recent years. They have, however,
been struck down in court, and licenses and permits are still regulated from one law dating back to
1985 and two others from 2005. Three licenses relating to mining exist: a prospecting license, an
operation license, and an operation permit (Kayikfi, 2010).
33.4 Profiles of Individual Mines
No information profiling individual Turkish coal mines was found. Updates on future CMM projects
in Turkey can be found at https: //www.globalmethane.org/partners/turkey.aspx
33.5 References
EIA (2009): Country Briefs - Turkey, U.S. Energy Information Administration, Washington, DC, April 2009.
EIA (2013): International Energy Statistics, U.S. Energy Information Administration, Washington, DC, website
accessed May 2014. http: //www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
EIA (2014): Country Analysis - Turkey, U.S. Energy Information Administration, Washington, DC, 17 April
2014. http://www.eia.gov/countries/cab.cfm?fips=TU
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EURACOAL (2010): European Association for Coal and Lignite, Brussels, Belgium, website accessed June
2010.
EURACOAL (2014): Country Profiles - Turkey, European Association for Coal and Lignite, Brussels, Belgium,
website accessed May 2014. http://www.euracoal.com/pages/layoutlsp.php?idpage=475
Kayikfi (2010): Turkey: A Brief Overview of the Licenses and Permits in the Turkish Mining Sector, Gencin
Kaya Kayikfi, hosted by MONDAQ, website accessed 30 June 2010.
http://www.mondaq.com/article.asp7articleickl03124
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
MBendi (2010): Coal Mining in Turkey - Overview, 2010.
http: / / www.mbendi. com / indv /ming/coal /as /tr /p0005.htm
MENR (2010): Energy and Natural Resources Map (Enerji ve Tabii Kaynaklar Haritasi), Turkey Ministry of
Energy and Natural Resources, Ankara, Turkey, website accessed June 2010.
MENR (2014): Coal, Turkey Ministry of Energy and Natural Resources, Ankara, Turkey, website accessed
November 2014. http://www.enerii.gov.tr/en-US/Pages/Coal
MEU (2013): Turkey's Fifth National Communication under the UNFCCC, Ministry of Environment and
Urbanisation, Ankara, Turkey, 2013.
http://unfccc.int/files/national reports/annex i natcom/submitted natcom/application/pdf/nc5 turke
vm.pdf
MONDAQ (2010): Turkey: Prospective Amendments on Natural Gas Market Law in Turkey, MONDAQ, 29 June
2010. http://www.mondaq.com/article.asp?articleid=l04024
Mustafa and Balat (2004): Turkey's Coal Reserves, Potential Trends and Pollution Problems of Turkey, Balat,
Mustafa and Gunhan Ayar, in Energy, Exploration & Exploitation, Volume 22, Number 1, 2004.
http://multi-science.metapress.com/content/r79q68u863354352/fulltext.pdf
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
TTK (2010): "Hard Coal Production" (in Turkish only), Turkish Hard Coal Enterprises, 2010.
http://www, taskomuru.gov. tr/index.php?page=savfagoster&id=2 5
UNFCCC (2010): 2010 Annex I Party GHG Inventory Submissions, 13 April 2010.
http: / /unfccc.int/national reports /annex i ghg inventories/national inventories submissions /items /52
70.php
UNFCCC (2013): 2013 Annex I Party GHG Inventory Submissions, 12 April 2013.
https: //unfccc.int/national reports /annex i ghg inventories/national inventories submissions /items /7
383.php
UNFCCC (2014): Status of Ratification - Turkey, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=TR
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
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34 Ukraine
34.1 Summary of Coal Industry
34.1.1 Role of Coal in Ukraine
Ukraine produced approximately 1 percent of total world coal production in 2012 (see Table 34-1)
producing 64,362 million tonnes (Mmt) of saleable hard coal according to the U.S. Energy
Administration, making it the fourteenth largest producer of coal in the world (EIA, 2014a). BP
ranked Ukraine as eleventh in production in their 2013 survey report with total raw coal
production of 88.2 Mmt in 2012, a 4 percent increase over 2011 and a 20 percent increase over
2009 (BP, 2013). Statistics for 2013 have been released by the Ministry of Energy and Coal Industry
of Ukraine, According to the Ministry, raw coal production totaled 83.7 Mmt in 2013 (Yashchenko,
2014).
Table 34-1. Ukraine's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous &
Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
15,351
18,522
33,873
7 (3.8%]
(2011]
Total Primary Coal Production (2012]
64.4
0
64.4
14 (0.8%]
Source: EIA (2014a]
All of Ukraine's production is hard coal, according to IEA and EIA. 2007 was the last year lower rank
brown coals were produced in Ukraine and even then only a small volume of lignite was
produced—0.2 Mmt comprising only 0.3 percent of total coal production (IEA, 2013). As reflected
in Table 34-1, Ukraine's total coal reserves as of 2012 were 33.9 billion tonnes, of which about 15.4
billion tonnes were hard coals and 18.5 billion tonnes were soft coals (sub-bituminous and lignite)
(BP, 2013). Euracoal, the European Association for Coal and Lignite, estimates that Ukraine's total
coal resources are 54 billion tonnes with economically recoverable reserves of 34 billion tonnes
(Euracoal, 2013). Coal in 330 seams has been explored to a depth of 1,800 meters, with 130 seams
exceeding 0.45 meters in thickness. Only 10 seams are suitable for development with the remainder
being too deep or too thin to mine (M2M Workshop - Ukraine, 2005).
Coal production in Ukraine declined significantly from 1990 to 1996, falling by over 50 percent
from 164.9 Mmt in 1990 to 70.5 Mmt in 1996. Coal production has since stabilized at an
approximate average of 80 Mmt per year of raw coal production (BP, 2013). In 2013, Ukraine
produced 83.7 Mmt of coal with 59.6 Mmt coming from private mines and the remaining 24.1 Mmt
coming from state-owned mines (Yashchenko, 2014). In addition to licensed mines, unregulated
coal mining is also reported to be occurring in Ukraine with reports estimating that illegal mining
may produce up to 10 percent of Ukraine's coal (Cragg 2013; Golovnev, 2013).
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Figure 34-1. Ukraine's Historical Raw Coal Production Volumes, 2000-2012
83.9
84.6
88.2
I
82.5
81.3
80.2 B 80.2
79.5
83.7
2005 2006
2010 2011 2012 2013
Sources: BP (2013]; Yashchenko (2014]
Ukraine remains critically reliant on coal as one of its primary resources for electric power
generation along with nuclear power (EIA, 2014b). In 2012, coal supplied 36 percent of Ukraine's
total energy supply (BP, 2013}. Ukraine is not among the world's major coal exporters because of a
lack of progress on deregulation, along with underinvestment in coal production l eading to high
coal production costs. Despite its sizeable resources Ukraine is a net importer of coal and in 2012
imported a net 6.963 Mmt (EIA, 2014a). In 2012, 46 percent of the country's rated generating
capacity was in thermal sources (coal, oil, and gas-fired), compared to nuclear at 48 percent and
hydroelectric at 6.0 percent (EIA, 2014a). Thermal production's role steadily decreased between
2003 and 2005 from 50 percent to 45 percent as nuclear generation capacity increased; however,
nuclear and thermal generation have been roughly equal since 2006 (EPA, 2014a).
Coal is produced in two major basins in Ukraine, the Donetsk Basin (60,000 km2) in southeastern
Ukraine (and western Russia), and the Lviv-Volyn basin (7,500 km2) in western Ukraine, which
continues into Poland (Sachsenhofera, 2002; M2M - Ukraine, 2005). The Donetsk Basin is
commonly referred to as "the Donbass" and holds approximately 95 percent of Ukraine's proved
coal reserves (Euracoal, 2013). The Donbass can be further subdivided between the Donetsk (45.6
percent), Lugansk (34.2 percent), and Dnipropetrovsk (15.3 percent) regions (Figure 34-2).
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Figure 34-2. Ukraine's Coal Fields
\
C
H r ~ r9
i vcon ) j r~"C
,:2HrTOfci*
/
V
^ K_ wmKrr* u
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iinnnw ¦ 1
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'caw
r X
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Source: IEA (2012}
34.1.2 Stakeholders
Potential stakeholders in coal mine methane (CMM) development in Ukraine are listed in Table 34-
2.
Table 34-2. Key Stakeholders in Ukraine's CMM Industry
Stakeholder Category
Stakeholder
Roles
Coal associations
Makeyevugol Coal Association
(http://www.makeevugol.donbass.com/)
Donets ksteel
DTEK (SCM Holdings)
Komsomolets Donbassa Mine
DTEK Pavlogradugol (10 mines)
Dobropolyeugol (5 mines)
Rovenkianthracite (6 mines)
Sverdlovanthracite (5 mines) Mine
ALC Mine Bilozerska (1 mine)
State Enterprise Coal Company Krasnolimanskaya Mine
Luganskugol
Pervomayskugol
Oktyabrugol
Private Joint Stock Company "Mine named after AF
Zasyadko
METINVEST Holdings
(http://www.metinvestholding.com/en)
Krasnodonugol (5 mines)
Project hosts
It
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Table 34-2. Key Stakeholders in Ukraine's CMM Industry
Stakeholder Category
Stakeholder
Roles
Coal associations (con't]
Coal Enersv SA fhttp://www.coalenergv.com.ua/en/l
Project hosts
Svyato-Pokrovskaya mine
Svyatitelya Vasiliya Velikogo mine
Svyato-Serafimovskaya mine
Svyato -And re evs kaya
Prepodobnogo Sergiya Radonezhskogo mine
Chapaeva mine,
1 Maya mine
Ternopolskaya mine
Svyato-Nikolayevskaya mine
Udacha mine
Rassypnianskii Krutoi mine sectors
Donetsk Coal & Enersv http://www.ivcdu.dn.ua/
Donugol (http://www.donugol.ru/]
Dobropolyengol
Dobropolye
Krasnoarmeyskugol
Equipment
Caterpillar, USA
Power generation
manufacturers
Zeppelin Ukraine (Ukrainian division of Caterpillar]
equipment supplier
GE Jenbacher (Austria]
Biothermica (Canada] - VAM
Hofstetter (Switzerland] - flares
MEGTEC Systems
Durr
Developers
ATEC
Project opportunity
Carbon TF
identification and
Eco-Alliance
planning
EcoMetan
Energolmpex
EuroGas (Lviv-Volyn Basin]
Green Gas International
Green Way 2020
HEL East Ltd
Pro2 Anlagentechnik GmbH
See http://www.epa.gov/coalbed/networkcontacts.html
Engineering, consultancy.
Advanced Resources International Inc. (USA]
Technical assistance
and related services
DMT GmbH
Raven Ridge Resources
RE I Drilling (USA]
Ruby Canyon Engineering
Schluberger (global]
Weatherford International (global]
See http://www.epa.gov/coalbed/networkcontacts.html
Government Groups
Ministry of Energy and Coal Industry of Ukraine
Project approval
Donetsk Regional State Administration (DRSA]
State Service of Mining Supervision and Industrial Safety of
Ukraine
Universities, Research
Donetsk Coal Research Institute
Technical assistance
Establishments
Ukrainian Natural Gas Research Institute
Dnipropetrovsk Mining University of Ukraine
National Academy of Sciences
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34.1.3 Status of Coal and the Coal Mining Industry
Ukraine experienced a steep decline in coal production from 165 million raw tonnes per annum
(Mta) in 1990 to 70.5 Mta in 1996. Production stabilized after 1996, fluctuating between 70 and 80
Mta, although 2012 production increased to 88.2 Mt (BP, 2013), and the Ministry of Energy and
Coal Industry of Ukraine reports that raw coal production totaled 83.7 million metric tonnes in
2013 (Yashchenko, 2014). Almost two-thirds of the production is steam coal and the remainder is
coking coal (IEA, 2013). The increase in coal production is due to the closure of uneconomic mines
that came about from the Ukraine mine closure plan in 1997 and the privatization of formerly state-
owned mines. Privatization has led to significant investment in the privatized mines and a broader
move to market standards where transactions occur with creditworthy customers and payments
are more regular. With reserves sufficient to last for over 350 years at current production levels,
the coal mining industry should remain stable for the foreseeable future.
Private companies operated 70 percent of Ukraine coal production capacity at the end of 2013
(Yashchenko, 2014). By year end 2013, there were 143 coal mines operating in Ukraine, a decrease
of 12 from 2012. Data on ownership is not available for 2013, but in 2012 there were 45 privately
owned mines in Ukraine, up from 29 in 2010. The number of state-owned mines declined from 127
in 2010 to 110 in 2012 (Yashchenko, 2013). These changes are in line with the Energy Strategy of
Ukraine, which plans for further decrease of state ownership of coal mines (Yashchenko, 2013). The
Cabinet of Ministers approved privatization of 66 coal mines between 2012 and 2014, including
noted coal associations such as Makeevugol and Luganskugol (MECI, 2012).
Most of the mines in Ukraine are underground mines (Table 34-3) producing bituminous coal.
Anthracite accounts for 11 percent of coal production (IEA, 2013). Ninety-five percent of the active
mines in 2012 were in the Donetsk basin, while the remaining five percent were found in the Lviv-
Volyn basin (MECI, 2012; Yashchenko, 2013).
Table 34-3. Ukraine - Number of Coal Mines by Type
Raw Coal Production
Type of mine
(million tonnes)
Number of mines
Underground (active] mines - total (2013]
83.7
143
Surface (active] mines - total (2012]
0.02
3
Sources: PEER (2005]; Yashchenko (2014]; UNFCCC (2014a]
Today, active Ukrainian underground coal mines have an average mining depth of more than 700m
and one out of six mines are at a depth of greater than 1,000m (IEA, 2012). The deepest mine is
1,332m, and some preparatory work is being undertaken at a depth of 1,386m (Euracoal, 2013).
Average seam thickness is 1.2m. Approximately 90 percent of mines release significant amounts of
methane. About 60 percent of mines are reported to have possible coal dust outbursts, while 22
percent of mines are susceptible to possible coal spontaneous combustion (IEA, 2012).
In 2013,133 out of 143 mines or 93 percent of operating mines were considered gassy, and these
mines produced 70 percent of Ukraine's coal in 2013. Thirty of the mines have absolute methane
emissions between 0.5 and 12 cubic meters per minute (m3/m) and the other 103 have emissions
greater than 12 m3/m (Yashchenko, 2014). At some mines, the natural gas content can exceed 35
cubic meters per tonne of dry ash-free coal (PEER, 2002).
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34.2 Overview of CMM Emissions and Development
The Global Methane Initiative (GMI) International CMM Projects Database identifies 31 CMM
projects in Ukraine, involving 13 active, underground mines and one surface mine in the Donbass,
and three active underground mines, one abandoned mine and one active surface mine in the
Lugansk basin. The methane is used for boiler fuel in 11 of these projects, for combined heat and
power in eight, flaring in seven, and for industrial use, power generation, pipeline injection,
heating/cooling and vehicle fuel and flaring in the remaining five projects (GMI, 2014a). GMI's 2010
Projects Database lists a further eight projects that were publicized through posters at the 2007
and 2010 GMI Expos at https:/ /www.global methane.org/activities /indexact2.aspx?sector=coal#
(GMI, 2014b).
Ukraine has registered more CMM projects under the Joint Implementation (JI) mechanism of the
Kyoto Protocol than any other country. Ukraine also has a very good track record with respect to
generating Emission Reduction Units (ERUs) under the JI. Thirteen of the 16 projects in the pipeline
have been registered with the remaining three still in the determination stage. Of the 13 registered
projects, 12 have been issued ERUs, an extremely high success rate compared with other countries.
Total ERUs issued through 2012 equal 23 million tonnes carbon dioxide equivalent (MmtCChe)
(UNEPRIS0 Center, 2014).
One of the latest CMM degasification and utilization projects at the Sukhodolska-Vostochnaya coal
mine in Krasnodon was announced by Green Gas International in February, 2010. The mine
currently operates at depths up to 1,000 meters and the project plans to enhance the gas drainage
system to provide a steady source of methane for heat and power production for use at the mine.
(Green Gas, 2010). In January 2014, GGI and Krasnodonugol announced they were entering the next
phase of the project to generate heat and power. In addition, DTEK has announced plans to develop
a 3 MW power project at the Komsomolets Donbassa mine where it has already used CMM in two
flares and also uses CMM in boilers for hot water and steam in winter.
34.2.1 CMM Emissions from Operating Mines
Ukraine is considered to be the world's fourth largest emitter of methane emissions from coal
mining activities (USEPA, 2012), even though emissions have been significantly reduced by mine
closures and reduced coal production (see Table 34-4). The data in this table may vary from the
USEPA data presented in the Executive Summary due to differences in inventory methodology and
rounding.
Table 34-4. Ukraine's CMM Emissions (million cubic meters)
Emission Category
2000
2005
2010
2015
(projected)
Underground mining - active
1692.55
1315.73
1191.32
Underground - post-mining
156.32
135.45
133.89
Surface mining - active
1.42
0.41
.01
Surface - post-mining
0.20
0.06
0.00
Abandoned Mines
7.86
4.65
2.80
Total Emissions
1850.49
1451.65
1325.21
2096.06*
Additional Recovered and Flared
70.36
55.02
127.61
Sources: UNFCCC (2014a]; *USEPA (2012]
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In August 2005, the U.S. Trade and Development Agency (USTDA) awarded a $585,570 grant to the
Donetsk Regional State Administration to conduct a feasibility study on commercial development of
coal bed methane (CBM) and CMM in the Donbass region. The project aimed to increase the
domestic supply of natural gas, increase mine safety, and improve local environmental quality. The
analysis focused on developing the best technical and economic approach for methane drainage at
mines, evaluating the technical and economic merits of producing CMM, and assessing the most
likely markets and infrastructure required to utilize CMM and CBM (USTDA, 2005). The study
focused on two mines, Bazhanov and South Donbass No.3, which were found to have average CMM
emissions of 9.9 and 8.8 million m3 per year respectively. Economic analysis suggests these
emissions are sufficient to power on-site electricity generators with capacities of 1.7MW and 3.3
MW. The Bazhanov mine already utilizes 5.5 million m3 per year of drained methane in onsite
boilers for heating purposes (USTDA, 2008). The two mines were publicized in posters at the 2010
GMI Expo. The projects are currently searching for further financial and technical assistance to
move their CMM projects to the development stage (GMI, 2014b).
The U.S. EPA supported two recent pre-feasibility studies in Ukraine:
¦ Komsomolets Donbassa Mine - The pre-feasibility study projects gas production from
surface pre-mine drainage and gob vent boreholes, analyzes end-use options and assess the
feasibility of various combinations of gas drainage and utilization technologies. The study
concludes that gob vent boreholes combined with power generation can be economic at the
mine.
¦ Zhdanovskaya Mine - There is large potential to reduce methane emissions at
Zhdanovskaya Mine. The study identified two main, technically-viable options for the
optimal utilization of CMM at the mine: (1) electricity generation by installing a gas-engine
generator to produce power for mine use or export to the public grid; and (2) on-site heat
generation from existing mine boilers which presently consume coal, but can be switched to
use CMM.
34.2.2 CMM Emissions from Abandoned Coal Mines
Hundreds of mines have been closed and abandoned in Ukraine since the inception of its coal
industry. Between 1990 and 2013,143 underground mines were abandoned or were in the process
of closure in a major effort by the state to increase mine efficiency, improve mine safety, and
achieve mine profitability (UNFCCC, 2007; Yashchenko, 2013 & 2014). The mine closure rate has
declined in recent years, as the government attempts to bolster national coal production with
technical upgrades at coal mines rather than closure, while also investigating opening some
previously closed mines (Euracoal, 2008). Due to high groundwater levels, it has been reported by
experts in Ukraine that all abandoned mines flood limiting their capacity to be sources of AMM
projects. Pumping flood water out of the mine has been considered but it is extremely energy and
cost intensive. There may also be environmental concerns with discharge of mine water onto
surface soils or surface water bodies. The Government of Ukraine has established a state-owned
company responsible for closing mines and managing the abandoned mines. The company is called
Ukruglerestrukturizatsia (UDKR). The Donetsk Regional State Administration and UDKR have
expressed interest in developing policies and procedures to prepare operating mines for future
AMM activity upon closure.
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34.2.3 CBM from Virgin Coal Seams
Ukraine's CBM resource is approximately 1.7 trillion cubic meters (ARI, 1992; Thomas, 2002). The
USTDA grant awarded to the Donetsk Regional State Administration in 2005 aimed to assess the
most likely markets and infrastructure required to utilize virgin CBM (USTDA, 2005). The study
looked at the feasibility of drilling CBM wells in the areas surrounding the Bazahnov and South
Donbass No. 3 mines. Multiple seams of coal are present in a section 500-900 m deep and with gas
contents ranging from 15-20 m3 per tonne. Markets for potential produced gas include direct
pipeline sales and compressed natural gas (CNG) projects (USTDA, 2008).
EuroGas Inc. was the first foreign company to drill for CBM in 1998, but has had no commercial
success. In 2008, they formed a joint venture with one of Ukraine's largest industrial holding
groups, to explore and develop CBM leases in east and west Ukraine, although this project is still in
the planning stages (EuroGas, 2010).
Ukraine has very limited R&D resources available for pursuing CMM or CBM research, namely lack
of technology for and experience in applying hydro-fracturing to stimulate CBM production. A more
favorable investment climate along with clarity on CBM ownership issues are needed before more
foreign companies are likely to commit to CBM projects in Ukraine.
34.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Ukraine has signed and ratified both the United Nations Framework Convention on Climate Change
(UNFCCC) and the Kyoto Protocol (see Table 34-5). As an Annex I country, Ukraine is eligible to
host Joint Implementation (JI) projects. Emission Reduction Units (ERUs) are the commodity
generated by JI projects and one ERU is equivalent to one tonne of CO2. ERU's are recognized offsets
in the European Emissions Trading Scheme. The Kyoto Protocol ended on 31 December 2013, and
there is no successor agreement; however, the EU ETS continues to operate. To be eligible to be
traded in the EU ETS, ERUs must have been generated prior to 1 January 2013, and issued by the
UNFCCC's Clean Development Mechanism Executive Board before 31 March 2015.
Table 34-5. Ukraine's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 11,1992
May 13,1997
Kyoto Protocol
March 15,1999
April 12,2004
Source: UNFCCC (2014b]
Per the Kyoto Protocol, Ukraine must stabilize greenhouse gas emissions at the 1990 level of 55.4
MmtC02e. Emission reductions since 1990 due largely to coal mine closures have resulted in
current estimated emissions of 17.1 MmtCC^e (UNFCCC, 2014a).
As of 2013, degasification is performed at 37 coal mines in Ukraine that account for 41 percent of
the country's total coal production. Of the 37 mines degassing 20 are private mines with annual
production of 28.6 Mmt or about one-third of total coal production. The remaining 17 are state-
owned mines generating 10 Mta. The number of mines using degasification was steady between
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2010 and 2012 at 41 to 42 mines but declined in 2013 to 37 mines. The decrease was due to a large
decrease in the number of state-owned mines using methane degasification, while privately owned
mines employing degasification has actually been growing since 2010 (Yashchenko, 2014).
Coal mines are prohibited from using CMM if the CH4 content is below 25 percent, which was the
case at 20 of the mines in 2012. The other 15 mines had CH4 concentrations above 25 percent in
their drainage systems, but only five of those have concentrations above 35 percent (Yashchenko,
2013).
In 2013, Ukraine mines recovered 370 Mm3 in their degasification systems, the same amount as
produced by degasification systems in 2012. The Ministry of Energy and Coal Industry reports
utilization of 34 percent of the drained gas in 2013, a decrease from 43 percent in 2012. The
Government's goal is to increase methane drainage to 450 Mm3 annually while doubling utilization
to 250 Mm3 per year (Yashchenko, 2014).
34.3.1 Market and Infrastructure Factors
In Ukraine, mineral resources and mines are owned by the state. Existing mines are operated under
licenses. While methane in coal is owned by the state, it is assigned to companies, mines, and
individuals. CBM/CMM development is subject to the approval of the Ministry of Energy and Coal
Industry (M2M Workshop - Ukraine, 2005).
Most CMM that is not flared is currently used for basic applications such as boiler firing and mine
air heating, and combined heat and power. There remains significant potential for CMM to fuel
additional power generation in gas or dual-fuel power plants, to supplement supplies for other
residential, commercial, and industrial uses, or to be converted into transportation fuel. In 2011,
Ukraine imported 77 percent of its natural gas requirements (EIA, 2014a) and so the potential
markets for CMM in Ukraine are significant, especially as prices for natural gas increase. The
principal barrier to expanding the use of CMM is poor market access, including the lack of modern
infrastructure to gather and transport methane produced by CMM processes to internal end use
markets and to existing international pipelines that serve foreign markets, mainly Western Europe.
34.3.2 Regulatory Information
The state owns all subsurface resources including coal and gas resources. Private mines lease the
minerals from the State. Forty-five operating coal mines have been privatized, which represent
roughly 71 percent of Ukraine's annual coal production (Yashchenko, 2013 and 2014). Major
private mining companies include DTEK, METINVEST, Donetsk Steel, and Coal Energy SA. The
remaining mines are state owned and are referred to as Joint Stock Holding Companies (Triplett,
2006).
The Government of Ukraine prepared the Updated Energy Strategy of Ukraine to 2030 in 2012,
addressing reform of the coal industry. Target growth is to reach 130 Mta of production by 2030, a
53 percent increase over 2012 levels.
State programs to advance CMM production, have previously relied mainly on private investment.
Government support has taken the form of various tax incentives to attract investment in coal
regions and exempting foreign-manufactured materials and equipment used in CMM development
from Ukraine's value added tax.
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On 22 February 2006, the Ukrainian Cabinet officially approved a setof JI procedures formally
outlining the Federal Government's procedures for consideration, approval, and implementation
for domestic companies such as coal mines to carry out JI projects under Article 6 of the Kyoto
Protocol; several projects have already been submitted under these guidelines.
More recently, Ukraine has undertaken several important policy steps to promote CMM capture and
use.
In 2009, Ukraine's Parliament passed the Law on Gas (Methane) from Coal Beds. The law defines
CMM as a fuel resource and clarifies ownership issues, making it easier for third parties to obtain
licenses to use vented CMM . The law also does not allow new mines to begin operating unless they
brought concentrations of methane down to acceptable levels. In addition, it clarifies that CMM
owners can sell their gas into the natural gas transmission system when the gas meets system
requirements. Finally, the law attempts to support investments projects by offering state
guarantees for protecting investments that aim to improve degasification, providing customs and
tax incentives to businesses engaged in CMM recovery and CMM-based production, granting state
support and guarantees to the producers and suppliers of energy from CMM.
Certain gas emissions, including methane and carbon dioxide, are controlled as a result of the Law
of Ukraine on Protecting the Natural Environment and the Law of Ukraine on Air Protection.
Ukraine has regulated emissions and pollutants by charging an ecological tax since 2009 in which
each company has to turn in ecological tax forms quarterly and pay for their emissions
(Roshchanka and Evans, 2014). The cost of methane emissions is 81.08 Ukraine Hryvnia
(UAH)/tonne, or $9.9/tonne, while the cost of carbon dioxide emissions is 54.05 UAH/tonne, or
$6.6/tonne (Government of Ukraine, 2010).
In June 2009, Ukrainian President Viktor Yushchenko signed important coal mine legislation that
includes a tax exemption for Ukrainian CMM projects. Starting in 2010 and continuing through
January 2020, profits from the production and use of CMM earned by Ukrainian enterprises will no
longer be subject to taxation (the basic charge rate is 16 percent). However, in 2012, the Ukrainian
Parliament amended the tax code, requiring mines to pay subsoil use tax for methane utilization.
This made CMM projects less feasible. For example, DTEK had to suspend its CMM-fired
cogeneration projects.
Due to the coal industry's large role in the economy, not only as an indigenous source of energy but
also for employment, the Government of Ukraine offers significant subsidizes to state-owned coal
enterprises. According to IEA, subsidies in 2009 totaled USD 1.7 billion (IEA, 2012). Private mines
do not receive direct subsidies but may receive other preferential treatment such as favorable loan
terms, low tariffs, or other attractive options.
34.4 Profiles of Individual Mines
Twenty-nine mines have been identified as primary opportunities for CBM/CMM development in
Ukraine. These mines have been profiled in great detail by the Partnership for Energy and
Environmental Reform in its Handbook on Opportunities for Production and Investment in the
Donetsk Basin (PEER, 2001).
Table 34-6 gives more up to date details of one of the profiled mines. Other profiles are available at
the following sources:
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¦ Updated profiles are available on the GMI website, under "Projects" (GMI, 2014b).
https://www.globalmethane.org/activities/indexact2.aspx?sector=coal#
The pre-feasibility studies of the:
¦ Komsomolets Donbassa mine
http://epa.gov/coalbed/docs/KDMineUkraine preFeasibilityStudy2013.pdf
¦ Zhdanovska mine
http://epa.gov/coalbed/docs/Ukraine PreFS CMM Zhdanovskaya%20Mine Tuly%202013.
pdf
¦ The Project Design Documents available on the UNFCCC website for the projects listed in
Table 34-7.
¦ The USEPA Publication Addressing Barriers to CMM Project Development in Ukraine: Four
Coal Mine Profiles http: //epa.gov/coalbed/docs/ukraine cmm profiles may2010.pdf.
¦ U.S. Trade & Development Agency. Feasibility Study for the South Donbass #3 and Bazhanov
Mines. Coal Mine Methane and Coalbed Methane in the Donetsk Region, Ukraine.
http://www.ustda.gov/librarv/reports/ukr 200581025a.pdf
Table 34-6. Profile of Yuzhno-Donbasskaya #3
Yuzhno-Donbasskaya #3 Mine
Mine Status
Active
Mine Owner
Donetskya Vulgina
Energetichna Kompanya
Mining Method
Longwall
Parent Company
State
Depth of Seams
585-940 m
Location
Vugledar, Donetsk
No. of Seams
2 - Cn & Cio
2008 VAM Volume
30.32
Million m3
Seam Thickness
1.5-1.7 m
2008 Drained CH4 Volume
2.9 Mm3
2008 Coal Production
1.2 million tonnes
2008 Utilized CH4 Volume
0
1997
1998
1999
2000
2001
2002
Coal Production
(thousand tonnes/yr)
1019
1053
1224
1273
1569
1510
Methane (million m3/yr]
Emitted from
ventilation systems
15.56
23.70
15.27
12.31
31.23
49.66
Liberated from
drainage systems
2.58
1.00
2.89
2.9*
2.9*
2.9*
Total Methane
Emissions
18.14
24.70
18.16
15.21
34.13
52.56
2003
2004
2005
2006
2007
2008
Coal Production
(thousand tonnes/yr)
1289
1190
1266
1200*
1200*
1200*
Methane (million m3/yr]
Emitted from
ventilation systems
46.97
53.75
47.97
35.00
32.90
30.32
Liberated from
2.9*
2.9*
2.9*
2.9*
2.9*
2.9*
drainage systems
Total Methane
Emissions
49.87
56.65
50.87
37.90
35.80
33.12
* Estimated
Source: GMI (2014b]
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Table 34-7. List of Ukraine Joint Implementation Projects
Name of Project
¦ Utilization of CMM at the Coal Mine named after A.F. Zasyadko
¦ CMM utilization on the coal mine Shcheglovskaya-Glubokaya of the State Holding Joint-Stock Company GOAO
Shakhtoupravlenye Donbass
¦ CMM utilization on the Coal Mine Na 22 "Kommunarskaya" of the State Holding Joint-Stock Company GOAO
Shakhtoupravlenye Donbass
¦ CMM utilization on the Joint Stock Company named Komsomolets Donbassa Coal Mine of DTEK (Donbasskaya
Toplivnaya Energeticheskaya Kompanya]
¦ CMM utilization on the Joint Stock Company "Coal Company Krasnoarmeyskaya Zapadnaya Na 1 Mine"
¦ CMM utilization for heat generation and flaring - Pivdennodonbaska No 3
¦ Utilization of CMM at the Coal Mine Sukhodilska-Skhidna
¦ CMM Capture and Utilization at Samsonivska-Zakhidna Mine
¦ Abandoned CMM Utilization at NPK-Kontakt Ltd.
¦ Utilization of CMM at the Coal Mine Named After M. P. Barakov of JSC Krasnodoncoal
¦ Power Generation from the CMM at the Sukhodolskaya - Vostochnaya Mine
¦ Utilization of CMM at the SE Makiyiwuhillya
¦ CMM utilization on the coal mine Molodogvardeyskaya of the Joint Stock Company Krasnodonugol
¦ Nykanor-Nova Coalmine Methane Utilization Project
¦ CMM capture and utilization at Holodnaya Balka mine in Donetsk Oblast
¦ CMM utilization on the coal mine Molodogvardeyskaya of the Joint Stock Company Krasnodonugol
¦ Nykanor-Nova Coalmine Methane Utilization Project
¦ CMM capture and utilization at Holodnaya Balka mine in Donetsk Oblast
Source: UNEP RIS0E Center (2014]
34.5 References
ARI (1992): Hunt for Quality Basins Goes Abroad, Velio A. Kuuskraa and Jonathan R. Kelafant, in Oil & Gas
Journal, 5 October 1992.
BP (2013): Statistical Review of World Energy, June 2013.
http://www.bp.com/content/dam/bp/pdf/statistical-
review/statistical review of world energy 2013.pdf
Cragg (2013): 'The Coal Mining Racket Threatening Ukraine's Economy," BBC World News, Gulliver Cragg, 23
April 2013. http:// www.bbc.com/ news / world-europe-2 2170976
EIA (2014a): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed April 2014. http: //www.eia.gov/cfapps /ipdbproiect/IEDIndex3.cfm.
EIA (2014b): Ukraine Country Analysis Brief, U.S. Energy Information Administration, Washington, DC, March
2014. http://www.eia.gov/countries/country-data.cfm?fips=up
Euracoal (2008): Ukraine - European Association for Coal and Lignite. Brussels, Belgium, 2008.
Euracoal (2013): Ukraine, European Association for Coal and Lignite, Brussels, Belgium, 2013.
http://www.euracoal.org/pages/layoutl sp.php?idpage=269
EuroGas (2010): CBM & Natural Gas Joint Venture Ukraine, website accessed July 2010.
http: IIwww.eurogasinc.com /i oint-venture-ukraine 8 5 .html
GMI (2014a): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed
September 2014. https: //www.glohalmethane.org/coal-mines/cmm/index.aspx
GMI (2014b): Projects in Ukraine, Global Methane Initiative, accessed September 2014.
https://www.glohalmethane.org/activities/indexact2.aspx?sector=coal
Y ' Global
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UKRAINE
Golovnev (2013): "Who is Behind the Crisis of Overproduction in Ukrainian Coal Sector," Sergey Golovnev,
Forbes Ukraine, 27 May 2013. http: //forbes.ua/magazine/forbes/1351902-kak-ustroen-biznes-na-
kopankah
Green Gas (2010): "Green Gas to provide new coal mine gas degasification and utilization system in Ukraine
to eliminate methane emissions," printed 2 February 2010, retrieved June 2010.
http://www.greengas.net/output/NewsPage.aspx?PageID=536
IEA (2012): Ukraine 2012: Energy Policies Beyond IEA Countries, Publication 978-92-64-17151-0,
OECD/International Energy Agency, Paris, France, 2012.
IEA (2013): Energy Statistics - Coal and Peat in Ukraine in 2007 and 2011, International Energy Agency, Paris
France, website accessed 12 May 2014.
M2M-Ukraine (2005): Ukraine Country Profile - Methane to Markets Partnership, July 2005.
M2M Workshop - Ukraine (2005): Prospects for CBM (CMM) Industry Development in Ukraine, V. Lukinov,
National Academy of Sciences of Ukraine, presented at the Methane to Markets Regional Workshop, 2
December 2005, Beijing, China.
MECI (2012): Information on the State-Owned Coal Mining Industry to be privatized in 2012-2014,
Respectively to the Cabinet Ministers of Ukraine 19-09-2012, Ministry of Energy and Coal Industry of
Ukraine, Kiev, Ukraine, 19 September 2012.
PEER (2001): Coal Mine Methane in Ukraine: Opportunities for Production and Investment in the Donetsk Coal
Basin, Partnership for Energy and Environmental Reform, Triplett, Jerry, Alexander Filippov, and
Alexander Pisarenko, January 2001. http: //www.epa.gov/cmop/docs/ukraine handhook.pdf
PEER (2002): Coal Mine Methane Recovery in Ukraine: Inventory of Coal Mine Methane Emissions from Ukraine
1990 - 2001, Partnership for Energy and Environmental Reform, Triplett, Jerry, Alexander Filippov, and
Alexander Pisarenko, 2002. www.epa.gov/cmop/docs/inventory2002.pdf
PEER (2005): Ukraine Energy Facts - 2005, Partnership for Energy and Environmental Reform, 2005.
Roshchanka and Evans (2014): Incentives for methane mitigation and energy-efficiency improvements in the
case of Ukraine's natural gas transmission system, Earth's Future, 2, 321-330, Roshchanka, Volha and
Meredydd Evans, 24 June 2014. http://onlinelibrary.wiley.eom/doi/l 0.1002/2013EF000204/pdf
Sachsenhofera (2002): The Donets Basin (Ukraine/Russia): coalification and thermal history, R. F.
Sachsenhofera, et al., International Journal of Coal Geology, Volume 49, Issue 1, pages 33-55, February
2002.
Thomas (2002): Coal Geology, Larry Thomas, John Wiley and Sons, 2002.
Triplett (2006): Personal communications with Jerry Triplett, Partnership for Energy and Environmental
Reform, 13 June 2006.
UNEP RIS0 Center (2014). Joint Implementation Pipeline, United Nations Environment Programme, 1 May
2014. http://cdmpipeline.org
UNFCCC (2014a): Ukraine National Inventory Report 2014, Annex I Party GHG Inventory Submission, United
Nations Framework Convention on Climate Change, 12 April 2014.
http: / /unfccc.int/national reports /annex i ghg inventories/national inventories submissions/items/81
08.php (Common Reporting Format, 1990-2012, Tables l.B.l).
UNFCCC (2014b): Ratification Status - Ukraine, United Nations Framework Convention on Climate Change,
accessed September 2014. http: //maindh.unfccc.int/puhlic/country.pl?country=UA
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
A
Methane Stive CMM Country Profiles 313
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USTDA (2005): USTDA Awards Grant For Coal Bed/Coal Mine Methane Project in Ukraine, U.S. Trade and
Development Agency Press Release, 31 August 2005.
http://www.ustda.gOv/USTDA/Press%20Release%20Archive/Press%20Releases/2005/Ukraine/Augus
t31 05Ukraine.htm.
USTDA (2008): Coal Mine Methane and Coalbed Methane Development in the Donetsk Region, Ukraine, U.S.
Trade and Development Association, Arlington, Virginia, USA, May 2008.
Yashchenko (2013): State Policy of Ukraine in Capturing and Utilizing Coal Mine Methane, presentation to the
18th Session of the Coal Mine Technical Subcommittee of the Global Methane Initiative, November 2013.
http://www.unece.org/fileadmin/DAM/energv/se/pp/coal/cmm/8cmm nov2013/7 Ukraine e.pdf
Yashchenko (2014): State and Directions of Development of Production and Use of Mine Gas-Methane,
presentation to the 20th Session of the Coal Mine Technical Subcommittee of the Global Methane
Initiative, October 2014.
http://www.unece.org/fileadmin/DAM/energy/se/pp/coal/cmm/9cmm gmi ws/7.5 UKRAINE.pdf
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35 United Kingdom
35.1 Summary of Coal Industry
35.1.1 Role of Coal in the United Kingdom
Coal use in the United Kingdom (UK) has fallen by about one quarter in recent years due to a
combination of relatively low natural gas prices and higher carbon dioxide (CO2) emission
allowance prices (EURACOAL, 2014). Coal still accounts for 19.9 percent of the UK's total energy
needs (DECC, 2014a). The bulk of coal use goes toward power generation, supplying approximately
36 percent of UK's power needs (EIA, 2014a). UK is the seventh largest coal importer worldwide
(WCI, 2014). Its primary importer is Russia, with Colombia and the United States contributing
significant portions (EIA, 2014a).
Coal production in the UK has declined steadily and dramatically since the early 1990s, falling to its
record low of 16.3 million tonnes (Mmt) in 2012, while holding proved reserves of 228 Mmt (Table
35-1; EIA, 2014b). Coal is located in a number of regions in the UK, as shown in Table 35-2 and
Figure 35-1. A more detailed map is provided by the Confederation of UK Coal Producers
(UKCoalPro, nda).
Table 35-1. United Kingdom's Coal Reserves and Production
Indicator
Anthracite &
Bituminous
(million tonnes)
Sub-
bituminous
& Lignite
(million tonnes)
Total
(million tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves
228
0
228
45 (0.03%]
(2011]
Annual Coal Production (2012]
16.3
0
16.3
24 (0.2%]
Source: EIA (2014b]
Table 35-2. United Kingdom's Coal Fields
Basin / Location
Coal Field
Midland Valley, Southern Scotland
¦ Fife
¦ Ayrshire
¦ Central
¦ Douglas
¦ Lothians
¦ Sanquhar
¦ Firth of Forth
¦ Machrihanish
Northern England, between the Southern
¦ Canonbie
¦ Northeastern (Durham]
Uplands and Craven
¦ Cumberland
¦ Ballycastle
¦ Northwest Northumberland ¦ Ingleton
¦ Midgeholme
East Pennine Basin
¦ Nottinghamshire
¦ East Lincolnshire
Central England, north of the Wales
¦ Yorkshire
¦ Scarborough
^ ,
fethaneinitiative CMM Country Profiles 315
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Table 35-2. United Kingdom's Coal Fields
Basin / Location
Coal Field
West Pennine Basin
Central England, north of the Wales
¦ Lancashire ¦
¦ Chester Plains ¦
¦ Anglesey ¦
¦ North and South Staffordshire ¦
¦ South Derbyshire ¦
¦ Leicestershire ¦
¦ Warwickshire ¦
Shropshire
Cannock
Coalbrookdale
Wyre Forest
Osfordshire
Flintshire
Denbighshire
Southern England, between the Wales-London-
Brabant Massif and Variscan Tectonic Front
¦ Pembrokeshire
Southern England, between the Wales
¦ South Wales
¦ Forest of Dean
¦ Bristol
¦
¦
Somerset (Nailsea and
Avonmouth],
Berkshire
¦ Kent
Source: Schwochow (1997)
Figure 35-1. United Kingdom's Coal Fields
7 J
Sf /
n/aku, C/oc/^annan coalfield
yO >^(7 Sfij
Ayrshire /§£
<
J y Northumberland
^ /) CumCS ^Acoalfietd
coal/iW
Burn 1$ jfiKtVennrne coalfield
coalfield \
Souihlansg^m ^
coalf\d&~j \
/
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UNITED KINGDOM
35.1.2 Stakeholders
Table 35-3 identifies potential key stakeholders in the UK's coal mine methane (CMM) development
industry.
Table 35-3. Key Stakeholders in the United Kingdom's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining companies
ATH Resources Limited
Project hosts
Celtic Energy
Energybuild
Goitre Tower Anthracite
H J Banks & Company Limited
H R M Resources Limited
Hall Construction Services Ltd
Hargreaves Services
J D Flack & Sons Ltd
Land Engineering Services Ltd
Maltby Colliery Ltd
Powerfuel Pic
Recycoal Ltd
Scottish Coal Company Ltd
Scottish Resources Group
The Kier Group - Kier Mining
The Miller Group - Miller Argent (South Wales] Limited
UK Coal Production Limited
Equipment manufacturers
MAN B&W Diesel
Methane treatment and
Hamworthy Combustion Engineering
utilization equipment
ALSTOM Power UK
Peter Brotherhood
EDECO Petroleum Services
Developers
Abmec
Project opportunity
Alkane Energy pic
identification and
Arevon Energy Ltd
planning
Clarke Energy Ltd.
Coalbed Methane Ltd.
Coastal Oil and Gas Ltd.
Db Schenker
DEUTZ UK Ltd.
Edinburgh Oil & Gas pic
Energy Developments (UK] Ltd.
Evergreen Resources UK Ltd.
Federation Of Independent Mines
First Energy Ltd.
GeoMetUKLtd.
Harworth Power Generation Ltd.
HEL-East Ltd
Mines Rescue Service Ltd
Octagon Energy Ltd.
R J Blasting (Scotland] Ltd
Renewable Power Systems
Rolls-Royce Power Ventures Ltd.
Scottish and Southern Energy pic
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Table 35-3. Key Stakeholders in the United Kingdom's CMM Industry
Stakeholder Category
Stakeholder
Role
Terex Distribution Ltd
The Solid Fuel Association
UK Coal Mining Ltd.
UK Gas Ltd.
Warwick Energy Ltd.
Workington Gas & Light Ltd.
See http://www.epa.gov/coalbed/networkcontacts.html
Engineering, consultancy.
ACA Howe International Ltd.
Technical assistance
and related services
AEA Technology Environment
Cadogan Consultants Ltd.
Celtic Energy Ltd.
EDECO Petroleum Services Ltd.
Farley Engineering Ltd.
HEL-East Ltd
International Mining Consultants
Knight Energy Services Ltd.
PR Marriott Drilling Ltd.
Pipeline Services Ltd.
Reeves Wireline Services Ltd.
Schlumberger Oilfield Services Ltd.
Scientific Analysis Ltd.
StrataGas pic
Wardell Armstrong
WS Atkins Consultants Ltd.
See http://www.epa.gov/coalbed/networkcontacts.html
Universities, Research
British Geological Survey
Technical assistance
Establishments
Cranfield University
Imperial College of Science, Technology, and Medicine
(ICSTM]
Loughborough University
University of Cardiff
University of Nottingham
Regulatory Agencies and
UK Coal Authority
Regulation of methane
other Government Groups
UK Department for Business, Innovation and Skills (BIS]
Department of Energy and Climate Change
rights
Other
European CO2 Network
CoalPro, Confederation of UK Coal Producers
The Association of Coal Mine Methane Operators
(ACMMO] (defunct]
Source: UKCoalPro (ndb); BERR/DTI (2001a]; UK Nat Stats (nd]
There have been several pilot drilling schemes in the UK during the last few years but as of October
2010 there is only limited commercial production of coal bed methane (CBM) and this is being used
to generate electricity rather than feeding the national gas distribution network. However,
companies are now utilizing directional drilling techniques from the oil industry to try and make
the exploitation of CBM a viable prospect in the UK (Coal Authority, 2014). Table 35-4 lists current
licenses or agreements for CBM sites.
<
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Table 35-4. United Kingdom's Current CBM Licenses/Agreements
Licensee
Name
Authority
Alkane Energy UK Ltd.
Glasshoughton Methane
Wakefield
Old Mill Lane Industrial Estate
Nottinghamshire
PPG Industries Site
Wigan
Rexam Glassworks Site
Barnsley
Coal Bed Methane Ltd.
Arns Farm Development
Clackmannanshire
River Forth Valley
Fife
Evergreen Resources (UK]
Bersham (South Dee]
Wrexham
Ltd.
Cronton
Knowsley
Halewood
Knowsley
Knowle Basin
Solihul
Mersey Sealand
Cheshire
Mersey Sealand Supplemental
Flintshire
North Ouse
York
Rhuddlan No. 1 Borehole
Denbighshire
South Dee
Wrexham
South Staffs
Staffordshire
Vale of Clwyd
Denbighshire
West Lanes
Cheshire
Nexen
Doe Green
NA
Potteries
NA
Octagon (CBM] Ltd.
Old Boston
St. Helens
Taff Merthyr - Penallta Project
Caerphilly
35.1.3 Status of Coal and the Coal Mining Industry
Coal production in the UK is declining because of falling consumption, relatively cheap natural gas
that competes with coal for power generation, and a surge of low-cost imports (EIA, 2014a). UK's
production shrunk roughly 40 percent over the last decade (DECC, 2013a).
Table 35-5. UK's Recent Coal Mine Statistics (2012)
Type of Mine
Coal Production
(million tonnes)
Number of Mines
Underground (active] mines - total
6.2 (2012]
10
Surface (active] mines - total
10.1(2012]
34
Source: (DECC, 2013b]
The UK coal mining industry is private, but subsidized by the government's Coal Investment Aid
program that was launched in June 2003. As of 2006, UK's Department of Energy and Climate
Change (DECC) reported that £162 million had been paid outto 26 different organizations (DECC,
2006).
Tables 35-6 and 35-7 provide information on major operating coal mines in the UK as of 2012.
<
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Table 35-6. UK's Major Underground Mines in Production as of 2012
Licensee Site Name Location
Ayle Colliery Company Ltd
Ayle Colliery
Northumberland
Eckington Colliery Partnerships
Eckington Colliery
Derbyshire
Grimebridge Colliery Company Ltd
Hill Top Colliery
Lancashire
Maltby Colliery Ltd
Maltby Colliery
Rotherham
Hatfield Colliery Ltd
Hatfield Colliery
Doncaster
RayAshly, Richard Daniels and Neil Jones
Monument Colliery
Gloucestershire
UK Coal Operations Ltd
Daw Mill Colliery
Warwickshire
Kellingley Colliery
North Yorkshire
Thoresby Colliery
Nottinghamshire
Unity Mine Ltd
Unity Mine
Neath Port Talbot
Source: DECC (2013b]
Table 35-7. UK's Surface Mines in Production as of 2012
Licensee
Site Name
Location
Aardvark TMC Ltd
Glenmuckloch
Dumfries & Galloway
(trading as ATH Resources]
Glenmuckloch Samsiston Area
Dumfries & Galloway
Laigh Glenmuir Site
East Ayrshire
Muir Dean
Fife
Netherton
East Ayrshire
Benhar Developments Ltd
Mossband Farm Quarry
North Lanarkshire
Bryn Bach Coal Ltd
Glan Lash
Carmarthenshire
Celtic Energy Ltd
East Pit
Neath Port Talbot
Nant Helen
Powys
Selar
Neath Port Talbot
Energybuild Ltd
Nant-y-Mynydd Site
Neath Port Talbot
H J Banks & Company Ltd
Brenkley Lane
Newcastle upon Tyne
Shotton
Northumberland
Hall Construction Services Ltd
Earlseat
Fife
Wilsontown
South Lanarkshire
Kier Minerals Ltd
Greenburn Project
East Ayrshire
Land Engineering Services Ltd
Comrie Colliery Site
Fife
Miller Argent (South Wales] Ltd
Ffos-y-Fran Land Reclamation
Merthyr Tydfil
Scheme
Newcastle Science Central LLP
Science Central
Newcastle upon Tyne
The Scottish Coal Company Ltd
Blair House
Fife
Broken Cross
South Lanarkshire
Dalfad
East Ayrshire
Dunstonhill
East Ayrshire
House of Water
East Ayrshire
Mainshill
South Lanarkshire
Spireslack Complex (Airdsgreen]
East Ayrshire
StNinians Fife
<
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Table 35-7. UK's Surface Mines in Production as of 2012
Licensee
Site Name
Location
Tower Regeneration Ltd
UK Coal Mining Ltd
Tower Colliery Surface Mining Site
Butterwell Disposal Point
Huntington Lane
Lodge House
Minorca
Park Wall North
Potland Burn
Rhondaa Cyon Taff
Northumberland
Telford & Wrekin
Derbyshire
Leicestershire
Durham
Northumberland
Source: DECC (2013b]
35.2 Overview of CMM Emissions and Development
Potential
The Global Methane Initiative (GMI) International CMM Projects Database currently identifies 46
projects in the United Kingdom (GMI, 2014). Of these 46, 23 are in place in abandoned mines,
another 23 are located at active underground mines, and the remaining project is in place at an
active surface mine. Of the 46 projects, 26 are for power generation, nine involve flaring five use
methane for boiler fuel, two involve heating and cooling two are for industrial use, and two destroy
ventilation air methane VAM). Updates on future CMM projects in the UK can be found at
https://www.globalmethane.org/coal-mines/cmm/index.aspx. There are no active CMM flaring
projects or VAM projects operating - all were decommissioned as there are no incentives in the UK
for CMM or VAM destruction following the end of the UK ETS in 2005.
Figure 35-2 depicts coal methane reserves in the UK.
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Figure 35-2, United Kingdom's Coal Methane Resources
Source: BGS (2006)
35.2.1 CMM Emissions from Operating Mines
Methane emissions in the United Kingdom were estimated at 489.5 million cubic meters (m3) in
2000, but are expected to decrease by nearly two-thirds to 183.5 million m3 by 2015, and then
anticipated to decrease slightly more to 176.5 million m3 by 2030 (see Table 35-8). As permeability
is low, mines always use post drainage methods for extraction of CMM, resulting in CMM quality in
the range of 25 to 60 percent methane.
Table 35-8. United Kingdom's CMM Emissions (million cubic meters)
Emissions
2000
2005
2010
2015
(projected]
Total CHU Emitted
489.5
285.7
191.2
183.5
Source: USEPA(2012)
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35.2.2 CMM Emissions from Abandoned Coal Mines
There are more than 900 former deep mines in the UK, which offer differing degrees of potential for
exploitation of methane. Projects can be developed using the existing mine shafts, where these
remain open, or by drilling from the surface into the abandoned workings (Coal Authority, 2014). In
2012, the country produced and consumed 703 GWh of CMM, down from 775 GWh in 2009 (DECC,
2013c). It is estimated that 31,000 tonnes of methane have been recovered and used annually from
abandoned mines (BERR/DTI, 2004b). Table 35-9 identifies abandoned mine methane (AMM)
projects in the UK.
Table 35-9. United Kingdom's AMM Projects
Stakeholder
Site
Extracted
Methane
Flow
(liter per
second)
Project
Operating
Dates
Use of
Methane
(type)
Electric
Generatio
n
(MW)
Global
Warming
Potential
Avoided
(tonnes
C02e)
Alkane Energy Pic.
Bevercotes, North
Nottinghamshire
N/A
2006-
present
N/A
4.05
138,155
Alkane Energy Pic.
Whitwell, North
Derbyshire
N/A
2006-
present
N/A
1.35
46,052
Alkane Energy Pic.
Warsop, North
Nottinghamshire
N/A
2006-
present
N/A
1.35
46,052
Alkane Energy Pic.
Wheldale, West
<•409
a2001-
Electric
4.5 [b10.3]
153,054
Yorkshire
present
generation
(e5.8)
(<•184,000]
Alkane Energy Pic.
Mansfield, North
Nottinghamshire
N/A
pre-2006-
present
N/A
3.7
126,216
Alkane Energy Pic.
Sherwood, North
Nottinghamshire
N/A
pre-2006-
present
N/A
0.66
20,467
eGreen Gas Power
Silverdale, North
200
1999-
Burner tip
d9
90,000
Ltd.
Staffordshire
use and
electric
generation
via
pipeline
eGreen Park Energy
Hickleton, South
Yorkshire
250
a2000-
Electric
generation
3.6 (b5.4)
112,500
cGreen Park Energy
Grimethorpe
Brodsworth
Frickley
Bentley
Houghton Main
N/A
N/A
N/A
4MWe per
site
N/A
eWarwick Energy
Annersley
Bentinck,
Nottinghamshire
140
a2000-
Electric
generation
2.0 (b10.5]
63,000
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UNITED KINGDOM
Table 35-9. United Kingdom's AMM Projects
Extracted
Methane
Flow
(liter per
second)
Global
Stakeholder
Site
Project
Operating
Dates
Use of
Methane
(type)
Electric
Generatio
n
(MW)
Warming
Potential
Avoided
(tonnes
C02e)
Likely Inactive
eAlkane Energy Markham. North 51
Pic. Derbyshire
dAlkane Energy Steetley, North NA
Pic. Nottinghamshire
eAlkane Energy Shirebrook, North 372
Pic. Derbyshire
eAlkane Energy Monk Bretton, 33
Pic. West Yorkshire
"1999-
a1999-
a2000-
N/A
Via
pipeline to
boilers
dElectric
generation
Electric
generation
Burner tip
use
d6 (b3]
d3
5.3 (b9.5]
b2 (c5]
23,000
NA
167,400
14,900
Sources cover entire row unless otherwise noted: a] Alkane (2003]; b] BERR/DTI (2004a]; c] Coal Authority (2008];
d] BERR/DTI (2001b]; e] BERR/DTI (2004b]
Figure 35-3 shows net emissions from current and future abandoned mines through 2050.
Figure 35-3. Abandoned Mine Net Emissions
J
n
1
limn.
1990 1995 2000 2005 2010 2015 2020 2030 2040 2050
Source: DECC (2011]
35.2.3 CBM from Virgin Coal Seams
There is a very substantial technical resource of virgin CBM in the UK totaling 2.45 trillion m3. This
would give the UK a 24-year supply under 2008 consumption levels. A 2001 estimate suggested
that only 30 billion m3 would be economically recoverable (BERR/DTI, 2001b). However, given that
the natural gas price in the UK was roughly $2.80 per million Btu in 2001 and the current EU
<
Methane Stive CMM Country Profiles 324
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UNITED KINGDOM
average price has risen to nearly $10 per million Btu, the economic viability for CBM recovery
would be far more favorable now (YCharts, 2014). Recent technological advancements associated
with hydraulic fracturing would also likely further expand recoverable reserves. The highest gas
contents of more than 20 m3 per metric ton can be found in South Wales and is the focus of most
commercial interest (ACMMO, nd).
It is worth noting U.K. coal seams are generally of low permeability; therefore, hydraulic fracking
and directional drilling techniques are likely to be necessary to recover commercial volumes.
35.3 Opportunities and Challenges to Greater CMM Recovery
and Use
The UK is a signatory to both the United Nations Framework Convention on Climate Change
(UNFCCC) and the Kyoto Protocol (Table 35-10). As an Annex I Party to the Kyoto Protocol, its
emissions target is 20 percent below 1990 levels by 2020.
Table 35-10. UK's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 12,1992
December 8,1993
Kyoto Protocol
April 29,1998
May 31,2002
Source: UNFCCC (2014]
The first and second phases (2005-8 and 2008-12, respectively) of the European Union Emissions
Trading Scheme (EU ETS) did not include methane emissions (EC, 2013). The European Union
Commission suggests that the EU ETS needs to be strengthened by taking measures that include
extending the scheme to other gases such as methane (EU, 2007). Just recently, the UK called for
major reforms to improve the EU ETS to tackle climate change, including provisions for additional
activities and gases (DECC, 2014b). The Department of Food and Rural Affairs commissioned a
study exploring CMM and incorporating it into the EU ETS, highlighting its challenges (DECC, 2005).
35.3.1 Market and Infrastructure Factors
British coal mining as a nationalized industry was self-sufficient with regards to research and
development (R&D). Companies downsized when the British government privatized the industry in
the mid-1990s, and emphasis moved away from long-term R&D to more immediate issues. The
industry position has stabilized and some long-term mining-related R&D effort has been taken over
by the universities and private businesses.
New CMM utilization projects have tended to be power generation projects. The technology is
usually standard modules of 1 to 2 MWe internal combustion engines as used in the landfill gas
industry. Landfill gas is a strong and growing sector in the UK with more than l,000MWe installed
capacity in 2012 (DECC, 2013d). Pipeline sales can occur if the infrastructure stays in place from
previous mining enterprises. However, CMM gas is not of sufficient quality to enter the national
natural gas network or even to be upgraded, so the economic viability of pipeline injection is
impossible. In some cases, CBM may be of adequate quality to enter the public distribution system,
but there is no evidence of this (Coal Authority, 2014).
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35.3.2 Regulatory Information
Ownership of the methane in coal rests with the UK government, but it passes to the licensee when
the methane is captured. The rights to the methane gas are regulated by the Department of
Business Enterprise & Regulatory Reform under the Petroleum Act of 1998 (Coal Authority, 2014).
Petroleum Exploration and Development Licenses (PEDLs) are awarded in a series of "rounds," the
most recent being the 13th Landward Licensing round, which accepted applications on February 6,
2008 (Oil and Gas, 2008a). Methane Development Licenses (MDLs) are used primarily for operating
mines. An MDL grants permission to get gas "in the course of operations for making and keeping
safe mines whether or not disused." It grants no exclusive rights, so it can overlap geographically
with one or more PEDLs. MDLs generally cover much smaller areas than PEDLs; typically each
covers one mine, although the Coal Authority holds a license that covers the whole country (Oil and
Gas, 2008b). Coal licensing—and through it, the responsibility for environmental and safety
standards—is handled by the Coal Authority.
The regulatory system for CMM/AMM/CBM ownership is straightforward and works well, subject
to clear delineation of when a mine is open and closed.
CMM currently enjoys an exemption from the UK Climate Change Levy (CCL), a tax on fossil fuels
that has not otherwise been taxed (as is the case with oil) (OPSI, 2003). When used for power
generation, it currently represents an incentive of 4.41 £ per MWe (Customs, 2007a). The CCL was
indexed to inflation starting April 1, 2007 (Customs, 2007b). These savings are shared with the
distribution company that accepts the power into its system; the net benefit to the generator is
likely being closer to 3.0 £ per MWe and is realized by the sale of CCL Certificates. With the
exception of this benefit, power from CMM must compete equally with that from all other
generators in the electricity market This has proved difficult in recent times due to the low price of
electricity on the wholesale market Recently, however, prices have risen, generating increased
interest in CMM projects.
CMM projects are normally developed by private capital. Recent natural gas price volatility has
meant a downturn in activity due to poor projected returns.
CO2 sequestration into the coal seam is often cited as a possible means of making CBM carbon
neutral. CO2 sequestration technology is immature at present and its potential application in the UK
cannot be assessed. However, there are vast areas of coal at depths below 1,200 m that are possibly
too deep for mining and thus may be suitable sites for sequestration.
35.4 Profiles of Individual Mines
The Coal Authority maintains coal mining data in an interactive national database (found at
http: //mapapps2.bgs.ac.uk/coalauthority/home.htmll. and provides information on past and
present coal mining activities in UK.
35.5 References
ACMMO (nd): Association of Coal Mine Methane Operators, not dated.
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Alkane (2003): Sustainable Energy from Abandoned Coal Mines, Alkane Energy Pic., presented to the UNECE
Ad Hoc Group of Experts on Coal in Sustainable Development, 17 November 2003.
http: II www, unece. or g /ie /s e / pp / coal / alkane.pdf
BGS (2006): Coal and Coal Bed Methane, British Geological Survey, United Kingdom, 2006.
BERR/DTI (2001a): Coalbed Methane Extraction and Utilization. Department of Business Enterprise &
Regulatory Reform, United Kingdom, October 2001.
BERR/DTI (2001b): A Review of the Worldwide Status of Coalbed Methane Extraction and Utilisation,
Department of Business Enterprise & Regulatory Reform, United Kingdom, 2001.
BERR/DTI (2004a): Methane Extraction and Utilisation from Abandoned Coal Mines - China/UK Technology
Transfer, Department of Business Enterprise & Regulatory Reform, United Kingdom, February 2004.
BERR/DTI (2004b): Coal Mine Methane - Review of the Mechanisms for Control of Emissions, Department of
Business Enterprise & Regulatory Reform, United Kingdom, February 2004.
Coal Authority (2008): Coal Mine Methane Activity in the UK, The Coal Authority, 2008.
Coal Authority (2014): Methane Associated with Coal Seams, The Coal Authority, website accessed July 2014.
https://www.gov.uk/government/organisations/the-coal-authority
Customs (2007a): Climate Change Levy (CCL) - rates to rise at 1 April 2007, HM Revenue and Customs, United
Kingdom, March 2007.
Customs (2007b): Climate Change Levy (CCL) change to rates, HM Revenue and Customs, United Kingdom,
March 2007.
DECC (2005): Mechanisms For Reducing Methane And HFC Emissions From Four Selected Sectors, Department
of Energy and Climate Change, website accessed July 2010.
DECC (2006): UK Coal Operating Aid Scheme (Ukcoas), Department of Energy and Climate Change, website
accessed July 2010.
DECC (2011): Update of Estimated Methane Emissions from UKAbandoned Coal Mines, Departmentof
Energy and Climate Change, 25 May 2011. http: //uk-
air.defra.gov.uk/assets/documents/reports/cat07/l 107080945 1775-ghg-improvement-proiect-wsp-
reportpdf
DECC (2013a): UK Energy Sector Indicators 2013: Reliable Supplies of Energy Dataset, Department of Energy
and Climate Change, October 2013.
https: //www.gov.uk/government/uploads/system/uploads/attachment data/file/2 54034/ukesi 2013
dataset 2-5 reliable supplies of energv.xls
DECC (2013b): Solid fuels and derived gases (DUKES [Tables] 2.7,2.10, and 2.11), Department of Energy and
Climate Change, 25 July 2013.
https: //www.gov.uk/government/uploads /system /uploads /attachment data/file/65755/DUKES 2013
Chapter 2.pdf
DECC (2013c): Supply and Consumption Of Natural Gas and Colliery Methane (DUKES [Table] 4.2),
Department of Energy and Climate Change, 25 July 2013.
https: / /www.gov.uk/government/uploads /system/uploads /attachment data/file/65800 /DUKES 2013
Chapter 4.pdf
DECC (2013d): Capacity of, and Electricity Generated from Renewable Sources (DUKES [Table] 6.4),
Department of Energy and Climate Change, 28 November 2013.
https: //www.gov.uk/government/uploads /system /uploads /attachment data /file/2 79547/DUKES 201
3 Chapter 6.pdf
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DECC (2014a): Inland consumption of primary fuels and equivalents for energy use -1970 to 2012,
Department of Energy and Climate Change, website accessed July 2014.
http://www.decc.gov.uk/assets / decc/statistics / source/total / dukesl 1 l.xls
DECC(2014b]: UK Calls for Major Changes to EU's "Cap and Trade" Emissions System, Department of Energy
and Climate Change, 16 July 2014. https://www.gov.uk/government/news/uk-calls-for-maior-changes-
to-eus-cap-and-trade-emissions-svstem
EC (2013): Fact Sheet - The EU Emissions Trading System (EU ETS), European Commission, October 2013.
http://ec.europa.eu/clima/puhlications/docs/factsheet ets en.pdf
EIA (2014a): Country Analysis Brief - United Kingdom, U.S. Energy Information Administration, Washington,
DC, last updated 3 June 2014. http://www.eia.gov/countries/cab.cfm?fips=UK
EIA (2014b): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed July 2014. http: IIwww.eia.gov/cfapps /ipdbproi ect /1ED Index3.cfm
EU (2007): Strategy on Climate Change for 2020 and Beyond, European Union, 10 January 2007.
http://europa.eu/legislation summaries/energy/european energy policy/128188 en.htm
EURACOAL (2014): Country Profiles - United Kingdom, European Association for Coal and Lignite, website
accessed July 2014. http://www.euracoal.be/pages/layoutlsp.php?idpage=82
GMI (2014): International Coal Mine Methane Projects Database, Global Methane Initiative, accessed in July
2014. https://www.globalmethane.org/coal-mines/cmm/index.aspx
Oil and Gas (2008a): Oil and Gas Licensing Round, Department for Environment, Food, and Rural Affairs (fmr.
Department of Trade and Industry), 2008.
https://www.og.decc.gov.uk/upstream/licensing/onshore 13th/index.htm
Oil and Gas (2008b): Oil and Gas Licensing Guidance, Department for Environment, Food, and Rural Affairs
(fmr. Department of Trade and Industry), 2008.
https://www.og.decc.gov.uk/upstream/licensing/lictype.htm
OPSI (2003): The Climate Change Levy Regulations 2003, Office of Public Sector Information, United
Kingdom, 9 October 2003. http: //www.opsi.gov.uk/si/si2003/20032633.htm
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
UKCoalPro (nda): Britain's Coalfields, Detailed Map, Confederation of UK Coal Producers, Wakefield, United
Kingdom, website accessed July 2014. http: //www.coalpro.co.uk/documents/UK%20Coalfields.ppt
UKCoalPro (ndb): Members, Confederation of UK Coal Producers, Wakefield, United Kingdom, website
accessed July 2014. http: //www.coalpro.co.uk/members.shtml
UK Nat Stats (nd): Energy Production and Consumption, UK National Statistics Publication Hub, United
Kingdom National Statistics, not dated.
UNFCCC (2014): Ratification Status - United Kingdom of Great Britain and Northern Ireland, United Nations
Framework Convention on Climate Change, website accessed September 2014.
http://maindb.unfccc.int/public/country.pl?countrv=GB
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
WCI (2014): "Coal Statistics, Top Coal Importers," World Coal Institute, website accessed September 2014.
http://www.worldcoal.org/resources/coal-statistics/
YCharts (2014): European Union Natural Gas Import Price, website accessed September 2014.
http://ycharts.com/indicators/europe natural gas price
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36 United States
36.1 Summary of Coal Industry
36.1.1 Role of Coal in the United States
The United States (U.S.) holds the world's largest estimated recoverable reserves of coal (more than
200 years based on current production levels). In 2012, the U.S. was the second largest coal
producer in the world (922 million metric tons [MMT]) after China (3,651 MMT), and followed by
India (589 MMT) (EIA, 2014a). Coal accounts for 24.7 percent of energy production in the U.S. (EIA,
MER March 2014, Table 1.2). The U.S. exports approximately 12 percent of its coal production,
while imports equal approximately 1 percent of its total domestic consumption (EIA, MER March
2014, Table 6.1). Table 36-1 quantifies recoverable reserves and recent coal production in the U.S.
Table 36-1. U.S. Coal Reserves and Production
Indicator
Anthracite & Sub-bituminous
Bituminous & Lignite
(million tonnes) (million tonnes)
Total Global Rank
(million tonnes) (# and %)
Estimated Proved Coal Reserves
107,276
127,340
234,615
1 (26.4%]
[2011]
Annual Coal Production (2012]
850.51
71.6
922.12
2 (11.69%]
Source: EIA (2014a)
Figure 36-1 highlights U.S. coal basins, as well as the location of gassy U.S. coal seams.
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Figure 36-1. Map of U.S. Coal Basins
Williston Bi
/0.88TCFG
. Western Oregon and Washington Province
1.49 TCFG
Bighorn Basin Province
0.13 TCFG\
Wyoming Thrust Belt Province Wind River Basin Province
0.36 TCFG 0.25 TCFG
- Powder River Basin Province
14.26 TCFG
PENNSYLVANIA
ANTHRACITE
BASIN
Southwestern Wyoming Province
1.53 TCFG
Uinta-Piceance Basin Province
2.31 TCFG
UINTA BASIN
\ PICEANCE
Paradox Basin Province BASIN
0.45 TCFG *
Forest City Basin Province
0.45 TCFG \
San Juan Basin Province
24.24 TCFG
Raton Basin Province
1.59 TCFG
SAN JUAN BASIN
ARKOMA BASIN
Arkoma Basin Province
3.51 TCFG
BLACK WARRIOR BASIN
¦ Black Warrior Basin Province
7.05 TCFG
Gulf Coast Region
4.06 TCFG
• Coalbed Methane Fields
Coal Basins, Regions & Fields
czj Bitmuminous Coal
EC Anthracite Coal
Sources: USGS (2014]; USEPA (2004)
Gassy coal seams of the U.S. are found in four geographic regions: the Appalachian Basins of the
eastern U.S. (medium to high volatile bituminous and anthracite), the Illinois Basin in the Midwest
(medium to high volatile bituminous), the Rocky Mountain Basins—Piceance, San Juan, and Uinta—
in the western U.S. (sub-bituminous to medium/high volatile bituminous), and the Black Warrior
and Arkoma Basins of the South/Southeast (sub-bituminous to medium/high volatile bituminous).
36.1.2 Stakeholders
Table 36-2 identifies mining companies that are currently draining gas and provides 2013 total
drained gas estimates and end uses for their projects, as reported to EPA's Greenhouse Gas
Reporting Program (GHGRP) (see page 351 for more details). These mining companies are key
stakeholders in U.S. coal mine methane (CMM) development as they host CMM recovery and use
projects.
Table 36-2. Key Coal Mine Companies Draining Gas at U.S. Mines
Mining Companies Draining Gas
Total Drained Gas in 2013
(thousand cubic meters per day)
End Uses
CONSOL Energy
1,954
Natural gas pipeline injection,
Thermal dryer
Walter Energy
720
Natural gas pipeline injection
Alpha Natural Resources
289
Natural gas pipeline injection
Murray Energy
228
Natural gas pipeline injection
Cliffs Natural Resources
172
Natural gas pipeline injection
Drummond Company
153
Mine air heating
ft
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Table 36-2. Key Coal Mine Companies Draining Gas at U.S. Mines
Mining Companies Draining Gas
Total Drained Gas in 2013
(thousand cubic meters per day)
End Uses
Arch Coal
BHP Billiton
Hallador Energy
Oxbow Carbon & Materials
Bowie Resource Partners
58
54
39
28
11
Electricity generation. Flare,
Mine air heating
N/A
N/A
N/A
N/A
Source: USEPA (2015a)
Additional key stakeholders include:
¦ CMM treatment and utilization equipment manufacturers;
¦ Project developers;
¦ Engineering, consultancy, and related services;
¦ Universities and research establishments (National Institute for Occupational Safety and
Health [NIOSH], U.S. Geological Survey [USGS], U.S. Department of Energy [DOE]);
¦ Regulatory agencies, including agencies that approve projects (Mine Safety & Health
Administration [MSHA]) and lease federal land (U.S. Bureau of Land Management [BLM],
U.S. Forest Service); and
¦ Other organizations, including the National Mining Association and emissions credits
brokers.
Many of these individual stakeholders are listed as Network Contacts on the U.S. EPA Coalbed
Methane Outreach Program's (CMOP) website athttp://www.epa.gov/cmop/networkcontacts.html.
36.1.3 Status of Coal and the Coal Mining Industry
All U.S. coal mines are owned and operated by private sector companies. Coal is produced in 25
states spread across three major coal-producing regions. In 2012, approximately 70 percent of
production originated in five states: Wyoming, West Virginia, Kentucky, Pennsylvania, and Illinois.
In addition, there are more than 7,500 abandoned underground mines (USEPA, 2004), 492 of which
are considered gassy (USEPA, 2015a). Table 36-3 summarizes coal mining in the U.S. by mine type.
Table 36-3. Summary of U.S. Underground and Surface Mine Production, 2013
Type of Mine
Production
Number of Mines
(million tonnes)
Underground (active] mines - total
309.5
395
Surface (active] mines - total
581.3
637
Source: EIA (2015]
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36.2 Overview of CMM Emissions and Development
Potential
In 2012, nearly 60 percent of all U.S. CMM emissions were released through underground mine
ventilation fans. Other sources include methane released through gas drainage systems at
underground coal mines that employ vertical and/or horizontal wells, fugitive emissions from
abandoned coal mines, coal seams that are exposed to the atmosphere through surface mining
operations, and post-mine emissions that are released from the handling and transportation of coal
following mining activities. The U.S. has been a leader in CMM recovery and use since the 1990s. As
of 2013, there were 22 projects at 16 active underground mines in the U.S., as well as 17 projects at
37 abandoned mines. Recovery and use projects at active underground U.S. mines reduced methane
emissions by approximately 41 billion cubic feet in 2013 (USEPA, 2015a).
36.2.1 CMM Emissions from Operating and Abandoned Mines
Table 36-4 quantifies methane emissions from the U.S. mining industry in recent years.
Underground coal mines in the U.S. contribute the largest share of methane emissions due to the
higher methane content of coal in the deeper underground coal seams.
Table 36-4. U.S. CMM Emissions (million cubic meters)
Emission
Category
1990
2005
2008
2009
2010
2011
2012
2013
Underground
Mining
4,754.7 <
3,513.3
4,235.7
4,629.5
5,007.7
4,174.2
3,868.5
3,871.8
Surface Mining
632.5
698.1
750.4
677.3
677.3
683.2
603.0
570.4
Post-Mining
(Underground]
541.5 <
449.7 ;>
429.4
392.0
397.3
405.2
393.7
386.6
Post-Mining
(Surface]
137.0 ^
151.2
162.6
146.7
146.8
148.0
130.6
123.6
Total for Operating
Mines
6,065.6
4,812.4
5,578.0
5,845.6
6,229.1
5,410.6
4,995.8
4,952.4
Abandoned Mines
423.1 ;
387.6
371.7
374.0
386.8
378.4
365.5
365.8
Total for
All Mines
6,488.7
5,200.0
5,949.7
6,219.6
6,615.9
5,789.0
5,361.3
5,318.2
Source: USEPA (2015a)
The recovery and utilization of methane liberated from coal mine degasification systems has
averaged 83 percent since 2000. This is due primarily to the deployment of large scale pipeline
injection projects located in the eastern U.S. The remaining portion of the liberated CMM is vented
and accounts for the 201 million cubic meters presented in Figure 36-2 for degasification
emissions.
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Figure 36-2. Active Underground Coal Mine Production and CMM Emissions in the
U.S., 2000-2013 (million cubic meters)
6,000
1,400
5,000
3,000
2,000
1,000
1,200
o
1,000 £
o
800 ~
600 £
u
3
-o
O
400 -
(U
o
u
200
2005
2007
Year
2009
2011
Total CMM Liberated VAM Degas Liberated ^—Recovered & Used Coal Production
Source: USEPA (2015a]
At the end of 2013, there were 22 methane recovery, destruction, or use projects in the U.S. Most of
the projects involve upgrading CMM for injection into a commercial pipeline. However, these
projects also include four other types of methane utilization and destruction, utilizing either flares
and/or thermal oxidizers. In addition, there were 17 abandoned mine methane (AMM) projects
operating at 37 abandoned mines in the U.S. All of these mines are located east of the Mississippi
River in the Central Appalachian, Northern Appalachian, Illinois, and Warrior coal basins with the
exception of two western mines, one in Colorado and one in Utah. One project—the Corinth Project
located in southern Illinois—recovers methane from 14 mines that were abandoned between 1926
and 1998. Table 36-5 shows a summary of the various types of CMM utilization deployed at the
mines.
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Table 36-5. Summary of U.S. Mine Methane Recovery & Destruction Projects
Number
of Mines
with
Projects
Number
of
Projects
Types of CMM Utilization
Pipeline
Electric
Generation
Heater
Boiler/
dryer
Flare
VAM
Underground
16
22
14
2
2
1
1
2
Abandoned
37
17
14
2
0
0
1
0
Underground
Surface
0
0*
0
0
0
0
0
0
*There were two projects at the North Antelope Rochelle Mine that were shut-in in 2011.
There were several new projects deployed in 2012, as well as new types of CMM utilization added
to existing projects. The Elk Creek Coal Mine project located at Oxbow's Elk Creek Mine in Gunnison
County, Colorado is the second active underground coal mine in the U.S. to generate electricity from
CMM and the first at a western coal mine. The planned three-Megawatt plant is currently operating
one engine with two additional engines to be installed in the future. The project also utilizes a flare
and heaters. In addition to selling electricity to a local utility, the project is expected to generate
offset credits in the voluntary carbon market and is listed with the Climate Action Reserve or CAR
(see page 356).
The VAM project at Murray Energy's Marshall County Mine (formally the McElroy Mine) in Marshall
County, West Virginia began destroying methane in May 2012, and is the largest VAM project in the
U.S. The project consists of three regenerative thermal oxidizers (RTO) that convert methane to
carbon dioxide and water vapor. At startup of the RTO, the ceramic medium bed in the RTO is
heated with a propane burner. VAM is then forced through the bed, methane is oxidized, and the
released heat is recovered by the ceramic bed medium and the air flow is reversed. The heat
recovered from the first cycle heats the incoming VAM and the process repeats. The methane
concentration in the VAM ranges between 0.6 and 1.5 percent. The project is listed with CAR and is
projected to reduce emissions by 322,000 tonnes of C02e per year.
In the U.S., flaring has not been widely implemented at active mines. However, the MSHA has
approved flares at the Elk Creek coal mine and the Solvay trona mine. In addition, at two active
mines drainage gas is used to preheat incoming ventilation air in cold months to both condition the
incoming air and prevent the formation of large icicles at the ventilation shaft opening; these
heaters essentially constitute horizontal flares.
36.2.2 Coalbed Methane from Virgin Coal Seams
The U.S. is the world's leading producer of coal seam gas or coalbed methane (CBM). Production has
been established in 10 coal basins nationwide (primarily San Juan, Black Warrior, and Central
Appalachian) as shown in Figure 36-1 (EIA, 2009a). Total annual CBM production in 2012 was
estimated at 1,655 billion cubic meters (EIA, 2014b). Table 36-6 summarizes the proved U.S. CBM
reserves by state.
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Table 36-6. U.S. CBM Proved Reserves (billion cubic meters)
Location
2005
2006
2007
2008
2009
2010
2011
2012
Alabama
50.2
58.6
60.2
48.9
38.0
36.8
34.3
28.5
Arkansas
0.8
1.0
0.9
0.9
0.6
0.8
0.6
0.3
Colorado
191.8
179.6
222.8
233.3
208.1
183.6
186.3
143.7
Kansas
7.3
6.6
9.6
8.5
4.6
7.3
6.5
5.2
Louisiana
0.0
0.03
0.2
0.3
0.0
0.0
0.0
0.0
Montana
2.1
2.2
1.9
2.1
1.0
1.8
0.7
0.3
New Mexico
148.6
138.6
118.1
113.0
103.2
100.0
95.1
78.5
Ohio
0.0
0.03
0.03
0.03
0.0
0.0
Oklahoma
16.1
19.4
35.8
14.5
9.6
9.2
7.8
12.4
Pennsylvania
1.3
1.4
3.1
2.9
3.7
3.7
3.5
3.0
Texas
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.3
Utah
25.5
21.2
26.1
25.3
20.5
20.3
19.2
14.7
Virginia
44.5
51.3
55.2
52.4
64.0
49.6
46.0
43.5
West Virginia
5.3
5.5
7.2
7.0
6.2
6.2
3.9
3.0
Wyoming
69.3
69.3
77.5
78.7
65.9
76.0
71.9
49.2
Other States*
0.5
0.8
0.8
1.2
0.5
0.5
0.5
0.4
U.S. Total
563.3
555.6
619.4
588.9
526.1
495.8
476.2
384.9+
*Other States includes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and
Tennessee.
Source: EIA (2014c]
36.2.3 Opportunities and Challenges to Greater CMM Recovery and
Use
As shown in Table 36-7, the U.S. is a signatory to UNFCCC and the Kyoto Protocol, but did not ratify
the Kyoto Protocol.
4 Coal reserves are generally classified as "probable" and "proved," with the resources in the "proved" categoiy having a
high degree of being economically recoverable at current prices and operating costs. As coal is produced, the amount in
the proved category is reduced by that amount. Additions to the proved categoiy can be made through exploration
findings or by moving reserves from the probable categoiy to the proved category if those reserves are deemed to be
economically recoverable to a high degree of certainty (usually by further development of the coal deposit]. Both
additions and reductions from the proved categoiy can be made depending on the relative price of coal and operating
costs and their effect on the economics of recovery. Another factor that influences the quantity of reserves reported is gas
prices. With the steady decline in gas prices since 2008, this could also account for the decline in coal reserves during the
same period.
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Table 36-7. The United States' Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 12,1992
November 12,1998
October 15,1992
Kyoto Protocol
Source: UNFCCC (2014)
At the present time, GHG emissions from coal mining activities are not regulated in the United
States. The U.S. Environmental Protection Agency (USEPA) has developed voluntary programs
aimed at partnering with industry states and communities to reduce GHG emissions, including
CMOP fwww.epa.gov/cmopl. CMOP is a voluntary program whose goal is to reduce methane
emissions from coal mining activities by promoting profitable CMM recovery and use. By working
cooperatively with coal companies and related industries, CMOP helps to address barriers to using
CMM instead of emitting it to the atmosphere. In turn, these actions mitigate climate change,
improve mine safety and productivity, and generate revenues and cost savings.
The California Air Resources Board (CARB) recently adopted the Compliance Offset Protocol Mine
Methane Capture (MMC) Protocol. The MMC Protocol allows for projects which quantify GHG
emission reductions from the capture and destruction of methane that would otherwise be vented
to the atmosphere at active underground and surface mines (via VAM and mine methane drainage
activities) as well as abandoned underground mines (via mine methane recovery). Under this
protocol, projects must meet a number of eligibility requirements to qualify, plus all offsets are
subject to verification.
CMM offset projects are also eligible for carbon credits through a number of voluntary GHG
registries located in the U.S., namely the Verified Carbon Standard (VCS), CAR, and the American
Carbon Registry (ACR). Whether a CMM project is eligible for carbon credits depends on a number
of project specifics, such as project start-up date, end use technology (i.e., electricity generation vs.
pipeline sales), and origin of methane (i.e., active vs. abandoned mines, surface vs. underground
mines). Each GHG registry also has its own rules governing project eligibility, additionality, and
registration. Currently, CMM projects at underground coal mines are eligible to some degree in all
three GHG registries, the exception being that CAR does not accept CMM pipeline sales projects.
AMM projects are accepted only by VCS, and SMM projects are accepted only by VCS and ACR.
Many states in the U.S. have developed renewable energy portfolio standards (RPS) or clean energy
goals (CEG) that direct electricity providers to generate or obtain minimum percentages of their
power from "eligible energy resources" by certain dates. Utilities in 42 states offer their customers
"green pricing," in which customers opt to pay a premium on their electric bills to have a portion or
all of their power provided from renewable sources (EERE, 2012). Six states include CBM or CMM
in their renewable/alternative energy standards: Colorado, Indiana, Pennsylvania, West Virginia,
Ohio, and Utah (DSIRE, 2014).
36.2.4 Market and Infrastructure Factors
Infrastructure Issues
The majority of CMM recovery projects in the U.S. involve selling the methane directly to natural
gas pipelines. Generally, only gas from wells drilled into virgin seams in advance of mining is
suitable to meet the high-quality gas standards required by pipelines (usually 95 percent or greater
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methane with minimal contaminants). However, medium-quality CMM (e.g., gob well gas) can be
processed to remove contaminants and upgraded to pipeline quality. Several technologies for
upgrading methane are now easily available through vendors (USEPA, 2008).
The existing U.S. gas pipeline infrastructure plays an important role in determining if and where
pipeline sales are feasible. In the eastern U.S., the natural gas pipeline system is more extensive and
is located closer to gassy coal mines than in the western U.S. In some instances, mines may need to
construct a feeder pipeline to transport the CMM to the pipeline from the wellhead or from the gas
upgrading/processing facility. Mines in the western U.S. often have little or no access to pipelines
and thus the option for pipeline sales is limited, since building feeder pipelines would be cost
prohibitive. Unlike Europe or China, large population centers in the U.S. are not typically located in
close proximity to coal mines. Thus, there are not always readily accessible major methane markets
near mines given the absence of reasonably accessible long-distance pipelines.
Figure 36-3 illustrates interstate and intrastate natural gas pipelines in the U.S. as of 2009. Figures
36-4 and 36-5 summarize the U.S. natural gas pipeline expansion from 1997 to 2012, with
estimations through 2015. From 1997 to 2012, natural gas pipeline capacity was expanded by
nearly 180 billion cubic feetper day and more than 32,000 miles of new natural gas transmission
pipeline were placed in service. However, both natural gas pipeline capacity and mileage peaked in
2008, and new additions reported in 2012 were the lowest since 1997 (EIA, 2013b),
Figure 36-3. U.S. Interstate Natural Gas Pipelines, 2009
Source: EIA (2009b)
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Figure 36-4. Annual Increases in U.S. Natural Gas Pipeline Capacity
(billion cubic feet per day)
1997 2002 2007 2012
Source: EIA (2013b]
Figure 36-5. Annual Increases in U.S. Natural Gas Pipeline Length (thousand miles)
4.0
1997 2002 2007 2012
Source: EIA (2013b]
Institutional Issues
Disputes over ownership of methane produced from coal seams can present a barrier to further
development of the CMM industry in the U.S. Ownership of carbon-based mineral rights is often
divided between the oil/natural gas estate and the coal estate. Whether on public or private land,
the coal lessee has had the right to capture and discharge methane without paying royalties to
maintain safe working conditions. Although some states have attempted to clarify the ownership
issue through legislation, the U.S. government has only done so in specific regions. BLM, within the
U.S. Department of the Interior, has established an incentive in Wyoming's Powder River Basin that
encourages pre-mine gas drainage prior to surface mining in return for reduced natural gas royalty
payments to the U.S. government. The areas in which this incentive applies are called Conflict
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Administration Zones (CAZ). The CAZs were established with BLM Instruction Memorandum No.
2003-253 in 2003 and were re-delineated in December of 2009 (BLM, 2010) and again in January
of 2013 (BLM, 2013). Other disputes are settled on a case-by-case basis.
For in-mine boreholes and gob wells at active mines, mine operators receive approval directly from
MSHA. However, licenses are granted by the state in cases where the wells are drilled for
exploration and production for pre-mine drainage on property outside the jurisdiction of MSHA and
for production of methane from abandoned mines that no longer fall under MSHA's jurisdiction.
Mineral leases are either owned by the U.S. government, as is the case in many parts of the West, or
privately owned, as is the case in most other areas of the country. For private leases, laws in each
individual state govern ownership of the resource. Federal law governs U.S. government-controlled
leases, and the BLM manages the mineral rights on those properties.
The markets for coal, gas, and electricity have been largely deregulated. Power generation is
deregulated, and there is free and open access in the wholesale market Power transmission rates
are regulated, but there is open access to transmission lines. Power distribution (retail) also
continues to be regulated, the prices of electricity being regulated closely by regional public utility
commissions. For natural gas, generation and distribution are deregulated and there is open access
in the wholesale market, with free and open competition. However, transportation of coal and
natural gas is regulated by the federal government for interstate transport and by states for
intrastate transport.
U.S. natural gas prices rose fairly steadily from 2001 until they peaked in 2008 and then declined
during 2009-2012, as shown in Table 36-8.
Table 36-8. Recent U.S. Natural Gas Prices
Year
U.S. Natural Gas Wellhead Price
(dollars per thousand cubic meters)
2012
$93.94
2011
$139.49
2010
$158.21
2009
$129.61
2008
$281.46
2007
$220.72
2006
$225.66
2005
$258.86
2004
$192.82
2003
$172.34
2002
$104.18
2001
$141.26
Source: EIA (2014d)
In 2012, coal delivered to the U.S. steam-electric utility plants averaged $45.77 per short ton, while
coal delivered to coke plants (metallurgical) averaged $190.55 per short ton (EIA, 2013a).
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Financing
Capital investment costs for CMM projects vary greatly depending on the project scope and site-
specific requirements. Similarly operating costs vary greatly depending on the site characteristics.
The vast majority of direct project funding has come from the private sector, especially mining
companies or private investment firms that have provided the capital investment for gas
processing, blending and transport for pipeline sales.
Several U.S. government agencies provide funding resources for CMM recovery and utilization
projects located in the U.S. DOE grants have provided funding for a number of demonstration
projects. The Small Business Administration operates a loan fund that assists small businesses
engaged in energy technology and energy efficiency by guaranteeing loans if key conditions are
met EPA's Environmental Finance Program assists communities in funding environmental projects
by helping to lower costs, increase investment, and build partnerships.
Tax credits were used to encourage the production of so-called "unconventional" sources of natural
gas, including virgin coal seam CBM and CMM. Known as "Section 29" tax credits (referring to the
chapter of the Internal Revenue Service tax code), they allowed for tax credits beginning at
nominally $3 per barrel of oil equivalent and gradually being reduced. The credits were enacted in
1980 and expired on 31 December 2002. The Section 29 tax credit is widely believed to have
spurred CBM production throughout the U.S. Reauthorization of Section 29 (now Section 45)
credits was removed before the Energy Independence and Security Act of 2007 was passed in the
110th Congress (NBSA, 2007). The tax credits were reinstated and revised under the Energy
Improvement and Extension Act of 2008 (IRS, 2009) and ended on 31 December 2013.
Although royalty fees are negotiable for private leases, a standard royalty of 12.5 percent of
revenues on sales is usually paid by the operator/lessee to the owner of the mineral estate.
Severance taxes are paid to state governments on revenues from natural gas sales. Power sales and
other uses generating revenues are also taxed. The U.S. does not have a Production Sharing
Agreements regime. The U.S. has removed all gas tariffs for gas exports / imports to or from Mexico
and Canada through the North American Free Trade Agreement enacted in 1994.
36.2.5 Regulatory Information
Methane recovery projects must comply with stringent environmental standards, especially in
environmentally sensitive areas and near urban centers. Environmental protection measures
generally can be categorized as pollution control measures and habitat/land use protection.
Pollution control requirements include (1) air quality standards for production of nitrous oxides,
sulfur oxides, and particulate matter; (2) water quality standards limiting stormwater and
wastewater discharge from facilities; and (3) noise abatement Habitat/land-use restrictions
include compliance with the Endangered Species Act and protection of forests and habitat such as
limiting access in roadless and wilderness areas. In some instances, especially on federal lands, it is
often necessary to prepare a formal environmental impact assessment
Safety relating to operating a CMM recovery project is governed by two regulatory agencies. MSHA
has jurisdiction over mining-related matters including operation of any in-mine drilling and gas
gathering equipment. MSHA also retains jurisdiction over most surface equipment The
Occupational Safety & Health Administration has jurisdiction over worker health and safety for
equipment unrelated to the mining operation (e.g., gas engines away from mine facilities).
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In 2009, U.S. EPA issued the Mandatory Reporting of Greenhouse Gases Rule that requires reporting
of GHG data and other relevant information from large sources and suppliers throughout the U.S.
The GHGRP fhttp: //www.epa.gov/ghgreporting/index.html] requires underground coal mines
above the reporting threshold to report methane liberated through ventilation streams and
degasification systems. The mines report the net ventilation and drainage flows along with the
portion of that flow that is emitted and the portion recovered for utilization or flaring. If the
recovered methane is flared, the CO2 from methane destruction is also reported. Methane utilized in
an engine or other combustion device requires that the facility reports CO2 emissions under the
subpart covering combustion devices, if it is a size and type that fits the subpart requirements.
In June 2013, President Obama announced a series of executive actions to reduce carbon pollution,
prepare the country for impacts of climate change, and lead international efforts to address global
climate change. As part of this Climate Action Plan (White House, 2013a), President Obama issued a
Presidential Memorandum directing EPA to complete carbon pollution standards for the power
sector (White House, 2013b).
In March 2014, the White House released the "Strategy to Reduce Methane Emissions," which
outlines steps to further cut methane emissions from landfills, coal mining agriculture, and oil and
gas systems through cost-effective voluntary actions (White House, 2014). For the coal mining
sector, the strategy includes both a voluntary element through CMOP, and a component highlighting
potential regulatory action on federal lands under BLM's jurisdiction. In April 2014, BLM released
an Advanced Notice of Proposed Rulemaking (ANPRM) to gather public input on the development
of a program for the capture and sale, or disposal of waste mine methane5 on lands leased by the
federal government (BLM, 2014).
36.3 Profiles of Individual Mines
Information on U.S. mines can be found on CMOP's interactive "CMM Recovery at Active and
Abandoned U.S. Coal Mines: Current Projects and Potential Opportunities" map
fhttp://epa.gov/cmop/resources/map.html]. The map and accompanying matrix provide information
about current projects and potential opportunities to develop CMM recovery and utilization
projects at active U.S. coal mines. The information presented is a condensed version of CMOP's
earlier report "Identifying Opportunities for Methane Recovery at U.S. Coal Mines: Profiles of
Selected Gassy Underground Coal Mines 2002-2006"
fhttp://epa.gov/cmop/docs/profiles 2008 final pdfl. which provides information about specific
opportunities to develop methane recovery and use projects at large underground coal mines in the
U.S. The report contains profiles of 50 U.S. coal mines that may be potential candidates for methane
recovery and use, as well as on-going recovery and use projects at 14 of the mines.
36.4 References
BLM (2010): Coal & Coalbed Natural Gas Conflict Administration Zone, U.S. Bureau of Land Management,
accessed 27 August 2010. http://www.blm.gov/wv/st/en/programs/energy/CAZ.html
BLM (2013): Maintenance of Conflict Administration Zone (CAZ), U.S. Bureau of Land Management, updated 10
January 2013.
5 Term used by BLM meaning methane emitted from coal mines, or CMM.
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http://www.blm.gov/stvle/medialib/blm/wY/programs/energy/coal/cazmaps.Par.4064.File.dat/CAZ 1 2013 De
cision.pdf
BLM (2014): BLM to Examine Steps to Reduce Methane From Mining Operations on Public Lands, U.S. Bureau of
Land Management, 24 April 2014.
http://www.blm.gov/wo/st/en/info/newsroom/2014/April/BLM to Examine Steps to Reduce Methane From
Mining Operations on Public Lands.html
DSIRE (2014): Incentives/Policies for Renewable Energy, Database of State Incentives for Renewables and
Efficiency, U.S. Department of Energy, Washington, DC, accessed September 2014.
http://www.dsireusa.org/Index.cfm?RE=l&EE=Q
EERE (2012): State-Specific Utility Green Pricing Programs, Energy Efficiency and Renewable Energy, U.S.
Department of Energy, Washington. DC, last updated May 2012.
http://apps3.eere.energv.gov/greenpower/markets/pricing.shtml?page=l
EIA (2009a): Coalbed Methane Fields, Lower 48 States, U.S. Energy Information Administration, Washington, DC,
8 April 2009. http://www.eia.gov/oil gas/rpd/coalbed gas.pdf
EIA (2009b): U.S. Natural Gas Pipeline Network, 2009, U.S. Energy Information Administration, Washington, DC,
2009. http://www.eia.doe.gov/pub/oil gas/natural gas/analvsis publications/ngpipeline/ngpipelines map.html.
EIA (2010): Annual Energy Outlook 2010, U.S. Energy Information Administration, Washington, DC, 11 May
2010. http://www.eia.doe.gov/oiaf/aeo/demand.html
EIA (2013a): Annual Coal Report 2012, U.S. Energy Information Administration, Washington, DC, 12 December
2013. http://www.eia.gov/coal/annual/pdf/table34.pdf
EIA (2013b): Today in Energy. Natural gas pipeline expansions in the United States, U.S. Energy Information
Administration. Washington. DC, posted 25 March 2013.
http://www.eia.gov/todavinenergy/detail.cfm?id=10511
EIA (2014a): International Energy Statistics, U.S. Energy Information Administration. Washington. DC, accessed
September 2014. http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
EIA (2014b): Coalbed Methane Production. U.S. Energy Information Administration. Washington, DC, released 10
April 2014. http://www.eia.gov/dnav/ng/ng prod coalbed si a.htm
EIA (2014c): Coalbed Methane Proved Reserves, U.S. Energy Information Administration, Washington, DC,
released 10 April 2014. http://www.eia.gov/dnav/ng/NG ENR COALBED A EPGO R51 BCF A.htm
EIA (2014d): U.S. Natural Gas Wellhead Price, U.S. Energy Information Administration, Washington. DC, released
30 April 2014. http://www.eia.gov/dnav/ng/ng pri sum dcu nus a.htm
EIA (2015): Annual Coal Report 2013, U.S. Energy Information Administration, Washington, DC, January 2015.
http://www.eia. gov/coal/annual/pdf/table 1 .pdf
IRS (2009): Production Tax Credit for Refined Coal, U.S. Internal Revenue Service, 7 December 2009.
http://www.irs.gov/pub/irs-drop/n-09-9Q.pdf
NBSA (2007): Pres. Bush to Sign Energy Legislation, America's Small Business Advocate, 19 December 2007.
http://www.nsba.biz/content/1615.shtml
Schwochow (1997): The International Coal Seam Gas Report, Cairn Point Publishing, Steve Schwochow, chief
editor, 1997.
UNFCCC (2014): Ratification Status - United States, United Nations Framework Convention on Climate Change,
website accessed September 2014. http://maindb.unfccc.int/public/countrv.pl?countrv=US
USEPA (2004): Methane Emissions From Abandoned Coal Mines in the United States: Emission Inventory
Methodology and 1990-2002 Emissions Estimates, U.S. Enviromnental Protection Agency, Coalbed Methane
Outreach Program, 2004. http://www.epa.gov/cmop/docs/amm final report.pdf
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USEPA (2008): Upgrading Drained Coal Mine Methane to Pipeline Quality: A Report on the Commercial Status of
System Suppliers, U.S. Environmental Protection Agency, Coalbed Methane Outreach Program, EPA-430-R08-
004, January 2008. http://www.epa.gov/coalbed/docs/red24.pdf
USEPA (2015a): Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013, U.S. Enviromnental
Protection Agency, April 2015. http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-
Inventorv-2014-Main-Text.pdf
USGS (2014): Map of Assessed Coalbed-Gas Resources in the United States, 2014: U.S. Geological Sur\>ev Digital
Data Series 69-11, National Assessment of Oil and Gas Resources Team, and Biewick, L.R.H. (compiler), U.S.
Geological Survey, December 2014. http://pubs.usgs.gov/dds/dds-069/dds-069-
ii/downloads/DDS69II platel.pdf
White House (2013a): The President's Climate Action Plan, Executive Office of the President, The White House,
June 2013. http://www.wMtehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf
White House (2013b): Presidential Memorandum ~ Power Sector Carbon Pollution Standards, Office of the Press
Secretary, The White House, 25 June 2013. http://www.wliitehouse.gov/the-press-
office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards
White House (2014): Climate Action Plan: Strategy to Reduce Methane Emissions, The White House, March 2014.
http://www.wliitehouse.gov/sites/default/files/strategy to reduce methane emissions 2014-03-28 final.pdf
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37 Vietnam
37.1 Summary of Coal Industry
37.1.1 Role of Coal in Vietnam
Coal accounted for 21 percent of Vietnam's electricity generation in 2011 (IEA, 2014). Although
Vietnam has historically relied on hydropower for electricity, coal-fired power plants are expected
to account for 48 percent of Vietnam's total electricity production by 2020 (Mayer Brown JSM,
2011). Vietnam suffered a shortage of electricity of 8-10 Terawatt-hours in 2008-09. By 2020, the
shortage could be 115-225 Terawatt-hours as energy demand is growing up to 14 percent per
year (Baruya, 2010; Economist, 2013).
The country's coal reserves, as shown in Table 37-1, are estimated at 150 million tonnes (Mmt),
with almost all of the reserves as anthracite. Since the 1980s, Vietnam has become a major player in
coal production in Southeast Asia. Production reached a peak of 44.7 Mmt in 2010 and declined
slightly to 41.8 Mmtin 2012 (EIA, 2014). Vietnam's Master Plan on Coal Sector Development to 2020
with Vision to 2030 projects annual coal output to reach 55 Mmt by 2015 (Le, 2013).
Table 37-1. Vietnam's Coal Reserves and Production
Sub-
Anthracite &
bituminous &
Total
Indicator
Bituminous
(million
tonnes)
Lignite
(million
tonnes)
(million
tonnes)
Global Rank
(# and %)
Estimated Proved Coal Reserves 150 0 150 54 (0.02%]
(2011]
Annual Coal Production (2012] 42.1 0 42.1 17(0.53%]
Source: EIA (2014]
Most of Vietnam's coal resources are located in the north. The Quang Yen anthracite region basin,
east of Hanoi near the Red River Delta, is the central mining area where coal deposits cover a total
area of 3,500 square kilometers (km2). These deposits are estimated to be 190-272 billion tonnes,
lying 250-1,200 meters beneath the basin. The dip makes about half of it suitable for surface mining
while the other half must be deep mined (Omdahl et al., 2009). In 2013, Vietnam's Prime Minister
approved a plan for a pilot project to test and evaluate technologies for underground coal mining
and gasification in the Red River coal basin. The pilot project is expected to be completed by 2020
(Vinacomin, 2013). Figure 37-1 below shows Vietnam's coal resources.
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Figure 37-1. Vietnam's Coal Resources
o
Hanoi
Da River of Song Da
,Na Duong
Thai Nguyen
Quang Ninh
\
Red River Delta
Ca River and
Nghe Tinh
1 Quang Ninh
2 Thai Nguyen
3 Backan
4 North Path
5 Da River
6 Ca River
7 Red River
8 Na Duong
Hue
Nong Son - deposit -
port of shipment
coalfield
300 km
H
Ba River - deposit ¦
Ho Chi Minh City
O
Mekong River Delta - peat deposit
Source: Baruya (2010)
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37.1.2 Stakeholders
Vietnam's coal mining industry is owned and operated by the state coal mining company
Vinacomin (Vietnam National Coal and Mineral Industries Group), which was created by the merger
of the Vietnam Coal Corporation (Vinacoal) and Vietnam Minerals Corporation. Vinacomin operates
95 percent of all coalmines (Le, 2012).
Table 37-2. Key Stakeholders in Vietnam's CMM Industry
Stakeholder Category
Stakeholder
Role
Mining Companies
¦ Vinacomin
Project hosts
Equipment Manufacturers
¦ Vietnam Research Institute of Electronics,
Informatics and Automation
Universities, Research
¦ Institute of Mining Science and Technology, Hanoi,
Technical assistance
Establishments
Vietnam
¦ University of Mining and Geology, Hanoi, Vietnam
Regulatory Agencies and
¦ Vinacomin
Project identification and
Government Groups
¦ PetroVietnam
assessment support
¦ PetroVietnam Exploration Production Corporation
37.1.3 Status of Coal and the Coal Mining industry
As of 2010, Vietnam had 30 underground mines, five of which have an annual production capacity
of more than 2 Mmt and nine of which have production more than 1 Mmt (Tran, 2010). Vietnam is
seeking to increase production of its deeper anthracite reserves for high-quality export grade coals,
as well as for its expanding coal power sector. Purchases of heavy mining equipment from Australia
have enabled the expansion of existing underground mines and development of new underground
mines.
Vietnam now has 24 open surface mines. Five of these mines have an annual production capacity of
more than 2 Mmt each. There are 15 surface mines with annual production capacity between 100
and 700 thousand tonnes. Production from surface mines accounts for 55 to 60 percent of coal
produced in Vietnam (Tran, 2010).
Vietnam exported 17.8 Mmt of coal, primarily to China, Japan, and South Korea in 2012, a decrease
from apeak of 31.3 Mmt in 2007 (EIA, 2014; Tran, 2010; Dao, 2014). Exports decreased further in
2013, falling to 12.8 Mmt In recent years Vietnam has cut its annual export volumes of coal to fill
growing demand from domestic coal-fired power plants (Dodson, 2014). Domestic coal demand
increased from 18 Mmt in 2007 to 24.8 Mmt in 2012. Exports are projected to fall to 9 Mmt per year
by 2015 (Le, 2013). Vietnam began importing coal to meet power plant demand in 2011, importing
9.5 thousand tonnes of bituminous coal from Indonesia annually (VPBS, 2013). Vietnam's state-
owned oil and gas group, PetroVietnam, is reportedly planning to purchase 10 Mmt of coal per year
from Australia and Indonesia beginning in 2017 to supply three new power plants. Vinacomin is
also planning to increase imports, with purchases to be made from Australia and Russia (Ho, 2014).
As of 2013, Vietnam had 18 coal-fired power plants with a total capacity of 6,766 MW and 13 gas
turbine plants with a total installed capacity of 7,285 MW. Coal-fired capacity is growing rapidly,
with new plants such as Uong Bi 2, Nghi Son 1 (1st unit), Quang Ninh 2 and Hai Phong 2
commissioning in 2013. Vietnam's National Plan for Power Development for the 2011-2020 Period
with Vision to 2030 (Master Plan VII) approved 52 coal-fired power plant projects and as of 2013,
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31 projects were in various stages ofplanning and construction (VPBS, 2013). To meetthe demand
outlined by Master Plan VII, Vietnam's annual coal demand will reach 62-72 Mmtby 2020, with
demand for power totaling 42-72 Mmt and other industries consuming 20-22 Mmt (Le, 2013).
37.2 Overview of CMM Emissions and Development
Potential
Vietnam has not hosted any coal mine methane (CMM) recovery and utilization projects; however,
the coal bed methane (CBM) industry is emerging in areas where mining is poised to take place, and
thus may evolve into CMM projects as CBM activity intersects with mining.
A recent study of Vietnam's 25 gassy hard coal mines was commissioned to determine gas content
of coals and to forecast methane release into the mines. Seven mines were classified as especially
gassy. The results of the forecasts and a study of the capacities of these mines' ventilation systems
are being used to estimate the amount of methane that may be captured by drainage systems.
Additionally, the gassiest mine, Mao Khe, was equipped with an automatic methane content
measurement control system (Somers, 2010).
The Khe Cham coal mine in Quang Ninh Province implemented a drainage system in 2012, reducing
the concentration of methane in ventilation air and improving mine productivity. The mine plans to
use drained methane to produce electricity for onsite use at the mining complex which includes
four underground mines. The proposed power generation project has the potential for reducing
greenhouse gas emissions by more than 360 thousand tonnes of C02e annually (GMI, 2013).
37.2.1 CMM Emissions from Operating Mines
With increasing coal production and the mining of deeper seams, CMM emissions in Vietnam have
also increased. Table 37-3 summarizes Vietnam's CMM emissions.
Table 37-3. Vietnam's CMM Emissions (million cubic meters)
Emission Category
2000*
2005
2010
2015
(projected)
Total Emissions from
Underground Coal Mines
Total Emissions from Surface
Mines
129.8
1.4
Total Emitted
131.2
366.3
484.2
530.4
Source: USEPA (2012]; *UNFCCC (2010]
37.2.2 CMM Emissions from Abandoned Mines
No information relating to recovery or use of CMM from abandoned mines is available.
37.2.3 CBM from Virgin Coal Seams
A number of potential areas for CBM development exist in Vietnam. The Red River Basin is an
economically important area of northern Vietnam. The area has coal deposits lying at depths of 250
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to 1,200 meters spread over a 3,500 square kilometer area. Gas content of the basin's sub-
bituminous coal is estimated at 0.94 to 1.6 cubic meters (m3)/tonne (30 to 50 scf/ton), with
conservative resource estimates ranging from 170 to 280 billion m3 (6 to 10 Tcf). Another area of
interest is the Quang Yen Basin, which extends over 200 km from east to west in northeast Vietnam
and covers approximately 5,000 km2. Though yet undetermined, CBM and CMM potential of this
area is a target for study (Thai, 2008).
Most of Vietnam's CBM activity to date has been confined to the Red River Basin. Keeper Resources
worked on the first CBM exploration projects. A negotiated CBM concession with PetroVietnam and
PetroVietnam Exploration Production Corporation (PVEP) covered approximately 3,600 km2 of the
Red River Basin to the southeast of Hanoi. Three years of negotiations were concluded with the
signing of a CBM Production Sharing Contract (PSC) in early 2010. The project proceeded with the
signing of drill site construction and preparation contracts after acquiring land access approvals
(Dragon Capital, 2008; Dragon Capital, 2010). According to a company announcement, however,
preliminary field desorption testing results determined that the coals were under-saturated with
no significant quantities of methane reported and further test wells were cancelled. The PSC was
relinquished in April of 2012 (VRI, 2011; Woodhouse, nd).
Arrow Energy signed a PSC with PVEP in a CBM concession block of 2,610 km2 in the Red River
Basin, referred to as the Hanoi Trough. Arrow, now Dart Energy Ltd., holds a 70 percent interest in
the block with a subsidiary of PetroVietnam holding the remaining 30 percent The block is in the
vicinity of the Tien Hai-Thai Binh industrial area and approximately 150 km southeast of Hanoi. In
2009, Dart Energy completed Phase 1 of an initial eight-well exploration drilling campaign. Results
from two wells indicated increasing gas volumes at depth. In 2010, Dart Energy commenced a
second phase of exploration drilling focusing on deepening a number of the earlier exploration
wells, which indicated some potential for commercial CBM production, at depths greater than 1,000
meters. Dart Energy has been given approval for an extension of the PSC exploration period for the
purpose of enabling further technical studies and pilot studies. The Hanoi Trough block currently
has 22.7 billion m3 of gross original gas in place (OGIP) and 7.1 billion m3 of gross 2C resource6, as
certified by Netherland, Sewell & Associates Inc. (Dart, 2013).
PetroVietnam developed a joint venture with Italian utility Eni SpAin early 2013 allowing Eni to
enter into partnerships for CBM and shale oil exploration projects in Vietnam. Eni drilled an
offshore exploration well in 2013 and studies are underway on CBM potential (Koh, 2013; Le,
2014).
37.3 Opportunities and Challenges to Greater CMM Recovery
and Use
Vietnam is a signatory to both the UNFCCC and the Kyoto Protocol (see Table 37-4). As a Non-
Annex I Party to the Kyoto Protocol, it has no national emissions targets and was eligible to host
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from
known accumulations, but the applied project(s] are not yet considered mature enough for commercial development
due to one or more contingencies. Contingent resources are further categorized in accordance with the level of
certainty associated with the estimates (low/best/high estimates are denoted as 1C/2C/3C, respectively] (PRMS,
2007],
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mitigation projects under the Clean Development Mechanism (CDM). Vietnam hosted 251
registered CDM projects; however, none were CMM recovery and utilization projects (UNEP, 2014).
Table 37-4. Vietnam's Climate Change Mitigation Commitment
Agreement
Signature
Ratification
UNFCCC
June 11,1992
November 16,1994
Kyoto Protocol
December 3,1998
September 25,2002
Source: UNFCCC (2014]
37.3.1 Market and Infrastructure Factors
Increased coal mining to meet electricity demand as well as increased demand for natural gas
makes CBM and CMM attractive in Vietnam. Coal mining is poised to continue escalating in Vietnam
to meet the demand of up to 72 Mmtby 2020 (Le, 2013). With electricity consumption growing by
12-16 percent annually through 2015 due to increased industrial and residential demand, power
shortages are expected (USCS, 2013). The government strictly controls electricity retail prices
which have been criticized as being too low to encourage investment in the power sector; however,
in order to attract more investment from the private sector in developing Independent Power
Producer (IPP) projects, Vietnam's Ministry of Industry and Trade and EVN are formulating plans to
increase prices. As of late 2013, the average price paid by retail customers was $0.07 USD per
kilowatt hour (kWh); however, the Prime Minister approved an increase to $0.09 per kWh to be
implemented by 2015 (USCS, 2013; Folkmanis, 2013).
Gas currently provides 30 percent of installed electric capacity in Vietnam (USCS, 2013). In 2012,
7.6 billion m3 of gas was used to generate 40.7 billion kWh of electricity. In 2013, 8.4 billion m3 of
gas was consumed to generate 44.4 billion kWh, an almost 9 percent increase. The total gas
consumption in Vietnam is forecast to reach 17 billion m3 in 2025, around 75 percent of which is
expected to be used for power generation. Gas prices are increasing in Vietnam, rising from $4.80
USD per million BTU (MMBtu) in 2011 to $5.19 USD per MMBTU in March of 2013. As of late 2013,
the forecasted natural gas price for March 2014 was $5.61 USD per MMBTU (VPBS, 2013).
Vietnam's gas demand is expected to exceed domestic supply by 2015 (Folkmanis, 2013) and as
such, additional gas-fired power plants are not currently planned. Vietnam is also limited in
pipeline networks (Le, 2014).
37.3.2 Regulatory Information
Vietnam's natural gas sector is controlled by the state-owned PetroVietnam, which is under the
control of the Ministry of Industry. CBM activity is conducted through PSCs and is treated legally as
petroleum. CBM is part of the government's Petroleum Development Planning; however, there are
currently no specific targets for unconventional gas production (Le, 2014). The Vietnam Petroleum
Institute cited a number of constraints to CBM production in Vietnam as of early 2014 including
lack of incentives for unconventional gas production as well as a lengthy negotiation process for gas
prices and a time-consuming process to acquire land (Le, 2014).
37.4 Profiles of Individual Mines
Profiles of individual mines in Vietnam are not available.
Y ' Global
Methane Initiative
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37.5 References
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9029-484-9, February 2010. http://www.iea-coal.org.uk/documents/82299/7465/Prospects-for-coal-
and-clean-coal-technologies-in-Vietnam- fCCC /1641
Dao (2014): Vietnam's Jan thermal coal exports fall 17% on year to 978,158 mt, Dao Dang Toan, Platts, 13
February 2014. http: //www.platts.com/latest-news/coal/hanoi/vietnams-ian-thermal-coal-exports-fall-
17-on-27929618
Dart (2013): Block MVHN-01KT (Hanoi Trough), Dart Energy Ltd., 2013.
http://www.dartgas.com/page/Worldwide/Vietnam/Block MVHN-01KT
Dodson (2014): Vietnamese state company plans to import coal from 2017, Sam Dodson, World Coal, 10
February 2014.
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MPldXzg
Dragon Capital (2008): Vietnam Resource Investments, Dragon Capital Markets Limited Monthly Report,
March 2008.
http://www.dragoncapital.com/UserFiles/File/monthly%20report/20Q8/Mar/MR 200803VRI.pdf?PHP
SESSID=elfc9daald3bfa3ae589ab41f43ad982
Dragon Capital (2010): Vietnam January 2010 Update, Dragon Capital Markets Limited, January 2010.
http://www.dragoncapital.com/UserFiles/File/monthlv%20report/2010/lan/MR 201001.pdf
Economist (2013): A heavy load, The Economist, 31 August 2013.
http://www.economist.com/news/asia/21584374-vietnams-power-grid-under-strain-all-kinds-fuses-
may-blow-heavv-load#
EIA (2014): International Energy Statistics, U.S. Energy Information Administration, Washington, DC,
accessed April 2014. http: //www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
Folkmanis (2013): Vietnam Faces Growing Threat of Power Blackouts: Southeast Asia, Jason Folkmanis,
Bloomberg News, 5 December 2013. http://www.bloomberg.eom/news/2013-12-05/vietnam-faces-
growing-threat-of-power-blackouts-southeast-asia.html
GMI (2013): Cross Measure Degasification Pilot Project at the Khe Cham 1 Underground Mine (Quang Ninh
Province, Vietnam), presented at the Global Methane Initiative Methane Expo 2013, Vancouver, Canada,
12-15 March 2013. https://www.globalmethane.org/expo-
docs/posters/CoalMines/CM VT Project KheCham-from-RRR FINAL.pdf
Ho (2014): Petrovietnam to import coal from 2017 for power plants, Ho Binh Minh, Reuters, 10 February
2014. http://uk.reuters.eom/article/2014/02/10/vietnam-coal-import-idUKL3N0LF36Y20140210
IEA (2014): Vietnam: Electricity and Heat for 2011, International Energy Agency, Paris, France, 2014.
http://www.iea.org/statistics/statisticssearch/report/?country=VIETNAM&product=electricityandheat
&vear=2011
Koh (2013): Petrovietnam, Eni Pen Pact for Unconventional Energy Exploration, Quintella Koh, Rigzone, 1
March 2013.
http://www.rigzone.com/news/oil gas/a/124727/Petrovietnam Eni Pen Pact for Unconventional Ene
rgv Exploration
Le (2012): The Coal Import and Export Strategy of Vinacomin in the Coming Years, Le Minh Chuan with
Vinacomin, presented at the Clean Coal Day International Conference, Tokyo, Japan, 5 September 2012.
http://www.icoal.or.ip/coaldb/shiryo/material/2012day2 session3 l.pdf
Le (2013): Current Status of Coal Demand and Supply in Vietnam and Plan of Vinacomin in the Coming Time,
Le Minh Chuan with Vinacomin, presented at the Clean Coal Day International Conference, Tokyo, Japan,
September 2013. http://www.icoal.or.ip/coaldb/shirvo/material/dav2 session2 3.pdf
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Le (2014): Non-Geological Constraints to Shale Gas/Coal-Bed Methane Production in Vietnam, Le Ngoc Anh
with Vietnam Petroleum Institute, presented at the Seminar on "Non-Geological Constraints to
Unconventional Gas Production in East Asia: China, Indonesia and Vietnam," Marina Mandarin, Singapore,
27 February 2014. http://www.esi.nus.edu.sg/docs/default-source/event/140218-vpi-emc-
unconventional-gas—presentation-in-singapore—final-version.pdf?sfvrsn=2
Mayer Brown JSM (2011): Vietnam Power Development Plan for the 2011-2020 Period, Mayer Brown JSM, 1
September 2011. http://www.mayerhrown.com/files/Puhlication/7eh02f45-1783-4fl4-8565-
bf5120elea08/Presentation/PublicationAttachment/5dcbbeal-2d9f-42ae-8cbd-
dab97456c4c5 Z11556.pdf
Omdahl et. al. (2009y.Vietnam's Coal, Mining, and Coal-fired Power Generation, Brent Omdahl, Nguyen Dzung,
and Jason Card, presented atthe U.S. Embassy, Hanoi, Vietnam, 10 June 2009.
PRMS (2007): Petroleum Resources Management System, Society of Petroleum Engineers, American
Association of Petroleum Geologists, World Petroleum Council, and Society of Petroleum Evaluation
Engineers, 2007.
http://www.spe.org/industry/docs/Petroleum Resources Management System 2007.pdf
Somers (2010): Coal Mine Methane Project Opportunities: Globally and in Vietnam, Jayne Somers and Charlee
Boger, presented at Advanced Mining for Sustainable Development, Ha Long Bay, Viet Nam, September
2010.
Thai (2008): Coal Bed Methane in Vietnam is Hot, Thai Son Do, Research Associate, Energy & Power Systems
Practice, Frost & Sullivan, 7 August 2008. http://www.frost.com/prod/servlet/market-insight-
top.pag?docid=140182389
Tran (2010): Coal Export and the Future in Vietnam, Dr. Tran Xuan Hoa with Vinacomin, presented at the
Clean Coal Day International Conference, Tokyo, Japan, 7 September 2010.
http://www.icoal.or.ip/coaldb/shiryo/material/Sessionl 5 TranXuanHoa.pdf
UNEP (2014): CDM Pipeline Spreadsheet, United Nations Environment Programme Risoe Centre, 1 April
2014. http://cdmpipeline.org /
UNFCCC (2010): Viet Nam's second national communication to the United Nations Framework Convention on
Climate Change, 7 December 2010. http://unfccc.int/resource/docs/natc/vnmnc02.pdf
UNFCCC (2014): Ratification Status - Vietnam, United Nations Framework Convention on Climate Change,
website accessed September 2014. http: //maindb.unfccc.int/public/country.pl?country=VN
USCS (2013): Vietnam Market for Power Generation, Transmission and Distribution, U.S. Commercial Service,
June 2013.
USEPA (2012): Global Anthropogenic Non-CC>2 Greenhouse Gas Emissions: 1990-2030, U.S. Environmental
Protection Agency, Office of Atmospheric Programs, Climate Change Division, December 2012.
http://www.epa.gov/climatechange/EPAactivities/economics/nonco2proiections.html
Vinacomin (2013): Red River coal basin development project re-kicked off, Vinacomin, 19 August 2013.
http://www.vinacomin.vn/en/news/News-of-Vinacomin/Red-River-coal-basin-development-proiect-re-
kicked-off-750.html
VPBS (2013): Vietnam Power Industry, Vietnam Prosperity Bank Securities, December 2013.
https://vpbs.com.vn/Handlers/DownloadReport.ashx?ReportID=1867
VRI (2011): Company Announcement: Vietnam Resource Investments (Holdings) Limited, Coal Bed Methane
Project - Preliminary Drilling Results, 12 December 2011.
http: //www.dragoncapital.com/media/74683/vri co%20announcement kee%20drilling%20results 12
122011.pdf
Woodhouse (nd): David Woodhouse Linkedln [Profile page], not dated, retrieved April 2014.
https://www.linkedin.com/puh/david-woodhouse/25/9a2/h76
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