COALTECH 2020
FINAL REPORT
Coal Mining and Carbon Constraints
by
MP de Wit
De Wit Sustainable Options (Pty) Ltd
Final Report on Task 6.1
August 2005
EXECUTIVE SUMMARY
Carbon constraints are starting to impact on energy choices especially in the European Union,
the largest coal export market for South African producers. This follows the adoption of the
Kyoto Protocol and the European Union Emissions Trading System. International greenhouse
gas reporting requirements further highlight the choice to measure emissions as accurately as
possible. This report provides a concise overview of a 3 year Coaltech 2020 research
programme on the measurements of greenhouse gases from South African coal mines,
scenarios for future emissions, technological options for greenhouse gas management and a
broad-based overview of the risks and benefits of coal mining in a carbon constraint world.
Information contained in this report is based on fifteen separate reports, two conference papers,
one journal publication and one international peer review generated during the course of the
project.
Earlier estimates on the amount of greenhouse gas emissions from South African coal mines
were first based on emissions factors in use by other countries, and later on correlations
between the fixed carbon content of the coal (on a dry, ash free basis) and the relationship
between seam pressure and gas content. Earlier results were a crude estimate only, and
needed site-specific refinement based on empirical evidence, in line with IPCC
recommendations.
Empirical work in the project focused on actual measurements of above and underground
methane emissions. For this task initial sampling was done for thirteen weeks at six different
mines which were selected as they represented methane concentrations for the coal mining
industry as a whole, and because ventilation fans in these mine shafts serve identifiable
production sections. In the case of surface mining, coal samples were collected from exposed
seams, drill holes and from interburden strata. Non-methane greenhouse gas estimates relied
on available input and activity data, and emission factors were determined on the basis of a
comprehensive literature review. A desktop review on possible impacts on coal and carbon
markets concluded the study.
The most significant result from this research programme is that much lower levels of methane
is actually recorded then initially calculated. Total methane from coal mining operations in
South Africa, including underground, surface and post mining activities is estimated at 72 Gg
CH4/a (±54.2 Gg). Including for non-methane emissions it was estimated that the coal mining
industry in South Africa is responsible for 6.55 Mt of CO2-e emissions (CH4, CO2 and N2O
emissions) at 2003 production levels. This is approximately 1.4 per cent of South Africa’s total
greenhouse gas emissions emitted in 2003. This translates into a methane intensity of 0.30 kg
CH4 per tonne of coal produced (6.9 kg CO2-e per tonne of coal produced) and a total carbon
intensity of 29.1 kg CO2-e per tonne of coal produced. These results are still subject to
considerable uncertainty, mainly because of large variations in free methane, and an intensive
monitoring programme is recommended. The study could not formalize an alternative
predictive model for methane release from South African coal mines, mainly because of large
variation in free methane released.
It has been estimated that state-of-the-art technology can capture at least 40 per cent of all
methane emitted from coal mining, treatment and storage operations. Methane drainage
schemes offer the best perspectives for cost-effective utilization. The income generating
potential of ventilation gas or the fugitive methane emissions released during coal mining (also
referred to as coal mining methane (CMM)), is relatively low with the possible exception of its
use as combustion air. It must be noted that South African coal fields, with lower levels of gas
saturation do not yield high levels of methane, thereby lowering the economic viability of
methane capture technologies. The Clean Development Mechanism (CDM), one of the
mechanisms under the Kyoto Protocol, currently provides an incentive to producers operating
under carbon constraints to invest in such technologies and in return receive certified emissions
reductions (CERs) counting as carbon allowances. This opportunity does not appear lucrative
to South African coal mines as South Africa is not rated as a strong CDM host country,
2
marginal abatement costs are lower in other countries such as China and India and free
methane levels are lower then in other gassy mines in China, the former USSR and the US.
With environmental constraints increasing, the quality of the coal utilised in the production of
energy will have an increasing role to play in the market share of coal as an energy source.
There is however currently no evidence that a market premium will be paid for coal products
which are mined at lower fugitive methane emissions. Nevertheless, combined with the fact
that the sulphur-content of South African export-quality coal is on par with Colombia and
Indonesia’s, an emphasis on quality aspects in coal marketing to the EU will do no harm and
might play a positive role in refining marketing and competition policy. The potential for market
erosion due to environmentally-friendly energy sources is not expected to be immediate. The
demand for steam coal will continue to be sensitive to prices for natural gas and oil, changes in
the regulatory environment and the willingness of governments to continue subsidizing
alternative sources of energy and to start internalizing the environmental costs of energy
sources.
The EU started a pilot emissions trading system for the period 2005-2007. CO2 allowances has
been allocated free of charge and 55 per cent of all allocations went to the public power and
heat sector. The important question is whether carbon constraints will be real, and if yes, how
these risks will or will not translate into costs for South African coal mining companies. South
Africa does not have carbon reduction targets until at least the next accounting period of 20132018 and whether any greenhouse gas emission caps will be taken on at that stage is
dependent on negotiations over the next few years. The short to medium term carbon risks are
therefore on the export side of coal operations. A possibility that need to be monitored is
whether more competitively focused coal-fired electricity generation sector in the EU can be
forced into a position to pass increased costs of generation on to their suppliers. This will place
South African coal mines at risk (to a maximum of R265 million at current carbon prices) as
they are reliant on the EU for 80 per cent of their exports. Whether this will be a reality depend
on a myriad of factors, most importantly the prices of other energy sources, the price elasticity
of demand and the ‘stickiness’ of supply contracts, a situation worth monitoring over time.
3
TABLE OF CONTENTS
1
2
3
4
5
6
7
INTRODUCTION ..................................................................................................................... 5
LITERATURE SURVEY .......................................................................................................... 8
2.1
Methods and measurements ...................................................................................... 8
2.2
Greenhouse gases from South African coal mines ............................................... 10
2.3
Coal Mining Greenhouse Gas Abatement Technologies ...................................... 10
2.4
Greenhouse gases and coal markets ...................................................................... 12
2.4.1 Coal markets and green coal ................................................................................ 12
2.4.2 Market erosion and environmentally friendly fuels ........................................... 13
2.4.3 Carbon markets and opportunities for the CDM ................................................ 14
RESEARCH METHODOLOGY............................................................................................. 15
3.1
Methane gas measurements..................................................................................... 15
3.2
Greenhouse gas inventory and non-methane gas measurements ...................... 16
3.3
Strategic risk-benefit analysis .................................................................................. 16
DISCUSSION OF RESULTS ................................................................................................ 17
CONCLUSIONS AND RECOMMENDATIONS .................................................................... 20
ACKNOWLEDGEMENTS ..................................................................................................... 21
REFERENCES ...................................................................................................................... 22
LIST OF TABLES
Table 1: Task list .......................................................................................................................... 6
Table 2: Tasks and actual deliverables for the research programme ................................... 7
Table 3: IPCC accepted approaches to measuring methane.................................................. 9
Table 4: Some technology options for methane abatement from coal mines.................... 11
Table 5: Selected energy prices in Germany .......................................................................... 12
Table 6: CDM country ratings ................................................................................................... 15
Table 7: Scenarios for economic growth and carbon constraints....................................... 18
Table 8: Recommendations to mitigate risks and realize benefits ...................................... 21
4
1 INTRODUCTION
Growing concern on global change, most pertinent climate change, has led to the adoption of
the Kyoto Protocol in 1997. This protocol requires industrialized or Annex I countries to reduce
their combined greenhouse gases by at least 5,2 per cent compared with 1990 levels, by the
period 2008-2012. The European Union responded with an emissions trading programme,
covering 12 000 installations and an estimated 46 per cent of all CO2 emissions in the EU.
Australia stated that it will keep to its Kyoto target, despite not having ratified the Protocol.
Although not clear yet, indications are that the United States through domestic carbon trading
schemes, regional blocks of cooperation and technological research and development, are and
will increasingly respond to the threat of climate change.
South Africa is vulnerable to predicted climate change impacts, has an energy and carbon
intensive economy, and falls under the top twenty greenhouse gas emitters in the world (DEAT
1998:7). Furthermore, given the fact that South Africa has a 12-14 per cent share in the
international coal market, and that both the share and rate of growth in coal exports are to the
European Union (DME 2003), an assessment of climate change impacts on South Africa’s
export markets is needed. In addition, more then half of domestic demand for coal comes from
coal-fired power stations, with another 40 per cent from a petrochemical operation, mostly
responsible for South Africa’s greenhouse gases, the coal mining sector’s vulnerability to any
changes international and national climate policy is apparent.
Based on the 1990 greenhouse gas inventory, coal mining accounted for almost 60 per cent of
the energy sectors’ methane emissions, 20 per cent of total methane emissions in the country,
and 3 per cent of the total greenhouse gas emissions in the country. At the moment the
greenhouse gas content of South African coal is calculated on non-site specific IPCC
coefficients. However, with the geological characteristics of South African coal it was expected
that the methane content should be lower than in other parts of the world. This intangible
benefit need to be quantified before the opportunities can be further exploited.
The main objectives of the study are:
1. The emissions of greenhouse gases, as defined by the UNFCCC (CO2, CH4, N2O, CO,
NOx aerosols and CFCs) resulting from the activities of the South African coal mining
industry in the year 2000 (up to, but not including, the combustion of the coal by
purchasers) will have been quantified to internationally-accepted standards, and
independently validated.
2. The projected emissions from the industry to the year 2020 will have been quantified
under a range of plausible scenarios, including high and low economic growth, and high
and low environmental pressure to minimise greenhouse emissions.
3. The technical options for minimisation of total greenhouse gas emissions (weighted by
the warming effect of each gas) will have been assessed and ranked in terms of the
feasible reduction, the net cost to achieve that reduction, and the timeframe over which
the technology could be introduced.
4. A broad-scale understanding will have been developed and communicated to industry
stakeholders regarding the risks and benefits of undertaking actions to reduce
greenhouse gas emissions, and of not undertaking such actions.
A breakdown of tasks for the research programme is presented in Table 1.
5
Table 1: Task list
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
Collate and review
a. existing work on methane emissions from coal mines in South Africa
b. the international literature on methods of estimating emissions from coal mining
c. data pertinent to the estimation of greenhouse gas emissions from coal mines in South Africa (including
coal characteristics, production statistics, type and depth of mining, size and type of stockpiles, mean
retention time in stockpiles)
Develop an empirical model of methane emissions from underground mining operations.
Validate the underground emission model for a range of circumstances using independent sampling.
Develop an empirical model of methane emissions from surface mining operations.
Develop a model of methane emission from coal post-mining, including during milling, stockpiling and transport.
Validate the post-mining emission model using chamber methods.
Develop a spreadsheet ‘activity-based’ model for non-methane greenhouse gas emissions due to coal mining,
including emissions due to the consumption of fossil fuels by the industry itself, the emissions of CFCs, N2O and NOx
emissions from explosives and fertiliser use.
Perform a sensitivity and error analysis on the estimates of coal gas characteristics, desorption curves, emission
factors in relation to mining practices, etc required by the various emission models (underground, surface,
smouldering and handling).
Undertake targetted new measurement campaigns to improve, if necessary to meet accepted international standards,
the estimates of input parameters to the emission models.
Describe, have internationally reviewed, and communicate the inventory method to be used for quantifying emissions
from the South African coal mines on an ongoing basis, including the specification of emission factors and the input
data required, and the creation of spreadsheets for this purpose.
Quantify the mass of carbon consumed in or around year 2000 by smouldering combustion in abandoned mines,
discard coal stockpiles and mine waste dumps, by estimating the area, (using MODIS/MAS its rate of spread, and the
equivalent thickness and carbon content of the coal residues involved.
Quantify the emission factors for CO2, CH4, CO, NOx and aerosols from smouldering coal under the core range of
circumstances where it occurs.
Calculate an integrated emission estimate for coal mining in South Africa, for a target year around 2000, along with
an analysis of uncertainty, interannual variability and trend.
Develop a boundary-layer method for validating regional emissions from non-point sources (e.g. open cast mines,
stockpiles, smouldering deposits) and collective point sources, and test it using existing data (SAFARI 2000 MOPPIT
images and atmospheric samples) and aircraft or tower profiles.
Convene and conduct stakeholder meetings (project team, Coaltech/Industry representatives, SA Climate Change
secretariat, interested NGOs)
a. Project initiation meeting
b. First-year evaluation and second-year planning
c. Second-year evaluation and third-year planning
d. Project finalisation and report-back
Survey the technologies available for the reduction of greenhouse gases from mining operations, quantify their
potential and perform marginal cost analyses on them.
Assess the information available on the potential market for ‘greener coal’ (i.e. coal with a reduced greenhouse gas
impact) and the potential market erosion by fuels perceived as being more environmentally-friendly.
Develop scenarios for emissions from coal mining in South Africa between 2002 and 2020, based on industry plans,
external factors (market demand and price, regulatory environment) and emission-reduction technology.
Identify opportunities for Clean Development Mechanism-funded mitigation projects.
6
The tasks were performed over three years and by several experts. Table 2 provides an
overview of tasks and actual deliverables. All tasks, except one which was adjusted after the
first year, were delivered in the form of a journal publication (1), independent reports (16) and
conference presentations (2). The quality of the work was guaranteed through two independent
peer reviews after the first year and halfway the third year of the project. During years 1 and 2
internal reviews and stakeholder meetings were conducted, subsequently informing and
adjusting tasks set for the following year. Tasks for years 1 and 2 correspond with those listed
in the Table. For the final year (April 2004 – March 2005) five tasks were identified (3.1 – 3.5)
for completion; some overlapping with those listed in the text box. This report aims to integrate
the main findings of these deliverables and interpret these within the context of emerging
carbon constraints to South African coal mining operations.
Table 2: Tasks and actual deliverables for the research programme
Subtask
No:
Sub-task Description
3.1
Validation measurements
3.2 (13)
Integrated emissions estimate
3.3
Final inventory
3.4
Publications and integrated
reporting
3.5 (15)
Stakeholder engagement
Expected Result
Year 3 (April 2004 – March 2005)
Final Models (UG, surface, Cook, A. 2005. Greenhouse Methane Emissions from
post-mining, non GHG,
South African Coal Mining. Report prepared for Coaltech
dumps & fires)
2020. Itasca Africa (Pty) Ltd, April
Report
Van der Merwe, M.R & Landman, T. 2004. Greenhouse
gas emissions inventory for coal mining activities in
South Africa. CSIR report 2004-036, CSIR, Pretoria.
Inventory to quantify
Van der Merwe, M.R & Landman, T. 2004. Greenhouse
emissions on ongoing
gas emissions inventory for coal mining activities in
basis
South Africa. CSIR report 2004-036, CSIR, Pretoria.
Scientific publications
Lloyd, P.J. & Cook, A. (in press) Methane release from
South African Coal Mines. The Journal of the South
African Institute on Mining and Metallurgy, 105, August.
Results wellCoaltech 2020 minutes of annual stakeholder meetings
communicated
Project management
4
Model surface mining GHGs
5
Model post mining GHGs
6
Validation and sensitivity of
models
9
New Measurement Campaigns
10
Inventory
12
Model GHGs from dumps and
fires
Actual Deliverable
Subcontracts and Progress reports
Year 2 (April 2003 – March 2004)
Model
Cook, A. 2004. Greenhouse Methane emission for
surface mining. Report prepared for Coaltech 2020.
Itasca Africa (Pty) Ltd, August.
Model
Cook, A. 2004. Greenhouse Methane emission post
mining. Report prepared for Coaltech 2020. Itasca Africa
(Pty) Ltd, September.
Validated models
Lloyd, P.J. 2004. Confirmatory tests for the emission of
coalbed methane from South African coal mines.
Report prepared for Coaltech2020. Report no CON130,
University of CapeTown, Energy Research Centre
Internationally
benchmarked input
parameters
Inventory to quantify
emissions
Model
17
Green coal SWOT analysis
Report
18
Emission scenarios
Report
19
CDM Opportunities
Report
Lloyd, P.J. &Cook, A. 2004. Methane release from
South African coal mines. Paper presented at Fossil
Fuel Foundation, Nov 2004
Suggestions from peer review and validations included
in updated work and report for underground models
(Task 3.1)
Van der Merwe, M.R & Landman, T. 2004. Greenhouse
gas emissions inventory for coal mining activities in
South Africa. CSIR report 2004-036, CSIR, Pretoria.
Landman, T. 2005. Satellite remote sensing to detect
and monitor coalfires. CSIR report 2005-002, CSIR,
Pretoria
De Wit, M.P. & Roux, R. 2004. The economics of
methane in South African coal mines. Paper presented
at South African Institute for Mining and Metallurgy
Sustainability of Coal Colloquium, 7-9 September 2004,
Nasrec Exhibition Centre, Johannesburg
Le Roux, R., de Wit, M.P., Harinath, V., King, N.,
Damon, M., Rapholo, B. & Botjes, W. 2005. Economics
of greenhouse gases in South African coal mines.
Report to Coaltech 2020. CSIR Report No 2005-015,
CSIR, Pretoria.
7
0
Project Management
0
Project Preparation
0
Project Initiation Meeting
1
Literature Survey
2
3
Subcontracts and Progress reports
Unpublished peer review by Dr. Bob Scholes
Year 1: Apr 2002 – March 2003
Detailed Project Plan
Project plan
Finalization of terms of
reference for project team
members
Literature Survey
Sub-contractor agreements
Model Methane UG
Underground methane
emissions model
Validate UG Meth Model
Validated methane
emissions model
Cook, A. 2004. Confirmatory surface and underground
methane emission measurement to verify previous
variable methane concentrations. Report to Coaltech
2020. Itasca Africa (Pty) Ltd, August.
Lloyd, P.J. & Cook, A. 2003. A possible model for the
release of coalbed methane from South African coal
mines. Report prepared for Coaltech2020. Report no
CON123, University of CapeTown, Energy Research
Centre, May.
7
Model Non-Methane GHG
Non-methane emissions
model
8
Sensitivity & error analysis
Sensitivity & error analysis
of methane and nonmethane models
11
Boundary-layer Method
14
Emission Trading Survey
Report on practicality of
boundary-layer method
measurements
Report on emissions
trading options
16
Technology Survey
17
Expert Review
0
Project Management
Report on abatement
technology options
Expert report on project
progress
Dynacon Technologies, 2002. Draft Literature Survey
Report. Report to Coaltech 2020, June.
Lloyd, P.J. & Cook, A. 2003. Further tests of a possible
model for the release of coalbed methane from South
African coal mines. Report prepared for Coaltech2020.
Report no CON128, University of CapeTown, Energy
Research Centre, October.
Van der Merwe, M.R & Landman, T. 2004. Greenhouse
gas emissions inventory for coal mining activities in
South Africa. CSIR report 2004-036, CSIR, Pretoria.
Lloyd, P.J. 2003. A preliminary assessment of models
for the release of methane from South African coal
mines. Report prepared for Coaltech2020. Report no
CON119, University of CapeTown, Energy Research
Centre. February.
Not reported, funds rolled over as per contract 2003/4
De Wit, M.P. 2005. Coal Mining and Carbon Constraints.
Report to Coaltech 2020. Prepared by De Wit
Sustainable Options (Pty) Ltd, August. (this report)
De Wit, M.P. 2002. Interim Report. Climate Change and
the measurement of greenhouse gases. Appendix 5,
Economic Report. CSIR Report ENV-P-C 2003-08,
CSIR, Pretoria.
Naicker, I. 2002. Methane abatement technologies.
Report to Coaltech 2020. CSIR Report ENV-P-C 2002070. CSIR, Pretoria
Naicker, I. 2005. Non-methane abatement technologies.
Report to Coaltech 2020. CSIR Report ENV-P-C 2005003. CSIR, Pretoria
Leung, L. 2003. Peer review. LGC GeoScience (Pty)
Ltd, unpublished.
Subcontracts and Progress reports
In section 2 the results of literature surveys on methods and measurements of greenhouse gas
emissions in coal mines, technologies to mitigate these emissions and impacts on coal and
carbon markets are presented. Section 3 focuses on the research methodologies used and
section 4 reports on the results of greenhouse measurement models and market overviews for
South African coal mines. Section 5 concludes and presents some recommendations on how
to mitigate against the risks of future carbon constraints, and exploit benefits of low methane
measurements.
2 LITERATURE SURVEY
2.1
Methods and measurements
Earlier work on the measurement of methane emissions from coal mines in South Africa was
largely driven by safety concerns. Barnard (1977) highlighted a history of methane explosions
8
in certain South African coal mines, prompting research in methane drainage techniques and
measures to improve general ventilation of these mines. These measures have proven
successful at least in some collieries, and methane has increasingly been captured and
released in the atmosphere, thereby increasing production safety (Kavonic 1990). Production
safety, however, has not been guaranteed as extensive, irregular and variable explosive fringes
have been measured close to working edges in several South African coal mine goafs (Cook
2000).
This discussion highlights the fact that coal mines had (and still have) a strong incentive for
accurate measurements of methane emissions. The measurement of methane content and
emission rate was at first done with the direct USBM method, but followed in 1988 by a
scientific and more accurate method developed in a research programme by the Chamber of
Mines Research Organisation (COMRO) (Kavonic 1990). Methane emission from coal seams
is a complex flow process, involving several variables, but the most dominant is the rate of
methane diffusion within the micropores of the coal. Seam gas content, pressure and
temperature are measured to calculate the diffusion coefficient, an approach used until today
(Dynacon Technologies 2002:3). Using this measurement approach, it was already pointed out
in the early nineties that South African coal tend towards slower (but highly variable) diffusions
then world average (Cook 1992). Later estimates place South African coal mine methane
emissions on par with those in non-gassy Australian mines (Cook 2000). Despite these
developments the need for more refined research on in situ gas content of coal seams and the
development of a national comprehensive methane emission prediction system became more
and more apparent (Creedy 1996).
With the development of the thesis that global climate change is perpetuated by anthropogenic
greenhouse gases, and subsequent international agreements on climate change such as the
UNFCCC and the Kyoto Protocol, the accurate measurement of methane in coal mines
received yet another rationale. South Africa, although not having any binding emission
reduction targets is obliged to report on greenhouse gas emission through national greenhouse
gas inventories. The IPCC (2000) published a guideline document on good practice in the
management of uncertainty in national greenhouse gas inventories.
The international literature on methane estimation and measurement generally follows the
Intergovernmental Panel on Climate Change (IPCC) Guidelines for National Greenhouse Gas
Inventories (IPCC, 1997). The accepted approach to estimating methane emissions from coal
mining is to add the net amount of underground mine emissions (emissions liberated minus
emissions used), opencast methane emissions and post-mining emissions (from underground
and opencast mined coal) (ICF Consulting, 1999). The IPCC recommends three approaches or
tiers to measuring methane, as described in Table 3.
Table 3: IPCC accepted approaches to measuring methane
Tier 1
Tier 2
Tier 3
Description
Global emission factor
Country or basin specific emission factor
Actual measurement data
Source: Based on IPCC (2000)
IPCC Recommendations
Uncertain method
Surface and post mining
Underground mining measurements
every two weeks
Greenhouse gas data from the United States show that 70 per cent of total methane in coal
mine operations is released by underground mining (ICF 1999). Almost two-thirds of US
underground coal mine methane emissions rely on actual measurements in ventilation and
degasification systems (Scheehle 2000). Two-weekly measurements are expected to bring
accuracy within ±15 per cent of the actual emissions.
At present there are no generally accepted methods for emissions from opencast or surface
mining, but indications are that emissions are relatively low (IPCC 2000). Accurate emission
9
factors are not available, but a range of 0.3 – 2.0 cubic metres per metric ton of coal mined is
used in the US (EIA 2002).
Some methane is also released during milling, stockpiling and transport. The IPCC (2000)
estimates that 30 per cent of in situ total gas content, or between 0.9 and 4.0 cubic metres of
methane per metric ton of coal mined (EIA 2002), is contained in coal which has not been
degasified before underground mining. The factor is estimated at 10 per cent if pre-mining
drainage has occurred (IPCC 2000). Post-mining emissions from surface mining is considered
negligible.
The greenhouse gas emissions from spontaneous combustion in hot soil piles has been
measured by using a chamber wherein the rate of increase in gas concentrations are measured
(Carras et al. 2000, Carras 1999). Preliminary findings suggest that spoil piles without
spontaneous combustion make a minimal net contribution to greenhouse gas emissions.
Another technique to measure greenhouse gases emitted from the entire mine, is to use special
instruments in a cross-wind concentration profile of the plume downwind from the mine
(Williams, 1998).
Several studies have attempted to locate and map underground and surface coal mine fires
using remotely sensed digital thermal infrared data. A study presented as part of this research
programme concluded that specifically the thermal Landsat band (at 11.5 microns) was usable
to delineate possible coal fire hotspots, but that the Advanced Spaceborne Thermal Emission
and Reflection Radiometer (ASTER) data is more useful to quantify the thermal combustion
rates (Landman 2005:9). Following Kaufman & Justice (1998), an algorithm was developed to
quantify the emissions impact from coal mine fires, including for the number of coal fires, the
combustion rates, carbon mass in the coal emitted as a gas, and the average lifetime of the fire
(Landman 2005:10), but not yet applied to South African conditions as data was not available.
2.2
Greenhouse gases from South African coal mines
The most important sources of greenhouse gas emissions from the coal mining industry include
the emissions from production, distribution and use of fossil-fuel based energy products such
as electricity, diesel and fuel oil, and fugitive methane emitted from underground mines. Other
emissions include SO2 emissions from coal fires and electricity generation, NOx emissions from
electricity generation and diesel use, CO emissions from diesel use on-site and NMVOC
emissions from diesel production and use (Van der Merwe & Landman 2004:ii).
Based on the 1990 greenhouse gas inventory (Van der Merwe & Scholes 1999); it was
estimated that coal mining accounts for almost 60 per cent of the energy sector’s methane
emissions, 20 per cent of total methane emissions in the country, and almost 3 per cent of the
total greenhouse gas emissions expressed as CO2-e in South Africa. These results are based
on a bottom-up approach to CH4 emissions from coal mining as previous estimates varied by a
wide margin (Scholes & van der Merwe 1995, Lloyd et al. 1997). In estimating the methane
content of the coal this inventory correlated the fixed carbon content of the coal (on a dry, ashfree basis) and the relationship between seam pressure and gas content. The depth of mining
was used to estimate pressure on the coal. The equilibrium methane content was then
estimated on the basis of the saturation content of coal at these varying depths of mining (Van
der Merwe & Scholes 1999: Appendix 2). At that time the results were a crude estimate only,
and needed site-specific refinement based on empirical evidence.
2.3
Coal Mining Greenhouse Gas Abatement Technologies
The reduction and removal of methane from coal mining operations is usually categorized as
pre-mining, during-mining, post-mining and integrated recovery and utilization technologies
(see EPA 2002, IEA 1998). Non-methane greenhouse gas reduction technologies in the coal
mining sector include options to reduce energy consumption and options to reduce or eliminate
below and aboveground coal mine fires (Moolman & Eroglu 2003).
10
It has been estimated that state-of-the-art technology can capture at least 40 per cent of all
methane emitted from coal mining, treatment and storage operations (Thakur et al. 1994). A
summary of coal mining methane abatement technologies and their potential is included in
Table 4. Several options are available and have been applied throughout the world (EPA
2002, Ruban 1999) but would need site-specific testing in South African conditions.
Table 4: Some technology options for methane abatement from coal mines
Criteria
Pre-Mining
degasification
Post-Mining
Enhanced Gob Well
Recovery
Vertical Gob Wells
In-Mine Boreholes
Integrated Recovery
and Utilisation
In-Mine Drills and/or
Advanced Surface Rigs
Compressors, Pumps
and Other Support
Facilities
During
Mining
Ventilation
Air/Degasification
In-Mine
Boreholes
Vertical Wells
Fans
In-Mine Drills and/or
Basic Surface Rig
Surface
Fans
and
Ducting Heat Recovery
from Vent Gas
Recovery Techniques
Vertical Wells
In-mine Boreholes
Support
Technologies
In-Mine Drills and/or
Basic Surface Rigs
Compressors, System
Pumps
and
Other
Support Facilities
Expected Gas Quality
High Quality
Low Quality
Medium Quality
Use Options
Chemical Feedstock
Power Generation
Co-generation
Gas
Distribution
Pipeline/Network
Industrial
Use
of
Liquefied Fuel
Currently Available
Combustion Air for OnSite/Adjacent Turbines
and Boilers
On-Site
Power
Generation
Industrial Use
On-Site
Power
Generation
Co-Gas
Distribution
Station/Network
Industrial Use
All Technologies Ability
to
Optimise
Degasification
Using
Combined Strategies
for Each Stage of
Mining
All Qualities, esp. High
Quality Gas to be
increased
Liquefied Fuel
Liquefied Natural Gas
Dim ethyl Ether
Methanol
Demonstration
Required for Vent Gas
Low-Medium
Medium-High
Adjacent Utilisation
Currently Available
Currently Available
Low
Low
Widely applicable
Site specific
50%
Net income to $45 per
tonne
of
methane
abatede
Medium-High
Medium-High
Technology, Finance,
Site Specific
80-90%
Not available
Availability
Capital requirement
Technical Complexity
Applicability
Methane Reductions
Cost (US conditions,
1998 study)
Medium-High
Medium-High
Technology,
Finance
and Site-Specific
70%+
Net income to $150 per
tonne methane abateda
10-90% Recovery
$50 - $350 per tonne
methane abatedb
$50 per tonne methane
abatedc
All Techniques
Smalld
Sources: Masa & Hirasawa [S.a], EPA (2002), US Department of Energy (1994), Moore et al. (1998), EPA (2002)
Notes:
a
Coal bed methane with utilisation
b
Ventilation air - improved drainage
c
Ventilation air – oxidation
d
Ventilation air - combustion
e
Methane drainage with utilisation
Methane drainage schemes offer the best perspectives for cost-effective utilization. Some of
the costs may be offset by a reduction in methane ventilation requirements during mining. This
does not mean that all methane degasification schemes will always be economically viable, as
the quality of the gas and assured flows are vital for the viability of enhanced gob well recovery.
In such cases reductions in methane emissions can be achieved by flaring gob well gas
(Brunner & Schultz 1999). The income generating potential of ventilation gas or the fugitive
methane emissions released during coal mining (also referred to as coal mining methane
(CMM)), is relatively low with the possible exception of its use as combustion air. The costs of
methane oxidation are lower then improved drainage through ventilation in the case where
drainage gas cannot be utilized. It must be noted that South African coal fields, with lower
levels of gas saturation do not yield high levels of methane, thereby lowering the economic
viability of methane capture technologies. It will be safe to interpret the cost figures as
optimistic for South African conditions.
R&D on methane abatement technologies related to coal mining tend to focus on more efficient
heat exchange thereby increasing the recovery rate of high quality methane gas from
ventilation air, the production of chemicals from methane gas (methanol and dim ethyl ether)
11
and the displacement of CH4 by CO2 through carbon sequestration projects. The latter is
expected to yield lower net costs of sequestration (Parson & Keith 1998)
A reduction in energy demand can be achieved by increasing the energy efficiency of coal
mining operations. Energy efficiency in coalmining, especially in opencast mining, can be
achieved by, amongst others, minimization of materials handling, reducing the deadweight of
equipment and an increased use of throw-blasting techniques. The amount of savings will
depend on site-specific mine operations, but could result in a significant reduction in energy
consumption at some mines (see Williams 1998). Such measures do not need to be motivated
by greenhouse gas response strategies, but could be implemented almost immediately with a
possible net savings to the coal mining operation.
Several control measures can be applied to deal with coal mine fires. These include using
cooling and sealing agents, dozing over, buffer blasting and cladding (Moolman & Eroglu 2002).
2.4
Greenhouse gases and coal markets
The literature review focused on international coal markets and potential markets for ‘greener
coal’, the potential market erosion by fuels perceived as environmentally-friendly and the
possible opportunities for CDM-funded mitigation projects.
2.4.1
Coal markets and green coal
South Africa produced 239 Mt of coal in 2003 of which 30 per cent (71Mt) was exported and 70
per cent (168Mt) consumed locally. The total value of production was almost R27bn, exports
valued at R13.5bn at a free-on-board (FOB) price of R189/ton and local sales valued at
R13.2bn at free-on-rail (FOR) price of R79/t (DME 2004). 80 per cent of exports are to the
European Union, with Spain, Holland, the UK, Italy and Germany the main customers, 14 per
cent to the Middle East, 3 per cent to Africa, 2 per cent to the Far East, and the remainder to
the Americas (DME 2004:61).
The FOB prices Richards Bay increased from over 40 US$/t in January 2004 to 70 US$/t at
their peak in July and fell to 50 - 53 US$/t at the end of the year. Despite higher import prices
for steam coal, it is still a cheap energy source in Germany (Table 5).
Table 5: Selected energy prices in Germany
Energy source
Natural Gas
Wind energy
Subsidised local hard
coal
Heavy fuel oil
Imported steam coal
Source: VDK (2004)
Price ( /tce)
180
150-180
160
120
60-80
With environmental constraints increasing, the quality of the coal utilised in the production of
energy will have an increasing role to play in the market share of coal as an energy source.
Currently two ‘clean’ coal commodities are marketed on the international market, namely
‘envirocoal’ and ‘green-coal’. Envirocoal is the term created by the Indonesian coal industries
to market its low ash and low sulphur content coal (Adaro 2002). The environmentally friendly
gains are found directly in the quality of the coal itself as a result of its lower ash and sulphur
emissions per energy content when combusted. Specifically the low sulphur content helps
users limit their SO2 emissions without the need for expensive equipment (Adaro 2002), a
particular important issue in countries such as the US where caps are placed on SO2
emissions. Envirocoal, although providing additional benefits to end users, does not as yet
command a premium over prices of other coals with a similar energy content but higher levels
12
of ash yields and sulphur content (Cook & Dauley 2000). However this situation is not likely to
prevail and it is recognized that environmental demands does have the potential to increase the
cost of coal (Gardiner 2002). Green-coal refers to the situation where certified emissions
reductions (CERs) from competitive forest projects are bundled together with coal exports to
provide a commodity otherwise known as greenhouse gas compensated coal. There is
anecdotal evidence that this approach has been applied to some Columbian coal exports.
Several countries can potentially impact on South African coal markets by competing on
environmental quality aspects. Indonesia’s high quality low sulphur coal provides it with a
unique competitive advantage in exporting to countries with sulphur emission caps. Colombia
has the potential to capture a major share of the coal market in the European Union (EU), due
to low sulphur content (Prévost, 2002). In 2004 it was already the fifth largest coal exporter in
the world. Australia, although not signatory to the Kyoto Protocol, is busy investing in the
development of advanced technologies to reduce greenhouse gas emissions associated with
the use of coal. China’s competitiveness is limited by low quality coal and high transport costs.
However, a possibility exists that China receives subsidies through the clean development
mechanisms (CDM) to lower the greenhouse gas emissions of coal mining, but at this stage
this is in developmental stage only.
There is currently no evidence that a market premium will be paid for coal products which are
mined at lower fugitive methane emissions. Nevertheless, combined with the fact that the
sulphur-content of South African export-quality coal is on par with Colombia and Indonesia’s, an
emphasis on quality aspects in coal marketing to the EU will do no harm and might play a
positive role in refining marketing and competition policy.
2.4.2
Market erosion and environmentally friendly fuels
The potential for market erosion due to environmentally-friendly energy sources is not
immediate. The demand for steam coal will continue to be sensitive to prices for natural gas
and oil, changes in the regulatory environment and the willingness of governments to continue
subsidizing alternative sources of energy and to start internalizing the environmental costs of
energy sources. The current outlook of high oil and natural gas prices, less oil and natural gas
reserves then coal, and limited market penetration of renewable energies, signal continued
demand for this energy source.
This does not mean that a business-as-usual scenario is predicted. It is projected that demand
for natural gas will overtake that of coal world-wide due to its environmental advantages, lower
capital costs and operational flexibility (IEA 2004). Nevertheless, coal is expected to continue
playing a key role in the world’s energy mix, especially as a source for electricity generation
(IEA 2004). An important factor is that it is projected that the rate of growth, as well as the
distribution and regional makeup of both the supply and demand for coal for electricity
generation will change. The EU is projected to generate a smaller percentage of electricity
from coal, but in East Asia this demand will rise significantly. A net absolute increase in the
demand for coal is projected on the back of continued economic growth and energy demand
(Melanie & Schneider 2002, IEA 2004). However, the effects on imports of low cost and high
quality coal from countries such as South Africa will not be immediate as pressure will first be
on EU countries to reduce their high levels of subsidies on hard coal production. The average
subsidy per ton of coal produced in Germany (and accounting for hard coal price increases
during 2004) is still around 2 times higher then the average price per ton of coal imported (IEA
2004b, VDK 2004). Further coal mine closures are scheduled for all major EU producers (IEA
2004b). The imports of hard coal in the EU have increased at an average rate of 2.61 per cent
between 1980 and 2002, and given production phase-outs and high costs of alternative energy
supplies, likely to continue at least in the short to medium term. Carbon-free energy sources,
including nuclear and renewable energy (most notably wind and biomass) will continue to play
a small role in future electricity generation, unless the full costs of energy are accounted for and
government regulations are enforced (IEA 2004).
13
2.4.3
Carbon markets and opportunities for the CDM
Those Annex I countries to the Framework Convention on Climate Change who have ratified
the Kyoto Protocol agreed to reduce or constrain growth of selected greenhouse gas
emissions. The mechanisms under which this is to be achieved include capped emissions
trading programmes and project-based GHG reductions through the Clean Development
Mechanism and Joint Implementation. The Kyoto Protocol entered into force on the 16th of
February 2005 and the first accounting period will be between 2008 and 2012.
The EU started a pilot emissions trading system for the period 2005-2007. CO2 allowances has
been allocated free of charge, covering 12000 installations in 25 countries in the EU, or an
estimated 46 per cent of the EU’s CO2 emissions in 2010. 55 per cent of all allocations went to
the public power and heat sector (Point Carbon 2004:13). This implies that coal-fired power
stations will have to adapt to the new reality of carbon constraints, especially evident in South
Africa’s main coal importing trading partners in the EU. Germany’s power and heat sector
depends for 90 per cent on solid fuels (hard coal and lignite), Spain for 81 per cent, the UK for
65 per cent, the Netherlands for 48 per cent and Italy for 25 per cent. A fine of 40 per tCO2 is
payable if an operator does not hold sufficient allowances (emissions exceed allocations); this
will increase to 300 per t CO2e in 2008. Use of emissions credits from project –based CDM
and JI mechanisms is possible up to a certain percentage as set by each Member state (EEA
2004). A recent survey indicated that The Netherlands intends to obtain 50 per cent of their
allowances abroad, 2/3 from CDM and 1/3 from JI, Portugal between 19 and 28 per cent,
Austria up to a maximum of 50 per cent, and Spain an unquantified amount through the CDM
(EEA 2004:422). The UK favours domestic emissions trading and Germany was not surveyed.
The market trading price per tCO2 has increased from around 6 in 2003 to 29 per tCO2 in
May 2005 before retreating to around 20 per t CO2 in July 2005. The price for certified
emission reductions through the CDM ranges from 3 – 5.5 per tCO2e. At this stage
regulatory and policy decisions are seen as the most important driver of the carbon market.
Supply and demand conditions will increasingly play a role, such as the terms on which
Russia’s will supply excess emissions allowances, how Japan and Canada will link up to
emissions trading and the CDM, the projected economic growth and energy demand in the EU,
the impact of weather on the demand for energy, and relative prices of energy sources such as
natural gas and oil (see Christiansen et al. 2005).
In terms of CDM ratings South Africa is rated as a CCC country (Table 6), meaning it has to a
very limited extent established a CDM/JI-related organisational apparatus. It has little CDM/JIrelevant project experience; and investment climate is not looking too good. It is therefore not
so attractive for CDM or JI investments (Point Carbon 2005).
14
Table 6: CDM country ratings
Country
Rating
1.India
BBB
2.Chile
BBB3.Brazil
BB+
4.China
BB5.Mexico
BB6.Peru
B
7.Morocco
B
8.Korea
B
9.Malaysia
B
10.Vietnam
CCC+
11.South Africa CCC
12.Thailand
CCC
13.Indonesia
CCC
Source: Point Carbon (2005)
Last (2 May 2005)
(1,BBB)
(2,BBB-)
(3,BB)
(4,BB-)
(5,BB-)
(7,B)
(8,B)
(6,B+)
(9,B-)
(10,CCC+)
(11,CCC)
(12,CCC)
(13,CCC)
World-wide there are currently no CDM projects registered or under review on coal mining
methane recovery at the CDM Executive Board, but provision has been made for methane
recovery projects. Existing methane recovery projects mostly focus on waste water
management and energy conversion from landfill gas (UNFCCC 2005). Earlier studies in the
United States show that the internal rate of return of projects mitigating coalmine and coal bed
methane can be improved significantly even at prices as low as $1.50 per tCO2 (Carothers et al.
[S.a]. In China, a study illustrated that at $5.5 per tCO2, economic impediments to methane
recovery and use in China would be removed. Recently the Asian Development Bank posted
an expression of interest for the sale of 5 million carbon credits from a coalmine methane and
coalbed methane utilization project in China (ADB 2005).
With current carbon prices and relative high volumes of methane recovery from coal mines,
there is a significant incentive to realize the economic opportunity of methane recovery in coal
bed and coal mine methane. This is especially the case in gassy mines in China where
certified emissions reductions translate in additional equity to such projects. South African coal
mines can probably competitively enter this market if demand for carbon allowances will prove
to be strong enough to exploit such less lucrative opportunities found in this country. This is a
situation worth monitoring, but certainly not one where immediate opportunity is available.
3 RESEARCH METHODOLOGY
Empirical work in the project focused on actual measurements of above and underground
methane emissions. For this task a specific sampling and measurement strategy was
developed. Non-methane greenhouse gas estimates relied on available input and activity
data, and emission factors were determined on the basis of a comprehensive literature
review. A desktop review on possible impacts on coal and carbon markets concluded the
study. The following three sections report on the methodologies used in these subtasks.
3.1
Methane gas measurements
Based on the hypothesis that South African coal mines emit less methane then indicated
through global emission factors, physical measurements of methane releases were taken.
Preliminary experiments were set up according to the internationally used IPCC model and
were intended to measure the methane content of coal on the face of operating
underground mines; to determine the methane content of the return air from the mine; and
to determine the methane remaining in the coal after it had left the mine. (Lloyd & Cook, in
press). Initial sampling was done for thirteen weeks at six different mines which were
selected as they represented methane concentrations for the coal mining industry as a
15
whole, and because ventilation fans in these mine shafts serve identifiable production
sections.
Initial results gave unexpected weak correlations between methane observed in the return
air and methane calculated to be released by residual coal and additional tests were done
to explain the observations. These additional tests focused on production shut-downs as
this signals changing conditions and presents an opportunity to measure methane release
not directly associated with production. It was observed that methane release actually
increased after production ceased and decreased after production started again. Further
tests on shift changes in other shafts confirmed this observation. Independent datasets
from Anglo Coal confirmed that methane levels dropped randomly to very low levels. In
total, 243 measurements in 27 different shafts were taken over the life-span of the project.
The approach to gather empirical information to populate the IPCC methane release model
therefore had to be abandoned after these results became evident. The combined slow
release from methane in freshly mined coal and the rapid release of free methane within
coal seams for South African coal stand in stark contrast to the IPCC model of rapid
release from freshly mined coal and slow release from methane in coal seams.
The subsequent approach was an attempt to fit a normal distribution to 65 data points
taken over two years at the Koornfontein Gloria shaft. The results were that methane
released from the mined coal and residual free methane showed very large variations,
leading to the conclusion that an intensive monitoring programme on ventilation flows is
required.
In the case of surface mining, coal samples were collected from exposed seams, drill holes
and from interburden strata. The results were analysed with the USBM graphical method to
determine lost gas volumes.
3.2
Greenhouse gas inventory and non-methane gas measurements
Non-methane greenhouse gas were estimated by using a desktop literature review on
quantities released and emission factors, limited additional calculations for coal mining
fires and relying on IPCC guidelines for the development of greenhouse gas inventories.
Both on-site and off-site emissions were included. The following emissions were included
in the final GHG inventory:
• fugitive methane emissions, the levels of which were estimated in this Coaltech 2020
study
• emissions from oxidation of carbon in waste and stockpiles, as well as spontaneous
combustion.
• emissions from energy use, including electricity, diesel, fuel and explosives.
• CO2 emissions from the use of lime and limestone to treat acid mine drainage.
• emissions associated with the production of fuel types.
• emissions associated with the production of fertilizers
Emissions excluded due to a lack of data are those from land fill sites operated by coal
mines and fugitive emissions of non-methane gases, mainly CO2 from coal seams.
All emission values are converted to CO2 equivalent (CO2-e) using latest global warming
potential (GWP) values as reported in the Third Assessment Report of the IPCC. Levels of
uncertainty were based on the availability and accuracy of input and/or activity data, and
emission factors in South Africa.
3.3
Strategic risk-benefit analysis
The desktop literature review on the state of the world’s coal markets and the relationship
with markets and regulations for greenhouse gases was further developed into a riskbenefit analysis on low methane coal (including the market for ‘greener coal’, market
erosion due to environmentally-friendly fuels and opportunities under the CDM). A logical
16
presentation of risks and benefits usually assists in the development of a strategic
response. This is supported by a quantitative, monetary analysis on potential opportunities
and/or liabilities of carbon constraints to South African coal mines.
4 DISCUSSION OF RESULTS
The most significant result from this research programme is that much lower levels of
methane is actually recorded then initially calculated. When average methane
concentrations were multiplied with known ventilation rates for each shaft, the total
ventilated methane emissions from underground coal mining in South Africa amounts to a
total of 40.8 Gg CH4/a (±30.2 Gg). The total methane lost for coal after leaving the mine in
South Africa was estimated at 28.6 Gg CH4/a (±24 Gg). Release from surface mining
operations was calculated at less then 3Gg Ch4/a. Total methane from coal mining
operations in South Africa, including underground, surface and post mining activities
therefore is estimated at 72 Gg CH4/a (±54.2 Gg). This is 6.5 times lower then the
estimate of 466.93 Gg CH4/a used for the South African Greenhouse Gas Emissions
Inventory for 1990 (Van der Merwe & Scholes 1999) and almost 14 times lower then the
numbers quoted in an earlier IEA publication (Moore et al. 1998). These results are still
subject to considerable uncertainty, mainly because of large variations in free methane,
and an intensive monitoring programme is recommended. Although exact levels are
impossible to determine at this stage, the top estimated ranges of emissions and variations
(at 126.2 Gg CH4/a) are still 3.5 times lower then reported in the South African Greenhouse
Gas Emissions Inventory for 1990.
Although actual measurements do show these lower levels, the study could not formalize
an alternative predictive model for methane release from South African coal mines, mainly
because of large variation in free methane released. Continuous future methane
measurement campaigns will strengthen the case for using the IPCC’s ‘Tier 3’ emission
coefficients.
Including for non-methane emissions it was estimated that the coal mining industry in
South Africa is responsible for 6.55 Mt of CO2-e emissions (CH4, CO2 and N2O emissions)
at 2003 production levels. This is approximately 1.4 per cent of South Africa’s total
greenhouse gas emissions emitted in 2003, assuming that emissions have grown at a
conservative 1.6 per cent per annum in the period 1990 to 2003. This translates into a
methane intensity of 0.30 kg CH4 per tonne of coal produced (6.9 kg CO2-e per tonne of
coal produced) and a total carbon intensity of 29.1 kg CO2-e per tonne of coal produced.
This compares to a factor of 127 kg CO2-e per tonne of coal produced in a similar
Australian study (William et al. 1998). Assuming that the average increase in production
realized in 1980-1998 will be sustained, CO2-e emissions for the coal mining industry are
set to increase to 10.2 Mt in 2013 and 13.3 Mt in 2020.
The low measurements on fugitive methane indicate reduced opportunities to utilize
coalmine methane in an economic feasible way. CBM, although not the focus of this
research programme, may still provide opportunities for utilization projects, but competition
for certified emission reductions (CERs) with other gassy mines worldwide are likely to be
intense. The feasibility of a CBM utilization project and associated CERs will all depend on
the financial-economic feasibility of such a project as compared to other projects worldwide. To consider pre-mining degasification through coal-bed methane (CBM) applications
as a greenhouse gas reduction option does pose its problems though. The most pertinent
are that there is not necessarily a well-defined linkage between coal mining and CBM and
that under the rules of the Kyoto Protocol additional management actions for the purpose
of greenhouse gas reduction need to be demonstrated.
Given that some methane reduction projects do show potential and that there are buyers
willing to invest in South African coal mine methane reduction or recovery projects, a key
factor will be the difference between the price of carbon allowances and the price of
implementing technology. The cost of technological interventions ranges from net gains to
17
R2275 ($350) per tonne of CH4. The highest technology costs amount to R100 or just over
12 per tonne of C02-e, lower but still within the range of current carbon prices in the EU.
This makes investment in technology for methane abatement more lucrative for overseas
investors operating under such carbon constraints.
Despite these comparisons, current trends indicate that it is unlikely that investors will
provide equity for an entire methane reduction or utilization project. CDM is often seen as
providing additional equity, thereby improving the feasibility of a project. This assumes
that CDM will be feasible in the first place. Two key risks facing the South African CDM
market need to be highlighted. First, South Africa as a country achieved very low rankings
as a CDM host country. This means that the return on projects would have to exceed
those of other more CDM friendly countries such as India, Chile, Brazil and China. This
situation and the combination of lower coalmine methane presently reduce opportunities to
the South African coal mining industry of coal mine methane recovery projects receiving
subsidies through the CDM mechanism. Second, on a macro level, a preliminary study
indicated that the assumed marginal abatement costs are lowest in China, followed by
India, the Middle East and Africa and then, Indonesia (Jotzo & Mitchaelova 2002). The
ranking is predominantly based on the availability of supply-side fuel efficiency and fuel
switching projects in the area of electricity generation as well as projects aimed at
increasing the efficiency of fossil fuel extraction and distribution. This does not mean that
CDM opportunities in South Africa, and the coal mining industry are necessary excluded,
but would need more detailed analysis to identify, and from a business perspective would
need to demonstrate higher returns to compensate for higher risks.
It is not yet clear how carbon liabilities will translate into costs for producers in countries
who have no targets under the Kyoto Protocol or any other agreement that may develop,
and whether these producers will or will not be included in future. Table 7 attempts to
highlight possible futures related to high/low industry growth and high/low carbon
constraints.
Table 7: Scenarios for economic growth and carbon constraints
Industry growth
Carbon constraints
High growth, low carbon
constraints
High growth, high carbon
constraints
Low growth, low carbon
constraints
Low growth, high carbon
constraints
Economic growth rates do not correlate well with the value of local coal sales or with the
value of exports. This signals that market drivers other then macroeconomic performance
drives performance in the South African coal mining industry. Factors that affect growth in
the value of the industry relate to sectoral supply and demand conditions as well as the
physical ability to deliver required volumes to these markets. To quantify high/low growth
scenarios in the industry would therefore require a detailed analysis on the sensitivity to
the drivers of the coal mining sector’s economic performance.
Based on the measurements of greenhouse gases, the South African coal mining industry
contributed to an emission of 5.4 Mt CO2-e in 1993 and 6.9 Mt in 2003. In a business-asusual scenario of 3.88 per cent growth in total production per annum, emissions are set to
increase to 10.2 Mt in 2013 and 13.3 Mt in 2020.
Low carbon constraints, in effect can be interpreted as no meaningful risk to the coal
mining industry. However, if South Africa coal mines were to face the same kind of carbon
constraints as in Europe (the highest carbon constraint at this point of time) this would
have translated into a potential carbon liability of R1.1billion or just more then 4 per cent of
18
the total value of production in 2003; given that carbon allowances would have to be
bought at current EU carbon emission market prices of 20 per tonne of CO2-e (R160 per
tonne). If similar constraints are imposed on South African coal exports to the European
Union only, this would translate into a potential carbon liability of R265 million, or almost 2
per cent of total export value for the year 2003. This risk could increase to almost R530
million (or 4 per cent of export value to the EU) if carbon prices settle on the current
penalty level ( 40 per tonne of CO2-e) and to R4 billion (30 per cent of export value to the
EU) if prices rise to penalty levels ( 300 per tonne of CO2-e) set for 2008. It is unlikely that
all these risks will be absorbed by exporters, and should therefore be interpreted as being
high carbon constraint estimates.
The important question is whether these carbon constraints will be real, and if yes, how
these risks will or will not translate into costs for South African coal mining companies.
South Africa does not have carbon reduction targets until at least the next accounting
period of 2013-2018 and whether any greenhouse gas emission caps will be taken on at
that stage is dependent on negotiations over the next few years. The South African
Treasury, however, is considering a carbon tax, but focused on specific sectors other then
the coal mining industry. Therefore, an internationally agreed carbon constraint to coal
production in South Africa is not expected until at least 2012 and any carbon constraints on
coal combustion and beneficiation will depend on domestic greenhouse gas policies. The
South African government has released a climate change strategy, mainly focused on
government departments to integrate climate issues in policies and practices, the
development of renewable energy sources, monitoring air quality including greenhouse
gases, and the promotion of the clean development mechanism (DEAT 2004). The coal
mining industry will be exposed in the following way should local carbon constraints
become a reality: 56 per cent to carbon released by local coal-fired electricity production,
34 per cent to the operations’ own fugitive methane emissions, 14 per cent to carbon
released through hydrocarbons, fuels and explosives, and 1 per cent to other factors
including coal fires. Local carbon constraints are therefore not expected to be significant in
the short to medium term, but could creep into the input costs (esp. electricity and fuel
costs) of coal mining over time.
The short to medium term carbon risks are more potent on the export side of coal
operations. A possibility that need to be monitored is whether more competitively focused
coal-fired electricity generation sector in the EU can be forced into a position to pass
increased costs of generation on to their suppliers. This will place South African coal
mines at risk (to a maximum of R265 million at current carbon prices) as they are reliant on
the EU for 80 per cent of their exports. Whether this will be a reality depend on a myriad of
factors, most importantly the prices of other energy sources, the price elasticity of demand
and the ‘stickiness’ of supply contracts. It is expected that the European power generation
sector will respond with wide-spread power sector abatement options, but this is primarily
dependent on long run fuel costs and the spread between coal and gas prices (ICF
Consulting 2005). With increasing gas prices, cost-effective abatement options become
more limited, and coal-fired power stations will need to focus on finding the optimal levels
between the cost of carbon allowances, cleaner coal combustion and passing on costs to
customers and suppliers.
There is an opportunity to market South Africa’s high quality coal in an environmentally
sensitive Europe. Although low coal mine methane levels during production do not
translate into direct financial advantage for exporters (as it does not reduce the amount of
greenhouse gases during combustion), together with other environmental attributes, this
can assist in maintaining and possibly increasing market share if competition for coal
extends to non-price attributes.
19
5 CONCLUSIONS AND RECOMMENDATIONS
The relationship between coal mining and the gases released during production,
stockpiling and transport has moved from being a safety concern to one of potential carbon
liability, and in some cases even one of opportunity. In addition, carbon constraints placed
on some major coal users, whether domestically or overseas, would more then likely
increase their input costs. This provides incentives for either switching to other energy
sources or passing on costs to suppliers (decreasing willingness to pay) and to customers.
These emerging risks and opportunities need to be managed and one of the first steps of
the Coaltech 2020 research programme was to refine measurements of greenhouse gases
from South African coal mines. The study concluded that fugitive methane emissions in
South African coal mines cannot be predicted on the basis of current IPCC models, but
high variations in measurements on free methane precluded the development of a robust
enough predictive model for South African conditions. Despite high errors associated with
the 243 measurements in 27 different shafts, a case was made that methane emissions
from underground, surface mining and post mining activities are in the order of 72 (± 54.2)
Gg CH4/a, several orders of magnitude lower then previously estimated, and much lower
then in other major coal producing countries. It is recommended that repeated
measurements on methane from underground mining are conducted to move towards
higher levels of certainty and a possible predictive model in future.
Following a desktop study and accounting for other greenhouse gases (CO2, N2O), it is
estimated that South African coal mine operations contribute to 1.4 per cent of South
Africa’s total greenhouse gas emissions emitted in 2003. This contribution include carbon
emissions embodied in electricity use, the coal mine industries’ own fugitive emissions,
emissions associated with the production and use of hydrocarbons, fuels and explosives
and coal mine fires. CO2 emissions from coal seams are excluded as no reliable data was
available. These emissions translate into a methane intensity of 0.30 kg CH4 per tonne of
coal produced (6.9 kg CO2-e per tonne of coal produced) and a total carbon intensity of
29.1 kg CO2-e per tonne of coal produced, compared to 127 kg CO2-e per tonne in
Australia. If it is assumed that average historical increases in coal production are
maintained, a total of 10.2 Mt CO2-e will be released during 2013, the start of the second
commitment period under the Kyoto Protocol, and 13.3 Mt CO2-e in 2020.
Technical options to reduce methane emissions are generally available, with the exception
of some ventilation air methane options that are in demonstration stages. Technically, 80–
90 per cent of methane can be reduced, recovered or utilized by using integrated recovery
and use technologies, 70 per cent recovery from pre-mining degasification and 50 per cent
recovery from post-mining enhanced gob well recovery options.
The costs of these
options range from a net income (primarily due to utilization) to R2275 per tonne of
methane for the most expensive ventilation techniques.
The Clean Development Mechanism (CDM), one of the mechanisms under the Kyoto
Protocol, currently provides an incentive to producers operating under carbon constraints
to invest in such technologies and in return receive certified emissions reductions (CERs)
counting as carbon allowances. This opportunity does not appear lucrative to South
African coal mines as South Africa is not rated as a strong CDM host country, marginal
abatement costs are lower in other countries such as China and India and free methane
levels are lower then in other gassy mines in China, the former USSR and the US.
Whether these emissions will turn into monetary liabilities is at this stage primarily a
function of the regulatory environments wherein South African coal mines produce and
wherein customers (local and overseas) operate. In the European market, it is expected
that supply and demand conditions will increasingly drive the price of carbon as a pilot capand-trade programme on CO2 emissions is already operational. Upper bound estimates on
carbon liabilities passed on to South African coal mines is estimated at R560 million, or 4
per cent of the 2003 export value. After 2008 these figures can change a lot due to the
20
start of the official commitment period under the Kyoto Protocol and alternative fine
structures in Europe. Lower bound estimates are zero as European customers do not
pass on costs to coal suppliers through a lower willingness to pay for coal imports. The
short to medium risks of domestic carbon constraints translating into significant costs to the
coal mining industry is remote.
The lower carbon intensity does present an opportunity for more targeted marketing on
high-quality (i.e. low sulphur and low carbon) coal, in line of the success of low sulphur
Colombian coal exports, to the EU.
In summary, Table 8 attempts to list the most important recommended actions to mitigate
against the risks of carbon constraints, and the opportunities presented by lower then
expected carbon intensity of South African coal mines.
Table 8: Recommendations to mitigate risks and realize benefits
Mitigate against risks
Monitoring of indicators that could
influence willingness-to-pay of European
power and heat producers for imported
coal:
• Prices
of
alternative
energy
sources (esp. natural gas) and
factors driving energy markets
• Phase-out of subsidies to the
European power and heat sector
• Price of carbon allowances and
factors driving carbon markets
• Development and implementation
of
cleaner
coal
combustion
technologies
• International
developments
on
climate
policies
esp.
local
development and
international
negotiations on post 2012 rules
Continuous measurements campaigns on
especially underground methane is needed
to formalize a predictive methane model fit
for South African conditions
Realize benefits
Intangible benefits of low methane and low
sulphur content of South African coal need
to be realized through targeted marketing
and competition policy to the EU market
CDM possibilities can be explored for
methane drainage rather then ventilation
projects, but macro-trends point away from
South Africa as a CDM host country and
competition is likely to be intense
Further research on the extent of Possible net savings in methane recovery
emissions from coal mine fires and CO2 technologies (excl coal mine methane) can
from coal seams
be achieved and need further research
6 ACKNOWLEDGEMENTS
The author would like to acknowledge CSIR, Environmentek for providing support in
managing most of the project and Coaltech 2020 for their financial support.
21
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