BUILDING THE COST CURVES FOR THE
INDUSTRIAL SOURCES OF NON-CO2
GREENHOUSE GASES
Report Number PH4/25
October 2003
This document has been prepared for the Executive Committee of the Programme.
It is not a publication of the Operating Agent, International Energy Agency or its Secretariat.
BUILDING THE COST CURVES FOR THE INDUSTRIAL
SOURCES OF NON-CO2 GREENHOUSE GASES
Background to the Study
The Non-CO2 gases taken together have made about half as much contribution as CO2 to climate
change since pre-industrial times. Their atmospheric concentrations are significantly lower than CO2
but are substantially more powerful greenhouse gases than CO2 , over a typical time period such as 100
years. In any assessment of greenhouse gas abatement strategy, the impact of reducing Non-CO2
greenhouse gas emissions must be carefully considered. One way of comparing the mitigation options
is to develop abatement cost curves1 for the Non-CO2 greenhouse gases that allow direct comparison
with similar curves for CO2 abatement options. This could be done by developing abatement curves on
a CO2 equivalent 2 (CO2 eq.) basis, which takes allowance of the different global warming potentials
(GWPs) of these gases.
The IEA Greenhouse Gas R&D Programme (IEA GHG) has carried out a series of studies covering all
of the Non-CO2 greenhouse gases (except those covered by the Montreal Protocol3 ). In Phase 2, a
series of studies were undertaken to assess the abatement options for methane (CH4 ), whilst in Phase 3,
the abatement options for nitrous oxide (N2 O) and the engineered chemicals 4 were assessed. In both the
phase 3 studies, although these had not been attempted for some of the Phase 2 methane studies because
there was insufficient information available at that time. However, it is now considered that sufficient
further research effort has been expended that will allow the abatement cost curves for all of these
sectors to be developed.
The aim of this study is to update the abatement potential and cost data presented in the earlier studies
on Non-CO2 greenhouse gases and to develop abatement cost curves for all the Non-CO2 gases on a common basis.
However, the scope of the study was limited to the industrial sectors only because, it is considered by
IEA GHG, that, there is still insufficient data available on the costs associated with the abatement of the
“other anthropogenic sources” that arise from agricultural production to allow an abatement cost curve
to be developed at this time.
The study has been carried out by ICF Consulting of the USA.
Results and Discussion
The following areas are discussed in this report:
•
•
•
•
Scope of study and methodology adopted,
Global emissions of Non-CO2 greenhouse gases (2000-2020),
Combined global Non-CO2 greenhouse gas abatement cost curve ,
Sensitivity studies.
1
Often referred to as marginal abatement cost curves or MACC’s for short.
Emission estimates are presented as CO2 equivalents - these weight each gas by its global warming potential
(GWP) which indicates how much these gases enhance radiative forcing, as well as taking into account their
different lifetimes in the atmosphere. For example, CH4 and N2 O have GWPs of 23 and 296 respectively; whilst
the main emitted PFCs, CF4 and C2 F6 have GWPs of 5700 and 11900 respectively.
3
The Non-CO2 greenhouse gases covered under the Montreal Protocol were all ozone depleting substances such
as Chlorofluorocarbons (CFCs ) and halons, carbon tetrachloride, methyl chloroform, methyl bromide and
methyl bromide
4
The term "engineered chemicals", used for this study, refers to a diverse group of volatile halogenated
compounds. These compounds include: Hydrofluorocarbons (HFCs), Hydrochlorofluorocarbons (HCFCs),
Perfluorocarbons (e.g. CF4 and C2 F6 ), Sulphur Hexaflouride (SF6 ) and methyl bromide.
2
i
Scope of study and methodology adopted
The industrial emission sectors, emission sources, and greenhouse gases (GHGs) covered by this study
are summarised in Table 1 below.
Emission Sector
Coal Mining
Oil Systems
Natural Gas Systems
Solid Waste Management
Wastewater Management
Nitric Acid Production
Adipic Acid Production
Industrial Sector High-GWP
Gases (Engineered chemicals)
Use of Ozone Depleting
Substance (ODS) Substitutes
Emission Sources
Underground mines
Oil production
Natural gas production,
transmission, processing, storage,
and distribution
Landfills
Anaerobic wastewater
management
Nitric acid production
Adipic acid production
HCFC-22 Production
Aluminium Production
Magnesium Production
Electricity Transmission and
Distribution
Electrical GIS5 Manufacturing
Semiconductor Manufacturing
Refrigeration and Air
Conditioning (AC)
Foams
Non-MDI Aerosols
MDI Aerosols
Solvents
Fire Extinguishing
Greenhouse Gases
CH4
CH4
CH4
CH4
CH4
N2 O
N2 O
HFC-23
CF4 and C2 F6
SF6
SF6
SF6
PFCs, HFCs, and SF6
HFC-134a and others
HFC-134a, HFC-152a, HFC245fa, HFC-365mfc
HFC-134a, HFC-152a
HFC-134a, HFC-227ea
HFC-4310mee
HFC-227ea and others
Table 1: Emission sectors, emission sources and greenhouse gases covered by study
A total of 119 different abatement options were analysed in the study and their technical and cost
characteristics assessed to allow them to be integrated into the abatement cost curves. Within each sector,
major emission sources were determined (e.g. methane emissions from natural gas transmission), which
were then further subdivided into emissions from individual sources (e.g. compressors, pipeline leaks,
etc.). The results have been collated for 12 different regions (Asia, Australia, China, Eastern Europe, FSU 6 ,
Japan, Latin America, Middle East, North America, OECD-Europe, Rest of Asia and South Asia)7 .
To develop the abatement cost curves, a baseline emission level was determined for each emission source
and each region. The purpose of these baselines8 was to determine potential emission reductions that can
be achieved by a specific option in a given year. After establishment of the baseline, the technical and
cost characteristics for each abatement option were then derived on a consistent basis to allow an
abatement cost curve for each sector to be developed. The individual abatement cost curves from each
sector (for 2000, 2010 and 2020) were then compiled into a combined abatement cost curve for each
gas (methane, nitrous oxide and engineered chemicals). Finally, a composite abatement cost curve for
5
Gas Insulated Switchgear
Former Soviet Union.
7
The individual countries included within each region are presented in Appendix A of the main report.
8
Baselines in this report describe emissions that are expected to occur if no additional measures (projects) to
reduce emissions are implemented with respect to the current situation. Additional measures can include
international actions to reduce Greenhouse gas emissions (such as the Montreal and Kyoto protocols ) and national
regulatory requirements (e.g., the “landfill rule” in the U.S).
6
ii
all the Non-CO2 gases was developed. The detailed methodology for the construction of the abatement
cost curves is outlined in the main report.
The main report provides a discussion on the development of the abatement cost curves for each of the
9 individual emission sectors covered, as well as details of the combined abatement cost curves for each
gas. The discussion in the overview focuses on the combined global abatement cost curve for all NonCO2 greenhouse gases.
Global emissions of Non-CO2 greenhouse gases (2000-2020)
The emissions for all the Non-CO2 greenhouse gases on a regional basis for the period 2000 to 2020 are
given in Figure 1.
7000
Africa
6000
Australia
China
5000
Emissions (MTCO2 eq.)
Eastern & Central
Europe
FSU
4000
Japan
Latin America
Middle East
3000
North America
OECD-Europe
2000
Rest of Asia
South Asia
1000
0
2000
2010
Year
2020
Figure 1: Global emissions of all Non-CO2 Greenhouse Gases
Annual emissions of Non-CO2 greenhouse gases are projected to increase from 3 800 Mt CO 2 eq. in
2000 to 6 700 Mt CO2 eq. by 2020. The regions showing the largest emissions growth are expected to
be: China, North America Latin America and the Rest of Asia. The projected emissions growth for
each gas is shown in Table 2.
Greenhouse Gas
Methane
N2 O
Engineered Chemicals
Total
Greenhouse Gas Emissions, Mt CO 2 eq.
2000
2010
2020
3156
3786
4435
230
271
298
411
683
995
3797
4740
5728
Table 2: All GHG Baseline Emissions by Gas (Mt CO2 eq.)
The biggest growth in (weighted) emissions will come from methane (1279 Mt CO2 eq.) and the
engineered chemicals (584 Mt CO2 eq.) Methane, therefore, will remain the most important Non-CO2
greenhouse gas. Nitrous oxide emissions from industrial sources are not projected to rise significantly
between 2000 and 2020.
The main increases in methane emissions are predicted to come from the natural gas sector (560 Mt
CO2 eq.) and the solid waste management (320 Mt CO2 eq.) sectors. On a regional basis, methane
iii
emissions growth between 2000 and 2020 in the natural gas sector is expected to be significant in: Latin
America, Middle East, Asia, FSU and North America (46 Mt CO2 eq.). Whilst in the solid waste
management sector, the most significant increases in methane emissions are projected for China and
Africa. For the engineered chemicals the main increases in emissions are predicted to come from the
foam manufacturing (224 Mt CO2 eq.) and refrigeration/air conditioning sectors (142 Mt CO2 eq.)
which between them contribute 62% of the predicted emissions increase. The biggest regional
increases are projected for: North America, OECD Europe, China and Japan.
Combined global abatement cost c urve s
Three global abatement cost curves for 2000, 2010 and 2020 were developed. The global abatement
cost curve for all the Non-CO2 greenhouse gases for 2020 is given in Figure 2 (abatement options with
costs above US$200/t CO2 eq. were excluded).
Abatement Costs (US$ 2000/t CO2 eq.)
250
200
150
100
50
0
0
500
1000
1500
2000
2500
3000
3500
4000
-50
Reductions (Mt CO2 eq.)
Figure 2: Cost Abatement Curve for All Non-CO2 Greenhouse Gases for 2020
The results indicate that up to 1 050 Mt CO2 eq. could be abated at costs of typically -$10 to $0/t CO2 eq.
A further 1 200 Mt CO2 equivalent could be abated at costs of up to $10/t CO2 eq. and 1 000 Mt CO2 eq.
at cost of up to $50/t CO2 eq. On a regional basis, the most significant regions with potential for costeffective abatement of Non CO2 greenhouse gas emissions in 2000 are: North America, China, South
Asia, Latin America, Rest of Asia and OECD Europe.
On an individual gas basis, the largest cost-effective reductions (costs up to $0/t CO2 eq. abated) in
emissions can be achieved through the abatement of methane emission sources, (900 Mt CO2 eq.)
followed by abatement of the engineered chemicals (150 Mt CO2 eq.). The cost-effective abatement
measures identified are summarised in Table 3 overleaf. For methane the cost-effective abatement
options come from the natural gas, waste water management and solid waste management sectors. The
abatement measures for the natural gas sector have been summarised into 5 categories in the overview,
full details of all the abatement options identified are given in the main report. For the engineered
chemical cost-effective abatement measure were identified in the semi conductor and aluminium
production industries as well in sub sectors like foam blowing, refrigeration/air conditioning, aerosols
and for fire extinguishers.
iv
Greenhouse Gas
Sub Sector
Sector
Methane
Coal mining
Natural Gas
Production,
transmission and
Distribution
Solid waste
management
Waste water
management
Engineered Chemicals
ODS Substitutes from Refrigeration and air
multiple sources
conditioning
Aerosols
Foams
Fire extinguishing
PFC emissions from Semiconductors
semiconductors
CF4 and C2 F4 from
Aluminium production
Abatement Option
Methane drainage combined with injection into a
natural gas pipeline
a) Revised maintenance procedures for gas
compressors
b) Equipment surveying to identify leaks and
direct maintenance/repairs
c) Installation of dry seals on compressors
d) Reduced glycol circulation rates in dehydrators
e) Installation of low-bleed pneumatic devices on
compressors
a) Anaerobic digestion with compost production
b) Use of landfill gas in existing boilers for heat
production
Electricity generation from recovered methane
Replacement of direct expansion systems with
distributed systems in Retail food and cold storage
Replacement of high GWP HFC based propellants
with Hydrocarbons or lower GWP HFC’s9 in Non
Metered Dose Inhalers.
Replacement of HFC blowing agents in spray
foams with CO2 /water blowing agents
Use of water mists for Class B fire hazards
Drop in C3 F8 replacement in Chemical Vapour
Deposition Cleaning Equipment
Retrofits for side worked pre-bake technologies
and centre-worked pre-bake technologies
Table 3: Summary of Cost-effective Abatement Options for the Methane and the Engineered
Chemicals
Sensitivity studies
In the development of the abatement cost curves IEA GHGs standard assessment criteria were used
(10% discount rate, natural gas price of $2/GJ etc.)10 . The sensitivity was determined of the emission
reductions to discount rate (2 to 20%) and natural gas price (-50% to 200% of base price). The
sensitivity analyses indicted that the emissions reductions for all the Non-CO2 gases were generally
insensitive to discount rate at costs above $0/t. Some sensitivity to methane emissions was observed at
low discount rates (2 and 5%) for methane emission reductions. Sensitivity to lower discount rates
would be expected for projects where there is a larger capital cost component compared to labour costs.
The abatement options identified in the methane sector all have a higher fixed capital/labour cost ratio.
Sensitivity to energy price was found for the methane abatement options, where increasing the natural
gas price, resulted in more of the methane emission reduction measures showing negative costs as could
be expected.
9
HFC-152a has a GWP of 120 which can be used to replace higher GWP HFC’s as a propellant in applications
where hydrocarbons and dimethyl ether are too flammable.
10
Since the study commenced the natural gas price in IEA GHGs standard assessment criteria has been increased
to $3/GJ.
v
Expert Group Comments
The draft report on the study was sent to a panel of expert reviewers and a number of the IEA GHG
Programme’s members who had expressed interest in reviewing it. The report was generally well received
by the reviewers. The reviewers felt the report was comprehensive and the methodology used and results
generated were presented in a transparent manner. It was also considering that bringing together the
analyses of the different gases under a common methodology in a single report was a commendable
exercise. A number of methodological, technical and editorial points were raised by the reviewers. The
consultant made best efforts to address these comments and adapt/modify the report to improve both the
clarity and the technical content.
IEA GHG would like to acknowledge the contribution made by the US EPA in making available data for
use by the consultants for the study and for their input to the review process.
Major Conclusions
IEA GHGs previous work on the Non-CO2 gases has been updated and the gases compared on a
common basis which makes the results of the study readily comparable with abatement options for CO2 .
It is felt that such abatement cost curve data generated will improve the quality of the Programme’s
Non-CO2 gas data, which is already well regarded internationally.
The study has shown that the emissions of the Non-CO2 greenhouse gases are projected to rise
significantly (from 3 800 Mt CO2 eq. in 2000 to 5 700 Mt CO 2 eq.) by 2020. Whilst the increase in
Non-CO2 greenhouse gas emissions (1 900 Mt CO2 eq.) is lower than that predicted for CO2 emissions
(10 090 Mt CO2 between 2000 and 2020 11 ), the contribution to climate change of these gases will
continue to be significant. The trend in emissions growth indicates that Asia will see the largest growth
followed by North America and OECD Europe. This trend is consistent with projections for increased
CO2 emissions which indicate that Asian emissions will grow substantially10 .
About 70% of the increase in Non-CO2 greenhouse gas emissions (1280 Mt CO2 eq.) is due to methane
and the rest due to the engineered chemicals (550 Mt CO2 eq.) By comparison, increases in emissions
of nitrous oxide from industrial operations are projected to be much less significant (68 Mt CO2 eq.).
The results indicate that up to 1 050 Mt CO2 eq. could be abated cost-effectively ( i.e. at costs of -$10 to
$0/t CO2 eq.) by 2020. A further 2 200 Mt CO2 eq. could be abated at costs of up to $50/t CO2 eq. by
2020. The cost-effective measures in particular, indicate that there are a significant number of early
opportunities for greenhouse gas abatement in the Non-CO2 greenhouse gas area.
Such early
abatement options will be attractive to many countries to meet their Kyoto commitments.
Recommendations
The agricultural sector Non-CO2 greenhouse gases were omitted from this study because it was
considered that there was currently insufficient data available to estimate abatement costs and the
impact of proposed abatement measures. It is recommended that IEA GHG maintain a watching brief
on the agricultural sector through the Non-CO2 Greenhouse Gas Network. When it is seen that
sufficient information has become available , a comparable study should be undertaken for the
agricultural sector.
11
Source: IEA World Energy Outlook, 2002.
vi
NON-CO2 MARGINAL ABATEMENT COST
CURVES FOR ENERGY, INDUSTRIAL and
WASTE MANAGEMENT SOURCES
Final Report
Prepared for
IEA Greenhouse Gas R&D Programme
Stoke Orchard
Cheltenham, Gloucestershire, GL52 4RZ
United Kingdom
Prepared by
ICF Consulting
1725 Eye Street, NW, Suite 1000
Washington, DC 20006 U.S.A.
August 2003
Executive Summary
The current study summarized and standardized currently available information on the global
methane, nitrous oxide, perfluorocarbons (PFC), hydrofluorocarbons (HFC), and sulphur
hexafluoride (SF6 ) abatement potential and produced marginal abatement cost curves (MACCs)
for twelve regions, 19 separate emission sectors (energy production and transmission, waste
management, industrial and end-use processes), and various combinations of discount rates and
energy prices. A total of 119 individual abatement options were analyzed with respect to their
technical and cost characteristics and integrated into custom-built methane/nitrous oxide and
industrial gas MACC models.
The current analysis revealed a large potential for the worldwide cost-effective abatement of
non-CO2 emissions. For example, the estimated 2010 annual cost-effective emission reductions
(with 10 percent discount rate) from all the sources covered by this study exceed 1000 million
tonnes of CO 2 equivalent (MTCO2Eq.), while the reductions under $50/tCO 2 Eq. (in constant
2000 U.S. dollars) are estimated at about 2900 MTCO2 Eq. Regio nally, the largest non-CO2
reductions under $20 per tonne of CO2 Eq. can be achieved in North America, followed by China,
OECD-Europe and Former Soviet Union (FSU) (Exhibit ES-1).
Exhibit ES-1: Combined Emission Reductions by Region at or below Different Net Specific
Abatement Costs (expressed in $/tCO2 Eq.) (Discount Rate – 10%, Year 2010)
600
500
MTCO2 Eq
400
>$100
$100
$50
300
$20
$0
200
100
0
Africa
ICF Consulting, Inc.
Australia
China
Eastern &
Central
Europe
FSU
Japan
Latin
America
Middle East
North
America
OECDEurope
Rest of Asia South Asia
i
The largest reductions can be obtained by abating emissions from methane sources, followed by
sources of engineered chemicals and sources of N2 O. Most of the potential cost effective
reductions can be achieved in the wastewater management sector, followed by solid waste
management, and the natural gas sector. The solid waste and natural gas sector lead other sectors
in the reductions that can be obtained under 20 and 50 dollars per tonne of CO2 equivalent
(Exhibit ES-2).
Exhibit ES-2: Reductions of Non-CO2 Emissions by Sector at Different Net Costs (MTCO 2Eq.)
900
800
700
MTCO2Eq
600
<$0/TCO2
<$20/TCO2
<$50/TCO2
500
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300
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100
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Key results of this analysis were obtained based on a range of assumptions on baseline
emissions, option costs and the applicability of individual options across the range of regions and
time periods. The study objective was to demonstrate the ultimate potential for future emission
reductions given the current knowledge on available abatement technologies. The MACCs
developed here do not correspond to the most “likely” or “probable” emission or technological
scenario, but instead delineate a potential “playing field” for different national and international
mitigation initiatives.
The present study should be viewed as a first step towards the comprehensive regionalized
analysis of non-CO 2 abatement potential. Its results suggest the need for more detailed
investigation of individual options and technologies at the regional and national scales.
ICF Consulting, Inc.
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Acknowledgements
ICF Consulting gratefully acknowledges the thoughtful guidance and technical insights received
from Paul Freund and John Gale of the IEAGHG Programme. We also deeply appreciate
the intellectual contributions and helpful advice offered by staff from the US Environmental
Protection Agency, especially Dina Kruger, Francisco de la Chesnaye, Casey Delhotal, Elizabeth
Scheehle, Debbie Ottinger Schaefer, and Dave Godwin. In particular, EPA’s work in refining
the analytical methodology and modelling framework used in international analyses of marginal
abatement curves for GHG mitigation, under the direction of Francisco de la Chesnaye, has been
essential for corroborating, supporting, and enlightening the work done in this project. As with
any large-scale research synthesis, we have drawn heavily on primary research performed by
many other analysts and are indebted to them for their creativity and analytic innovatio ns.
ICF Consulting, Inc.
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TABLE OF CONTENTS
1.
2.
Introduction............................................................................................................................ 1
General Methodology............................................................................................................. 3
2.1
Emission Sectors, Sources, and Regions ........................................................................ 4
2.2
Baseline Emissions ......................................................................................................... 5
2.3
Characterization of Abatement Options .......................................................................... 6
2.4
Marginal Abatement Costs and Cost Curves ................................................................ 10
3. Methane from Coal Mining ................................................................................................. 14
3.1
Baseline Emissions ....................................................................................................... 14
3.2
Abatement Options ....................................................................................................... 15
3.3
Marginal Abatement Cost Curves................................................................................. 17
4. Methane from Oil Systems................................................................................................... 19
4.1
Baseline Emissions ....................................................................................................... 19
4.2
Abatement Options ....................................................................................................... 19
4.3
Marginal Abatement Cost Curves................................................................................. 20
5. Methane from Natural Gas Production, Transmission, and Distribution ........................ 23
5.1
Baseline Emissions ....................................................................................................... 23
5.2
Abatement Options ....................................................................................................... 24
5.3
Marginal Abatement Cost Curves................................................................................. 27
6. Methane from Solid Waste Management............................................................................ 30
6.1
Baseline Emissions ....................................................................................................... 30
6.2
Abatement Options ....................................................................................................... 31
6.3
Marginal Abatement Cost Curves................................................................................. 32
7. Methane from Wastewater Management ............................................................................ 35
7.1
Baseline Emissions ....................................................................................................... 35
7.2
Abatement Options ....................................................................................................... 36
7.3
Marginal Abatement Cost Curves................................................................................. 37
8. Nitrous Oxide from Nitric Acid Production........................................................................ 38
8.1
Baseline Emissions ....................................................................................................... 38
8.2
Abatement Options ....................................................................................................... 39
8.3
Marginal Abatement Cost Curves................................................................................. 40
9. Nitrous Oxide from Adipic Acid Production....................................................................... 43
9.1
Baseline Emissions ....................................................................................................... 43
9.2
Abatement Options ....................................................................................................... 43
9.3
Marginal Abatement Cost Curves................................................................................. 44
10.
ODS Substitutes from Multiple Sources ......................................................................... 46
10.1 Baseline Emissions ....................................................................................................... 46
10.2 Abatement Options ....................................................................................................... 50
10.3 Marginal Abatement Cost Curves................................................................................. 56
11.
HFC-23 from HCFC-22 Production............................................................................... 58
11.1 Baseline Emissions ....................................................................................................... 58
11.2 Abatement Options ....................................................................................................... 58
11.3 Marginal Abatement Cost Curves................................................................................. 59
12.
CF4 and C 2 F6 from Aluminium Production ................................................................... 59
12.1 Baseline Emissions ....................................................................................................... 59
ICF Consulting, Inc.
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12.2 Abatement Options ....................................................................................................... 61
12.3 Marginal Abatement Cost Curves................................................................................. 62
13.
SF6 from Multiple Sources .............................................................................................. 64
13.1 Baseline Emissions ....................................................................................................... 64
13.2 Abatement Options ....................................................................................................... 66
13.3 Marginal Abatement Cost Curves................................................................................. 67
14.
PFC Emissions from Semiconductors ............................................................................ 70
14.1 Baseline Emissions ....................................................................................................... 70
14.2 Abatement Options ....................................................................................................... 70
14.3 Marginal Abatement Cost Curves................................................................................. 71
15.
Combined Marginal Abatement Cost Curves ................................................................. 74
15.1 Combined Methane Baseline Emissions and Marginal Abatement Cost Curves ......... 74
15.2 Combined Nitrous Oxide Baseline Emissions and Marginal Abatement Cost Curves 78
15.3 Combined Engineered Chemicals Baseline Emissions and Marginal Abatement Cost
Curves ........................................................................................................................... 82
15.4 All-GHG Baseline Emissions and Marginal Abatement Cost Curves .......................... 86
16.
Sensitivity Analysis........................................................................................................... 91
16.1 Sensitivity to Discount Rate .......................................................................................... 91
16.2 Sensitivity to Energy Price............................................................................................ 92
17.
Discussion......................................................................................................................... 93
17.1 Key Results ................................................................................................................... 93
17.2 Uncertainties and Recommendations............................................................................ 95
18.
References ........................................................................................................................ 96
Appendices: ................................................................................................................................ 100
Appendix A: Description of MACC Regions ……………………………………………… A-1
Appendix B: Description of Abatement Options ………………………………………….. B-1
Appendix C: Examples of Economic Applicability Functions …………………………….. C-1
Appendix D: Temporal Changes in Technical Applicability of Industrial Sector Options ... D-1
Appendix E: Marginal Abatement Cost Curves for 2000 and 2020. ………………………. E-1
ICF Consulting, Inc.
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Introduction
According to the Intergovernmental Panel on Climate Change (IPCC) Third Assessment
Report, non-CO2 greenhouse gases (GHGs) — CH4 , N2 O, and engineered chemicals
(halocarbons and SF6 ) — contribute up to 40 percent of the increase in radiative forcing from
pre-industrial period to the present time (IPCC, 2001a). Meanwhile, climate change
mitigation strategies that include these gases can substantially reduce the average mitigation
cost, as opposed to strategies that exclusively target carbon dioxide (CO2 ) (Reilly, et. al.,
1999). Both the importance of non-CO2 gases as global warming agents and arguably low
costs of their abatement has led to a wide range of studies on current and future emissions of
non-CO2 GHGs and corresponding abatement technologies.
During the last decade, the IEA GHG Programme (IEA GHG), the U.S. Environmental
Protection Agency (U.S. EPA), and the European Commission (EC) have conducted
comprehensive studies of non-CO2 GHG mitigation opportunities. The IEA GHG Programme
developed a series of reports on non-CO2 GHG emissions and mitigation options, including
separate assessments of methane (CH4 ), nitrous oxide (N 2 O) and engineered chemicals (IEA
GHG, 1999, 2000a, 2000b, and 2001). These reports include detailed descriptions of
abatement options, estimates of global and regional emissions, and cost-benefit analysis of
selected options. Likewise, the U.S. Environmental Protection Agency supports a number of
research projects focused on non-CO2 GHGs. Major U.S. EPA non-CO2 publications include
the 1999 Report on U.S. methane emissions and abatement options (U.S. EPA, 1999b), two
reports on baseline non-CO2 emissions in Annex I and non-Annex I countries (U.S. EPA,
2001b, 2002b), and a recent assessment of non-CO2 abatement potential in different countries
and regions (De la Chesnaye et al., 2000; U.S. EPA, 2003). Finally, the European
Commission (EC) has prepared a series of studies of the European Union non-CO2 mitigation
potential in various sectors, including industry, agriculture, and waste management (EC,
2001).
The main objective of this study is to develop an internally consistent and comprehensive
assessment of non-CO2 abatement potential and costs for different gases, sectors, and regions.
The study is based on results of previous non-CO2 mitigation studies and also includes
original research on selected sectors and abatement options (e.g., wastewater management
sector). The report preparation included an extensive clarification and standardization of data
from a wide range of sources using a set of common assumptions, including measurement
units, Global Warming Potentials (GWPs), and energy prices. The core results are presented
in a form of marginal abatement cost curves (MACCs), which show the magnitude of
reductions that can be achieved at or below a given net specific cost (expressed in 2000 US
dollars per tonne of CO2 equivalent). The report also illustrates the sensitivity of MACCs to
discount rates and energy prices and discusses key results and uncertainties.
For sources of data on baseline emissions this study relies, primarily, on recent U.S. EPA and
IEA GHG Programme reports, while most of the abatement options are characterized using
information from the referenced IEA GHG, U.S. EPA and EC studies.
The rest of this report is organized as follows:
•
Section 2 (General Methodology) explains data, methods, and assumptions used to
develop non-CO2 MACCs.
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•
Sections 3 through 14 present baseline emission, key characteristics of individual
abatement options and MACCs for the following combinations of GHGs and
emission sources:
Ø
Ø
Ø
Ø
Ø
Ø
Ø
Ø
Ø
Ø
Methane from Coal Mining;
Methane from Oil Production, Transmission, and Distribution;
Methane from Natural Gas Production, Transmission, and Distribution;
Methane from Solid Waste Management;
Methane from Waste Water Management;
Nitrous Oxide from Nitric Acid Production;
Nitrous Oxide from Adipic Acid Production;
Ozone Depleting Substances (ODS) Substitutes from Multiple Sources;
HFC-23 from HCFC-22 Production;
Tetrafluoromethane (CF4 ) and hexafluoroethane (C2 F6 ) from Aluminium
Production;
Ø Sulphur Hexafluoride (SF6 ) from Multiple Sources; and
Ø PFC Emissions from Semiconductors.
•
Section 15 (Combined Marginal Abatement Cost Curves) summarizes sectoral
baselines and MACCs.
•
Section 16 (Sensitivity Analysis) illustrates the sensitivity of MACCs to changes in
discount rates and base energy prices.
•
Section 17 (Discussion) discusses key results of the current analysis, major
uncertainties and gaps, and potential improvements.
•
Report Appendices illustrate the MACC methodology used in this report; provide
standardized descriptions of individual abatement options; and present additional
results. The Appendices section includes:
Ø
Ø
Ø
Ø
Appendix A: Description of MACC Regions
Append ix B: Description of Abatement Options
Appendix C: Examples of Economic Applicability Functions
Appendix D: Temporal Changes in Technical Applicability of Engineered
Chemicals Options
Ø Appendix E: Marginal Abatement Cost Curves for 2000 and 2020
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2.
General Methodology
Marginal Abatement Cost Curves (MACCs) presented in this report were developed for the
following range of input assumptions:
•
•
•
baseline emissions by gas, region and emission sector in the years 2000, 2010, 2020;
discount rates of 2, 5, 10, 15, and 20 percent; and
energy prices ranging from –50 to +200 percent of the base energy price
Reported MACCs display the cumulative amount of emission reductions achievable at or
below a specific GHG abatement cost expressed in constant US dollars (2000) per tonne of
carbon dioxide equivalent.
The methodology used in the report to develop MACCs for different sets of input
assumptions is a synthesis of methods used in the IEA GHG Programme, U.S. EPA, and EC
analyses (IEA GHG, 1999; EC, 2001; U.S. EPA, 2003;). This methodology integrates
analyses of the costs and benefits of mitigating the non-CO2 gases, which facilitates
comparison of abatement potentials and costs of various options across different sectors,
regions, and years.
The rest of this section presents in detail the MACC methodology adopted in this study,
including:
•
•
•
•
description of emission sectors, sources, and regions;
baseline emission estimation;
characterization of abatement options; and
method of MACC compilation.
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2.1
Emission Sectors, Sources, and Regions
Emission sectors, emission sources, and greenhouse gases (GHGs) covered by this study are
specified in Table 2.1.
Table 2.1: Emission Sectors, Emission Sources, and Greenhouse Gases
Emission Sector
Coal Mining
Oil Systems
Natural Gas Systems
Solid Waste Management
Wastewater Management
Nitric Acid Production
Adipic Acid Production
Industrial Sector High-GWP
Gases (Engineered chemicals)
Use of Ozone Depleting
Substances (ODS) Substitutes
Emission Sourcesa
Underground mines
Oil production
Natural gas production,
transmission, processing,
storage, and distribution
Landfills
Anaerobic wastewater
management
Nitric acid production
Adipic acid production
HCFC-22 Production
Aluminium Production
Magnesium Production
Electric Transmission and
Distribution
Electric GIS Manufacturing
Semiconductor Manufacturing
Refrigeration and Air
Conditioning (AC)
Foams
Non-MDI Aerosols
MDI Aerosols
Solvents
Fire Extinguishing
a
Greenhouse Gases
CH4
CH4
CH4
CH4
CH4
N2O
N2O
HFC-23
CF4 and C2F6
SF6
SF6
SF6
PFCs, HFCs, and SF6
HFC-134a and others
HFC-134a, HFC-152a, HFC245fa, HFC-365mfc
HFC-134a, HFC-152a
HFC-134a, HFC-227ea
HFC-4310mee
HFC-227ea and others
List of emission sources within each sector for which marginal abatement cost curves are developed.
Within each sector, this study analyses major emission sources (e.g., methane emissions
natural gas transmission, which are further subdivided into emissions from compressors,
pipeline leaks, etc.) and specifically focuses on emissions that can be abated using widely
available or emerging technologies.
The baseline emissions and MACCs are developed for the follo wing regions (a complete list
of countries for each region is provided in Appendix A):
v
v
v
v
v
v
Africa
Australia
Central and Eastern Europe
China
Former Soviet Union (FSU)
Japan
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v
v
v
v
v
v
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Baseline emission estimates and MACCs are also compiled for UNFCCC1 Annex I and NonAnnex I groups of countries as well as for the entire world.
2.2
Baseline Emissions
The development of GHG MACCs begins with establishing region- and source-specific
referenc e or baseline scenarios (baselines) of future emissions. The purpose of these baselines
is to determine potential emission reductions that can be achieved by a specific option in a
given year. Baselines in this report describe emissions that are expected to occur if no
additional measures (projects) to reduce emissions are implemented with respect to the
current situation. These additional measures (projects) include those implemented specifically
to reduce GHG emissions into the atmosphere (e.g., those implemented to achieve Kyoto
targets) and those implemented to meet non-climate related regulatory requirements (e.g.,
“landfill rule” in the U.S. and EU). The baselines include, however, installations of new
technologies that are unrelated to either GHG mitigation or regulatory requirements, but are
part of conventional economic development. For example, if a new currently available
technology is scheduled to replace the retired capital stock, changes in emission factors
associated with this replacement are reflected in the baselines.
In essence, the baseline methodology adopted in this study corresponds to the “frozen
abatement technology ” scenario, where the current level emission abatement is preserved for
the entire period for which emissio ns are projected 2000-2020. A similar approach to
defining baselines was adopted in the recent EU mitigation assessment (EC, 2001).
The frozen abatement technology baselines reflect the installation of mitigation options prior
to 2000 and the continued impact of these mitigation options through 2020. The installation
and subsequent use of mitigation options after 2000 are not included in the baselines. For
example, if regulations require a landfill to install a methane abatement option in the year
2005, the greenhouse gas reductions associated with this option/landfill are not reflected in
the baseline emissions.
The baseline methodology used in this study leads to marginal abatement cost curves
(MACCs) that reflect a full range of complete spectrum of new emission-reductions
opportunities, whether they are regulatory- or commercially-driven. The baselines adopted
here do not represent the most probable or most likely GHG emission scenarios, but instead
delineate a potential “playing field” for different national and international mitigation
initiatives.
Most of the baseline scenarios used in this study were obtained from the referenced literature
(e.g., IEA GHG Programme, U.S. EPA, and EC reports). If needed, these literature-based
scenarios were adjusted to reflect the frozen abatement technology assumption (e.g., in case
of CH4 emissions from U.S. landfills, reductions associated with regulations under “Landfill
1
United States Framework Convention on Climate Change.
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Rule” were not included in the baseline). Consequently, some
are higher than those used in other studies (e.g., EPA, 2003).
emissions for particular regions and/or GHGs were not readily
(e.g., wastewater management) these emissions were estimated
drivers, such as population.
resulting baseline emissions
In situations when baseline
available from the literature
based on common emission
All the non-CO2 GHG baseline emissions were converted into CO2 equivalents using the new
Global Warming Potentials (GWPs) presented by the IPCC Third Assessment Report (IPCC,
2001a).
2.3
Characterization of Abatement Options
The current study uses a common format to describe sector-specific abatement options for
non-CO2 gases (Appendix B). This format includes the following information:
•
Brief technical description;
•
State of development and current level of usage (widely- used; new; R&D phase);
•
Associated technical (and other) risks and uncertainties;
•
Potential presence in different regions, based on known barriers, constraints, and
incentives;
•
Average lifetime (years);
•
Technically feasible level of GHG emissio n abatement achieved by a given option
(Reduction Efficiency) (%); and
•
Fixed and recurring costs and cost offsets expressed in constant 2000 U.S. dollars.
The key technical characteristics of abatement options are described in Table 2.2. 2
2
The terminology used in this study is adopted from U.S. EPA (2003). The underlying concepts are the same
as those used in the IEA GHG report (1999) where the share of the baseline emissions that can be abated is
derived based on an implementation factor and an option-specific emission reduction factor. The reduction
efficiency used in the U.S. EPA (2003) study and option-specific emission reduction factor used in the IEA
GHG (1999) study have the same meaning. Similarly, the Technical Applicability from the U.S. EPA (2003)
study and imple mentation factor from the IEA GHG report (1999) both reflect the share of baseline emissions
that can be treated by a given option.
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Table 2.2: Technical Characteristics of Abatement Options a
Characteristic
Presence
Unit
Yes/No
Reduction Efficiency (RE)
%
Technical Applicability (TA)
%
Economic Applicability (EA)
%
Abatement Potential (AP)
%
Option Lifetime (L)
Years
a
Definition
A parameter determining whether a specific option is
present or absent in a given region.
The percentage of emissions that can be abated by a
given option relative to the total emissions to which this
option is applied.
The percentage of the total emissions from a particular
emission sector (e.g., underground coal mining) to
which a given option can be potentially applied based
on the sector’s technological structure. The TA is
option- and region-specific.
Economic Applicability (EA) is a share of TA that can
be realized due to economic factors. In the current
study, EA is equal to TA for non-overlapping options.
When two or more options are technically applicable to
the same source (overlapping options) their EAs are
inversely related to their net specific abatement cost
(Equation 4).
The percentage of baseline emissions that can be
reduced by an option given potential interactions with
other options. AP is calculated as the product of RE,
TA, and EA.
The average technical lifetime of an option.
– adopted from U.S. EPA, 2003.
The Reduction Efficiency (RE) of an abatement option is equal to the average percentage of
emissions from a given point source that can be abated once this option is implemented. For
example, catalytic oxidation (CO) systems applied to the vent ilation air stream of coal mines
can destroy (abate) about 98 percent of methane contained in ventilation air, so the Reduction
Efficiency of this option is equal to 98 percent.
The Technical Applicability (TA) of a given option within a specific emission sector (e.g.,
natural gas industry) is determined by the composition of emission sources in this sector. For
example, if 20 percent of natural gas industry emissions originate from compressors, then the
Technical Applicability of emission-reduction options aimed at compressors (e.g.,
replacement of compressor seals) is equal to 20 percent. In general, Technical Applicability
depends on the level of disaggregation of baseline emissions. For example, if baseline N2 O
emissions from adipic and nitric acid production were estimated and projected as an
aggregate source, then the Technical Applicability of abatement options designed for nitric
acid facilities would be equal to the share of emissions produced by these facilities.
Meanwhile, if emissions from nitric acid production were estimated separately, the Technical
Applicability of nitrous acid options vis-à-vis these baseline emissions would be equal to 100
percent. The term “Technical Applicability” in this study is similar to the “implementation
factor” term used in the IEA GHG Programme report (IEA GHG, 1999).
The Technical Applicability and Presence of methane and nitrous oxide options in this study
are kept constant from 2000 to 2020, while the Technical Applicability and Presence of some
options in the engineered chemicals sectors are assumed to change with time. The later
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assumption is associated, primarily, with a continuing process of ODS 3 phaseout, which
affects emissions of different ODS substitutes and, consequently, leads to changes in the
applicability of corresponding abatement options.
A set of options that are technically applicable to the same emission source are defined here
as “overlapping options”, while options that are technically applicable to separate emission
sources within the same sector (e.g., options aimed at compressors and at gas distribution
networks within the natural gas systems) are called “non-overlapping”. This study recognizes
two types of overlapping options: options that can be sequentially applied to the same point
source of emissions (sequential options) and options that are mutually excluding. An example
of sequential options is a set of coalmine methane abatement technologies, such as
degasification, enhanced degasification, and catalytic oxidation, which can be applied in a
sequential order at the same mine. Examples of mutually excluding options are mechanicalbiological treatment of wastes and waste treatment in anaerobic digesters. In this case,
potential methane emissions from a given quantity of waste can be abated by either the first
or the second option, but not by the two options applied in a sequential order.
The Economic Applicability (EA) of an abatement option is defined here as the percentage of
emissions from a given source that can be abated by this option based on economic
considerations. Economic Applicability is estimated with respect to emissions that can be
treated by a given option based on technological considerations (the share of these emissions
to the total baseline emissions is the option’s Technical Applicability).
Unlike the Technical Applicability, the Economic Applicability may depend on properties of
point sources of emissions (e.g., the facility size and surrounding infrastructure) and also on
macroeconomic factors, such as energy prices and labour costs. For example, the catalytic
oxidation option in the coal mining sector may only be economically applicable (feasible) at
the mines with sufficient volume and stability of the ventilation methane flow.
In order to accurately determine the Economic Applicability of a particular abatement option
the economic costs and barriers of this option need to be analyzed at a regional or local scale
and compared to those of other options that are technically applicable to the same emission
source. While detailed bottom- up studies have been conducted for some emission sectors in
the U.S. and Europe (e.g., U.S. EPA, 1999b; EC, 2001) such studies are presently unavailable
for most of other regions. Consequently, in order to maintain the integrity and compatibility
of analysis, the current study assumes that the Economic Applicability is equal to 100 percent
for non-overlapping options and is less tha n 100 percent when two or more options are
technically applicable to the same emission source (i.e., overlapping options).
This study uses a combination of Technical and Economic Applicability and also Reduction
Efficiency to determine the option’s Abatement Potential (AP), which is equal to the
percentage of sector-specific baseline emissions that can be abated by a given option in the
presence of other options. The process of estimating AP adopted here depends on the number
of options that are potentially applicable to the same emission source and the type of these
options. The explanation of estimation approaches used for non-overlapping options;
mutually excluding overlapping options; and sequential overlapping options, is presented
below.
3
Ozone Depleting Substances
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Non-Overlapping Options
The AP of non-overlapping options is equal to the product of their Technical Applicability
and its Reduction Efficiency:
AP = TA * RE
(1)
For example, if 20 percent of methane emissions in the natural gas sector originate from
compressors (TA = 0.2) and the Reduction Efficiency (RE) of the seal replacement option is
0.9 (90 percent of emissions can be abated once the option is applied), then the abatement
potential of this option (given that no other options are applied to reduce emissions from
compressors) is equal to 0.2 * 0.9 = 0.18 (18%). Consequently, the Economic Applicability
of non-overlapping options is assumed to be equal to 100 percent. This assumption reflects
the intent of this study to assess the maximum levels of abatement potential. In addition, for
most regions there is not enough data to calculate option-specific values of EA.
Sequential Overlapping Options
This study assumes that sequential overlapping options can be applied to the same emission
point source in a sequential order, which is based on either cost effectiveness (i.e., from the
most cost-effective to the least cost-effective one) or technological considerations (e.g., in the
coal mining sector, the enhanced degasification option always applies after the degasification
option). The Economic Applicability of the most cost-effective option in a set of sequential
options is assumed to be equal to 100 percent, while the Economic Applicability of the
subsequent options from the same set is assumed to be equal to the remaining shares of
emissions left after the preceding options are applied.
For example, the Economic Applicability (EA) of the three hypothetic al sequential options is
estimated as follows:
EA (1) = 100 %
(2)
EA (2) = 1 – RE (1)
EA (3) = 1 – RE (1) – {1 – RE (1)}* RE (2)
The APs of these options are determined as follows:
AP (1) = RE (1) * TA (1),
(3)
AP (2) = EA (2) * TA (2) * RE (2),
AP (3) = EA (3) * TA (3) * RE (3), respectively.
Since the options are applied in sequence to the same emission stream TA (1) = TA (2) = TA
(3).
In this study, mutually compatible overlapping options were included in the MACCs for the
coal mining, natural gas, and aluminium sectors.
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Mutually Excluding Overlapping Options
Unlike sequential options, mutually excluding options cannot be applied in a sequential order
to the same point source of emissions and need to be assigned to different portions of an
emission stream. The current study uses a cost-based approach to determining the Economic
Applicability of mutually excluding overlapping options. This approach uses a customized
function of the option’s specific abatement cost to determine its Economic Applicability. This
function was developed based on the following requirements:
§
Allow for negative, zero, and positive arguments (i.e., net specific costs);
§
Asymptotically approach 1 at minus infinity (negative costs) and 0 -- at plus infinity
(positive costs) (which ensures that more economically-effective options have higher
Economic Applicability); and
§
Provide a smooth non- linear transition when the argument changes from negative to
positive.
The following functional form was selected:
EA0 = - atan(x/k) / p +0.5,
(4)
where EA0 is the raw value of Economic Applicability of a given option; x – its net specific
cost, atan – arctangent function, p – number p, and k – a positive constant, which in this
study is equal to 10. 4 Once EA0 for all source-specific overlapping options are estimated
based on Equation (4), the final values of EA are calculated by normalizing the raw values so
that the sum of source-specific EAs is equal to one.
After EAs of mutually excluding options are determined, the AP of each option is estimated
as the product between TA, EA, RE. Examp les of applying Equations (2)-(4) to a set of
hypothetical options are provided in Appendix C.
2.4
Marginal Abatement Costs and Cost Curves
Each abatement option selected for this study has three input cost components: fixed (one
time) cost (FC), recurring (annual) cost (RC), and cost offset (CO) (Table 2.3). All three cost
components are expressed in constant U.S. dollars (2000) per unit of emissions reduced (one
tonne 5 of CO2 equivalent or one tonne of corresponding GHG). All the option costs used in
the current analysis are based on core studies conducted for the two regions: USA and
European Union (EU) and are assumed to remain constant from 2000 to 2020. Whereas,
changes in options’ costs and benefits are likely to occur in reality, resulting from
technological progress and changes in labour costs and energy prices, projecting such
changes over the next 20-year period would involve a number of assumptions, which cannot
be adequately substantiated at this time.
In order to standardize the energy prices, which were used in the core studies to calculate cost
offsets of individual options and also to make the current analysis comparable with other IEA
GHG reports, all the natural gas prices were assumed to equal 2 $US (2000) per GJ (which is
equivalent to 4.78 $/tCO2 Eq.) and all electricity prices -- to 3 cents per kWt-h. For all the cost
offsets that represent direct gas sales the specific offset (offset per tonne of CO2 Eq. reduced)
was set to 4.78 $/tCO2 Eq., while all the U.S. or EU-based cost offsets that represent
4
This value of k was not based on empirical data fitting, but rather represents a value arbitrary chosen to
develop a smooth curve. A comparison of curves based on Equation 4 with different values of k is provided in
Appendix C.
5
Tonne = metric ton
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electricity or heat sales were divided by 4 and multiplied by 3. This latter adjustment was
needed since offset calculations for most of the U.S. and EU options were based on the input
electricity price of 4 cents per kW-h.
Following an approach that was implemented in the study of methane mitigation in the
European Union (AEA Technology, 1998) and the recent U.S. EPA analysis (EPA, 2003), the
recurring cost and cost offsets were further adjusted for different regions based on regionspecific economic indicators. Recurring costs were adjusted using regional labour costs,
while cost offsets were adjusted based on energy prices (electricity or natural gas) or GDP
per capita (for non-energy offsets). Most of initial values of costs and offsets were obtained
from the bottom- up mitigation studies (e.g., U.S. EPA, EC or IEA GHG Programme reports)
and reflect average abatement costs for source regions such as EU or U.S. When a particular
option is implemented in a region other than the source region, the adjusted costs are
estimated as follows:
RC (i) = RC (j) * Xi/Xj,
(5)
CO (i) = CO (j) * Xi/Xj,
where RC and CO (i) are a recurring cost or cost offset in a target region (e.g., China);
RC and CO (j) – a recurring cost or cost offset in a source region (e.g., U.S.), and Xi and Xj –
an economic indicator in the target and source regions, respectively. This study uses the
following economic indicators for different adjustable cost components (Tables 2.3, 2.4):
§
§
§
Recurring cost (RC) – average labour cost in manufacturing for 1995-1999 as
indicated in the World Bank 1999 World Development Report (World Bank, 2000);
Energy component of cost offset (ECO) – average regional 1994-1999 energy prices
provided by the U.S. Energy Information Administration (EIA, 2002a,b); natural gas
offsets were adjusted based on natural gas prices, while electricity prices were used to
adjust electricity and heat offsets; and
Non-energy component of cost offset (NECO) – 1999 GDP per capita based on the
2001 World Bank’s World Development Indicators (World Bank, 2001a).
The labour costs and energy prices for each region were estimated as weighted averages of
country- level costs and prices. The weights were equal to the relative share of a given country
in the regional 1999 GDP (based market exchange rates; expressed in constant 1995 U.S.
dollars) (World Bank, 2001a). The use of GDP values as weights for prices and labour costs
was implemented to emphasize the importance of countries with higher GDP and potentially
larger emissions in determining the regional indicator values.
Estimating abatement costs in different regions based on scaling and weighting of costs for
the same options used in other regions is viewed here is an intermediate measure that is
required to fill existing information gaps. With only a handful of regional abatement cost
studies (performed mostly in U.S. and EU) this approach provides a consistent way of
developing the global analysis that recognizes regional differences in energy and labour
costs. In general, low labour costs in developing and transitional countries are universally
viewed as one of the key factors for developing flexible Kyoto mechanisms, such as Clean
Development Mechanism (CDM) and Joint Implementation (JI). Moreover, low energy costs
in the same countries are regarded as important impediments to implementing local
mitigation projects with energy co-benefits. The inclusion of labour- and price-based scaling
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in the current analysis makes it more realistic and useful for assessing the GHG abatement
feasibility in different regions.
Clearly, there are other factors that can increase or reduce the cost of abatement in a specific
country or region, such as a need for training, capital opportunity costs, import tariffs,
licensing, permitting, and many others. While all these factors should be considered while
preparing specific mitigation projects, their comprehensive cross-regional comparison and
quantification was not available at the time of this study.
Based on option-specific abatement costs and potential and region-specific baseline
emissions (BE), this study estimates the emission reduction (ER) that could be achieved by a
given option in a given year and the associated net specific cost (NSC) of abatement
expressed in constant U.S. dollars (2000) per tonne of CO2 equivalent or tonne of GHG. The
estimation procedure for each option and region includes the following equations (IEA GHG,
1999) (for abbreviations see Tables 2.2 and 2.3):
ER = BE * AP
(6)
NSC = [DR/(1-(1+DR)-L)] * FC + RC – CO,
(7)
where BE is baseline emissions, DR is a discount rate, and L is the option’s lifetime.
The methodology adopted in this study does not assume changes in costs or annual emission
reductions during the option’s lifetime. For example, the net specific cost of a given option
estimated for the year 2010 is based on a constant annual emission reduction and constant
recurring cost from 2010 to the end of this option’s lifetime.
Table 2.3: Cost Characteristics of Abatement Options
Characteristic
Specific Fixed (One-Time) Cost
(FC)
Unit
$/tCO2 Eq.
Specific Recurring Cost (RC)
$/tCO2 Eq.
Specific Cost Offset (CO)
$/tCO2 Eq.
Net Specific Cost (NSC)
$/tCO2 Eq.
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Definition
The one-time (fixed) cost of an abatement option
measured in US $ (2000) per metric ton of abated
emission expressed in CO2 equivalent.
The annual cost of abatement option measured in US $
(2000) per metric ton of abated emission expressed in
CO2 equivalent. For all CH4 and N2O options RCs are
adjusted for different regions based on region-specific
labour costs; for engineered chemicals options RCs are
adjusted for different regions based on region-specific
labour costs or electricity prices.
The annual non-GHG option benefit measured in US $
(2000) per metric ton of abated emission expressed in
CO2 equivalent. Specific cost offset includes two
components: energy component - ECO (e.g., electricity
generated from methane) and non-energy component –
NECO (e.g., sales of digestate from an anaerobic
digestion facility). CO is adjusted for different regions
based on region-specific energy prices (energy
component) and GDP per capita (non-energy
component).
The average net specific cost of an abatement option
measured in US $ (2000) per metric ton of abated
emission expressed in CO2 equivalent.
12
Table 2.4: Economic Indicators for Scaling Recurring Costs and Cost Offsets
Country/Region
USA
EU-15
Africa
Australia
China
Eastern and Central
Europe
FSU
Japan
Latin America
Middle East
North America
OECD Europe
Rest of Asia
South Asia
a
- World Bank, 2000
b
- World Bank, 2001a
c
- EIA, 2002a
d
- EIA, 2002b
Weighted Average
Weighted
Labour
Average
Cost/Worker in
Electricity
Manufacturing
Price (US $
from World Bank
(1995) /kWh)
(1995-1999)
(1994-1999) c,b
(US $ (1995)/yr) a,b
Source Regions
28,907
0.0411
29,209
0.0660
Target Regions
5571
0.0235
26,087
0.0487
631
0.026
2359
1445
31,687
9561
25,121
28,872
28,508
8328
1143
0.0412
0.0293
0.1455
0.0569
0.0682
0.0406
0.067
0.0552
0.0695
Weighted
Average
Natural Gas
Price (US $
(1995)/107 Kcal)
(1994-1999) d,b
1999
GDP/Capita
(US $(1995))b
112.29
154.41
30,845
25,080
127.3
125.06
69.45
5416
23,554
769
118
40.28
404.23
112.25
116.11
109.2
157.26
112.21
74.96
3209
1622
42,318
3763
1697
29,947
21,983
3037
443
The marginal abatement cost curves (MACCs) in this study are developed by rank-ordering
individual options by their net specific costs (NSC) expressed in US $ (2000)/TCO2 Eq. and
plotting these options against corresponding annual emission reductions (ERs).
In order to make the compiled MACCs available for use in other analyses, they were
converted into a tabular format, which reflects the cumulative emissions reductions that can
be achieved at or below a given NSC. For example, the following table represents a MACC
in the cost interval of up to $20/tCO2 Eq., where X1<X2<X3<X4<X5:
-$20/ tCO2 Eq.
X1
-$10/ tCO2 Eq.
X2
$0/ tCO2 Eq.
X3
$10/ tCO2 Eq.
X4
$20/ tCO2 Eq.
X5
Reductions of GHG emissions in MACC tables and charts (e.g., X1) are expressed in
MTCO2 Eq.6 per year. The MACC table format was adapted from U.S. EPA (2003) to
facilitate comparative analysis of different studies.
6
MTCO2 Eq. – million metric tonnes of CO2 equivalent.
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3.
Methane from Coal Mining
3.1
Baseline Emissions
Baseline methane emissions from coal mining (1990 – 2020) were compiled from the
following major sources:
•
•
•
Emissions and Projections of Non-CO2 Greenhouse Gases for Developed Countries 19902010 (U.S. EPA, 2001b);
Emissions and Projections of Non-CO2 Greenhouse Gases from Developing Countries:
1990-2020 (U.S. EPA, 2002); and
Most recent National Communications of Annex I and non-Annex I countries
(http://unfccc.int/resource/natcom/nctable.html).
All the coal bed methane (CBM) abatement options analyzed in this study are applicable
exclusively to underground mining emissions. The percentage of underground emissions
relative to the total emissions from coal mining was derived from historic emission data. Data
sources for major emitting regions included:
Ø China – Asian Development Bank (ADB) (1998);
Ø North America – U.S. EPA (2001a); and
Ø FSU – based on CBM emissions in Russia (Russian CBMC, 1999), Ukraine
(UNFCCC, 1997), and Kazakhstan (Kazakhstan Country Studies Program, 1995).
In line with the “frozen abatement techno logy” approach to the baseline emission estimation,
the current level of CBM utilization was assumed to stay constant from 2000 to 2020.
Table 3.1 presents the total baseline CBM emissions from coal mining in different regions
and also provides the percentage of emissions resulting from underground mining. Most of
the global CBM emissions is produced in three regions: China, North America, and FSU.
Baseline emissions from FSU mines are expected to decline from 2000 to 2020, while
emissions in China and North America are projected to increase.
ICF Consulting, Inc.
14
Table 3.1: Baseline Methane Emissions from Coal Mining (MTCO2 Equivalent) a
Region
1990
2000
2010
2020
Emissions from
Underground
Mining (%)b
100
98
100
Africa
10
10
10
10
Australia
17
20
27
30
China
202
188
246
304
Eastern and
Central Europe
36
28
27
28
91
FSU
148
82
72
60
84
Japan
2
1
1
1
100
Latin America
6
8
11
17
99
Middle East
0.3
0.3
0.2
0.2
0
North America
97
68
84
81
71
OECD-Europe
61
31
28
27
90
Rest of Asia
35
32
39
49
99
South Asia
8
11
21
40
87
Annex I
334
218
227
218
91
Non-Annex I
290
260
339
430
99
World
624
478
566
648
95
a
MTCO2 - million metric tonnes of carbon dioxide equivalent.
b
Represents percent of emissions from the coal mining sector that are from underground mining.
The estimates of baseline methane emissions in this study are generally consistent with the
values presented in the previous IEA GHG assessment (1999). The previous IEA GHG global
emission estimate for 1993 was about 467 MTCO2 , while for 2010 and 2020 it was 616 and
662 MTCO2 , respectively. 7 The differences in historic CBM emissions are explained by the
fact that the 1999 IEA GHG analysis only included emission estimates from selected
countries and excluded emissions from lignite mining (IEA GHG, 1999). The differences in
future CBM emissions can be explained by more conservative coal production outlook.
3.2
Abatement Options
The current study explores seven abatement options for the coal sector (Table 3.2). The first
four options are based on the U.S. studies (U.S. EPA, 1999b; Schultz et. al., 2001a,b; Brunner
and Schultz, 1999), while the last three – on the EC study (EC, 2001). The first two U.S.based options (C1 and C2) include degasification of coal seams with subsequent re- injection
of CBM into natural gas pipelines. All three EC-based options (C5-C7) use CBM as fuel to
generate heat and electricity (EC). The two remaining options are catalytic oxidation of
ventilation air methane (C3) and flaring (C4). This set of options covers most of the
technologies presented in the previous IEA GHG CBM mitigation assessment (IEA GHG,
1999). Some options, such as the use of degasification methane to power coal driers and the
co-firing of ventilation air methane (VAM) in boilers were not included in the current
analysis, due to the lack of data and limited use for these options.
Options C1, C2, and C3 were treated in this study as overlapping sequential options (see
Section 2, General Methodology, for definitions). Option C1 was applied first, followed by
C2 and C3. Options C1-C3 were combined into a single “package” that was treated as one
7
Based on 0.67 kg/m3 of CH4 and CH 4 GWP = 23.
ICF Consulting, Inc.
15
option when compared with options C5, C6, and C7. The C1-C3 “package ” and options C5,
C6, and C7 were assumed to be overlapping mutually excluding options, and Equation (2)
was applied to estimate their economic applicabilities (EA). Finally, option C4 (flaring) was
assumed to be applied to the 10 percent of emissions remaining after all other options were
used.
The region-specific Technical Applicability for the coal sector options was assumed to be
equal to the percentage of emissions from underground mining (Table 3.1).
Based on global average estimates, the largest emission reductions at the lowest cost can be
achieved by the “Degasification and Pipeline Injection” option (Table 3.2). Overall, the
weighted average costs of the coal sector options are fairly low due to significant offsets or
low implementation costs (Appendix B).
Table 3.2: Characteristics of the Coal Sector Abatement Options (Discount Rate is 10%)a
Id
Name
C1
Degasification and
Pipeline Injection
Enhanced
Degasification, Gas
Enrichment, and
Pipeline Injection
Catalytic Oxidation
of Ventilation Air
Methane
Flaring
C2
C3
C4
C5
Degasification and
Power Production –
A
Degasification and
Power Production –
B
Degasification and
Power Production –
C
C6
C7
RE (%)
TA
(%)b
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $(2000)
/tCO2 Eq)
Source
57
10-100
93.84
-2.16
U.S. EPA (1999b,
2003)
77
70-100
35.88
0.54
U.S. EPA (1999b,
2003)
98.5
70-100
43.45
3.61
99.99
7-10
20.20
0.49
30
70-100
37.64
2.16
EC (2001)
50
70-100
57.23
3.45
EC (2001)
70
70-100
74.30
4.50
EC (2001)
Schultz, et. al.
(2001a, 2001b)
U.S.EPA (2003)
Brunner, et. al.
(1999)
U.S.EPA (2003)
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each
region used as weights.
b
varies by region.
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3.3
Marginal Abatement Cost Curves
Marginal abatement cost curves for the coal- mining sector based on a 10 percent discount
rate are provided in Table 3.3.
Table 3.3: Marginal Abatement Cost Curves for the Coal Mining Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010,2020; Discount
Rate -10% (MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for Year 2010
7
7
7
7
7
7
18
18
18
18
18
18
167 167
167 167
167
167
(20) 8
(10)
0
Africa
Australia
China
Eastern and
Central
Europe
FSU
Japan
Latin
America
Middle East
North
America
OECDEurope
Rest of Asia
South Asia
Annex I9
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
3
5
61
0
0
0
0
0
0.19
6
10
0.7
17
43
0.74
17
43
0.74
17
43
0.74
17
43
0.74
17
43
0.74
0
0
0
0
3
0
8
0
8
0
8
0
8
0
0
0
11
45
45
45
0
0
0
0
0
0
0
0
0
0.19
0
0.19
4
9
5
37
81
118
17
26
13
142
221
363
17
26
13
142
221
363
17
26
13
142
221
363
0
0
21
World
World (% of
baseline)
0
0.2
98
0
0
20
World
0
0.19
World (% of
baseline)
0
0
150
200
>200
7
18
167
7
18
167
7
18
167
17
43
0.74
17
43
0.74
17
43
0.74
17
43
0.74
8
0
8
0
8
0
8
0
8
0
45
45
45
45
45
45
17
26
13
142
221
363
17
26
13
142
221
363
17
26
13
142
221
363
17
26
13
142
221
363
17
26
13
142
221
363
17
26
13
142
221
363
64
64
64
64
MACCs for Year 2000
305 305
305 305
64
64
64
64
64
305
305
305
305
305
64
64
64
64
64
140
64
64
64
64
MACCs for Year 2020
418 418
418 418
418
418
418
418
418
22
65
65
65
65
65
65
65
65
65
As one can see from Table 3.3, close to 50 percent of all the potential emission reductions in
the coal sector can be achieved in China, with North America and FSU being distant second
and third. The large potential abatement in China is explained by high estimated values of
8
( ) – denotes a negative value.
MACCs for Annex I are developed by summing up MACCs for North America, OECD-Europe, Japan,
Australia, and FSU.
9
ICF Consulting, Inc.
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baseline emissions and Technical Applicability (equal to the percentage of CBM from
underground mines). The latest number represents an upper side of a potential range of values
and is likely to be revised downward once a more detailed bottom- up analysis of CBM
emissions in China becomes available.
According to Table 3.3, all the abatement options in the coal sector can be implemented
within the ($10) - $10/TCO2 Eq. range. This relatively modest cost is explained by the fact
that cost offsets (based on energy sales) of coal options in most cases exceed annual costs
(Appendix B). Cost-effective emission reductions in Non-Annex I countries are about twice
as high as cost-effective reductions in Annex I countries (Table 3.3).
Figure 3.1: Option-Based 2010 MACC for the Coal Sector (at 10% Discount Rate)a
Net Specific Cost (US$(2000)/TCO2 Eq.)
$5
$4
$3
$2
$1
$0
($1)
-
50
100
150
200
250
300
350
400
($2)
($3)
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option.
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4.
Methane from Oil Systems
4.1
Baseline Emissions
Baseline methane emissions from the oil sector (1990 – 2020) were estimated by projecting
1990 emissions from the EDGAR (2003) GHG database using the oil production growth rates
from the EIA’s International Energy Outlook 2003 (EIA, 2003). The 1990 EDAGR emissions
represent the sum of emission from oil production processes, associated gas flaring and oil
handling (tankers).
Table 4.1: Baseline Methane Emissions from the Oil Sector (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
1990
2000
2010
2020
33
5
11
38
5
13
44
6
14
53
5
14
% Emissions
from Oil
Production
98
99
99
2
49
0.05
34
30
32
5
11
4
93
122
215
1
38
0.05
47
38
33
8
15
6
85
156
241
2
50
0.06
56
46
35
7
18
7
100
185
284
3
62
0.05
68
64
37
6
22
8
113
229
342
100
99
100
99
93
100
92
98
100
99
97
98
The largest emissions from the oil sector are estimated to occur in Latin America, FSU, and
Middle East (Table 4.1).
4.2
Abatement Options
Abatement options in the oil sector were quantified based on the EC study Economic
Evaluation of Sectoral Emission Reduction Objectives for Climate Change (EC, 2001). All
four EC options target methane emissions from oil production and are summarized in Table
4.2.
Technical Applicability of the oil sector options was estimated as a product of EC-based
applicability of each option to emissions from oil production (assumed to be the same for
each region) and the percentage of emissions from oil production relative to the total oil
sector emissions (Table 4.1).
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Table 4.2: Characteristics of the Oil Sector Abatement Options (Discount Rate is 10%)a
Id
Name
RE (%)
TA (%)b
Total AER in
2010
(MTCO2 Eq)
NSC
(US $ (2000)
/TCO2 Eq)
Source
O1
Flaring Instead of Venting
98
10
27.20
109.65
EC (2001)
(Offshore)
O2 Flaring Instead of Venting
98
5
13.60
4.39
EC (2001)
(Onshore)
O3 Associated Gas (vented) Mix
90
23-25
62.45
3.98
EC (2001)
with Other Options
O4 Associated Gas (flared) Mix
95
14-15
39.55
5.75
EC (2001)
with Other Options
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each region
used as weights.
b
varies by region.
Most of the reductions in the oil sector can be achieved by the low-cost option (O3) that
utilizes methane instead of venting it (Table 4.2).
4.3
Marginal Abatement Cost Curves
Most of the reductions in the oil sector can be achieved at a net cost between 0 and
$10/tCO2 Eq. across all the regions. This result is consistent with the previous IEA GHG
findings of a high economic effectiveness of associated gas utilization (IEA GHG, 1999).
The largest reductions in the oil sector can be attained in Latin America, FSU, and Middle
East regions (Table 4.3).
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Table 4.3: Marginal Abatement Cost Cur ves for the Oil Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
18
18
18
18
18
18
2
2
2
2
2
2
6
6
6
6
6
6
(20)
(10)
0
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.02
0
0
0
0
0
0
0.02
0
0.02
0.82
20
0.03
23
18
14
3
7
3
41
75
116
0
0
0
41
World
World (% of
baseline)
0
0
0.02
0
0
0
World
World (% of
baseline)
0
0
0.02
0
0
0
ICF Consulting, Inc.
0.82
20
0.03
23
18
14
3
7
3
41
75
116
0.82
20
0.03
23
18
14
3
7
3
41
75
116
0.82
20
0.03
23
18
14
3
7
3
41
75
116
150
200
>200
22
3
7
22
3
7
22
3
7
0.82
20
0.03
23
18
14
3
7
3
41
75
116
0.82
20
0.03
23
18
14
3
7
3
41
75
116
1
25
0.03
28
22
18
4
9
3
51
92
143
1
25
0.03
28
22
18
4
9
3
51
92
143
1
25
0.03
28
22
18
4
9
3
51
92
143
41
41
41
MACC for 2000
98
98
98
98
41
41
50
50
50
98
98
121
121
121
41
41
41
41
MACC for 2020
139
139
139
139
41
41
50
50
50
139
139
171
171
171
41
41
41
50
50
50
41
41
41
21
Net Specific Cost (US$(2000)/TCO2 Eq.)
Figure 4.1: Option-Based 2010 MACC for the Oil Sector (at 10% Discount Rate)a
$120
$100
$80
$60
$40
$20
$0
0
20
40
60
80
100
120
140
160
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option.
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5. Methane from Natural Gas Production, Transmission, and
Distribution
5.1
Baseline Emissions
Baseline methane emissions from the natural gas sector (1990 – 2020) were compiled from
the following major sources:
•
•
•
Emissions and Projections of Non-CO2 Greenhouse Gases for Developed Countries 19902010 (U.S. EPA, 2001b);
Emissions and Projections of Non-CO2 Greenhouse Gases from Developing Countries:
1990-2020 (U.S. EPA, 2002); and
Most recent National Communications of Annex I and non-Annex I countries
(http://unfccc.int/resource/natcom/nctable.html).
Baseline emissions for each region were further subdivided into emissions from production
and from transmission/processing/distribution in order to develop more accurate Technical
Applicability estimates for each natural gas option. The subdivision was based on the average
1990-2000
shares
of
emissions
from
natural
gas
production
and
transmission/processing/distribution estimated using the default IPCC methodology (IPCC,
1997) and EIA natural gas statistics (EIA, 2003).
Baseline emissions from the natural gas sector are summarized in Table 5.1. The largest
emissions from this sector occur in the FSU region, followed by North America, Middle East,
and Latin America.
The global combined 1990 emissions from the natural gas and oil sectors in this study (215 +
969=1184 MTCO2 ) are higher than emissions estimated by the previous IEA GHG
Programme study of the natural gas and oil sector (1082 MTCO2 10 ) (IEA Greenhouse Gas
R&D Programme, 1999). This difference is mainly explained by higher emissions from the
oil sectors, which are based on the EDGAR database (2003).
10
Recalculated based on CH4 GWP = 23
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Table 5.1: Baseline Metha ne Emissions from the Natural Gas Sector (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
1990
21
7
1
2000
24
7
2
2010
32
11
5
2020
44
18
11
32
524
1
72
85
152
41
13
21
686
283
969
23
411
2
100
150
153
44
28
37
580
401
981
29
447
2
166
224
178
47
51
79
618
652
1270
40
481
2
246
262
189
51
77
121
661
879
1540
5.2
Abatement Options
Abatement options in the na tural gas sector were quantified based on the U.S. EPA’s report
(U.S. EPA, 2003) and the EC study Economic Evaluation of Sectoral Emission Reduction
Objectives for Climate Change (EC, 2001). A total of 35 options were compiled for the
natural gas sector, of which two options were based on the EC study and the rest -- on the
U.S. EPA study (Table 5.2). The reason for the disproportional reliance on the U.S. EPA
analysis was the more detailed description of the U.S. options (most of the EC options are
technologically the same or very similar to the U.S. ones). The combination of U.S. EPA and
EC analyses provides updated information on all the options included in the previous IEA
GHG natural gas and oil mitigation study (IEA GHG, 1999).
All the natural gas options were assumed to be fully applicable in all the regions. The only
exceptions were the options applicable to reciprocating compressors (NG3, NG12, and
NG17), which are quite rare in the OECD-Europe, Eastern and Central Europe, and FSU
regions. The Technical Applicability of reciprocating compressor options was set in these
regions at a very low level of 0.1% based on the EU assessment (EC, 2001). For all other
options, the Technical Applicability was estimated as a product of U.S- or EU-based
applicability
of
each
option
to
emissions
from
production
or
processing/transmission/distribution subsectors (assumed to be the same for each region) and
region-specific percentage of emissions from these two subsectors.
ICF Consulting, Inc.
24
Table 5.2: Characteristics of the Natural Gas Sector Abatement Options (Discount Rate is 10%)a
Name b
Id
RE (%)
TA (%)c
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/TCO2 Eq)
Source
Processing and Transmission (P&T)
NG1
NG2
NG3
NG4
NG5
NG6
NG7
NG8
NG9
NG10
NG11
NG12
NG13
NG14
NG15
NG16
NG17
P&T-Altering Start-Up
Procedure during
Maintenance
P&T-Catalytic Converter
P&T-D I&M (Compressor
Stations)
P&T-D I&M (Compressor
Stations: Enhanced)
P&T-D I&M (Enhanced:
Storage Wells)
P&T-D I&M (Pipeline:
Transmission)
P&T-D I&M (Wells:
Storage)
P&T-Dry Seals on
Centrifugal Compressors
P&T-Fuel Gas Retrofit for
Blowdown Valve
P&T-Installation of Flash
Tank Separators
P&T-Portable Evacuation
Compressor for Pipeline
Venting
P&T-Reciprocating
Compressor Rod Packing
(Static-Pac)
P&T-Reducing the Glycol
Circulation Rates in
Dehydrators
P&T-Replace High-bleed
pneumatic devices with
compressed air systems
P&T-Replace high-bleed
pneumatic devices with
low-bleed pneumatic
devices
P&T-Surge Vessels for
Station/Well Venting
P&T-Use gas turbines
instead of reciprocating
engines
100
<0.5
1.64
-2.74
EC (2001)
56
5-8
41.55
16.95
U.S. EPA (2003)
13
3-5
5.76
-2.82
U.S. EPA (2003)
20
2-4
6.27
-2.62
U.S. EPA (2003)
50
<0.5
0.72
27.17
U.S. EPA (2003)
60
<0.5
0.4
709
U.S. EPA (2003)
33
<0.5
0.55
23.47
U.S. EPA (2003)
69
4-6
41.01
10.86
U.S. EPA (2003)
33
1-27
32.1
-4.16
U.S. EPA (2003)
61
0-1
2.46
4.83
U.S. EPA (2003)
72
3-4
26.77
39.1
U.S. EPA (2003)
6
1-27
2.14
11.69
U.S. EPA (2003)
30
0-1
1.72
-3.39
U.S. EPA (2003)
100
3-5
13.42
11.6
U.S. EPA (2003)
86
3-5
28.47
-0.41
U.S. EPA (2003)
50
3-4
19.35
1,919
U.S. EPA (2003)
90
0-27
19.1
22.26
EC (2001)
Production
NG18
NG19
NG20
NG21
NG22
Prod-D I&M (Chemical
Inspection Pumps)
Prod-D I&M (Enhanced)
Prod-D I&M (Offshore)
Prod-D I&M (Onshore)
Prod-D I&M (Pipeline
Leaks)
ICF Consulting, Inc.
40
1-2
2.55
31.6
U.S. EPA (2003)
50
33
33
0-1
1-2
1-3
2.58
1.98
2.54
183
14.54
150
U.S. EPA (2003)
U.S. EPA (2003)
U.S. EPA (2003)
60
1-8
16.46
15.94
U.S. EPA (2003)
25
Id
Name b
NG23
Prod-Electric Starter for
Compressors
Prod-Installation of Flash
Tank Separators
Prod-Installing Plunger Lift
Systems In Gas Wells
Prod-Portable Evacuation
Compressor for Pipeline
Venting
Prod-Reducing the Glycol
Circulation Rates in
Dehydrators
Prod-Replace High-bleed
pneumatic devices with
compressed air systems
Prod-Replace high-bleed
pneumatic devices with
low-bleed pneumatic
devices
Prod-Surge Vessels for
Station/Well Venting
NG24
NG25
NG26
NG27
NG28
NG29
NG30
RE (%)
TA (%)c
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/TCO2 Eq)
Source
75
<0.5
0.45
2,189
U.S. EPA (2003)
54
2-12
19.91
23.05
U.S. EPA (2003)
4
1-3
0.06
739
U.S. EPA (2003)
72
<0.5
0.31
39.2
U.S. EPA (2003)
31
1-3
2.91
-2.91
U.S. EPA (2003)
100
5-30
31.98
10.38
U.S. EPA (2003)
86
5-30
62.32
-0.23
U.S. EPA (2003)
50
<0.5
0.17
1,912
U.S. EPA (2003)
Distribution
NG31
NG32
D-D I&M (Distribution)
26
1-12
30.39
-0.01
U.S. EPA (2003)
D-D I&M (Enhanced:
66
1-12
56.65
10.85
U.S. EPA (2003)
Distribution)
NG33 D-Electronic Monitoring at
95
5-8
68.53
5.64
U.S. EPA (2003)
Large Surface Facilities
NG34 D-Replacement of Cast
Iron/Unprotected Steel
95
6-10
87.24
4,549
U.S. EPA (2003)
Pipeline
NG35 D-Replacement of
95
3-4
36.32
108,406
U.S. EPA (2003)
Unprotected Steel Services
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each
region used as weights.
b
Prod – production; P&T - processing and transmission; D – distribution.
c
varies by region.
As suggested by their relatively low Technical Applicability values, the natural gas sector
options described in Table 5.2 are applicable to narrowly defined emission sources within the
production, transmission and processing, and distribution subsectors.
Natural gas sector options vary greatly in their net costs, with some costs being fairly modest,
while others prohibitively high. The high costs are usually associated with relatively small
emission reductions as compared to the size of one-time investment in the underlying
technology (Appendix B).
Cost offsets in the natural gas sector are associated with the saving of natural gas through
implementation of the abatement options. In field conditions these cost offsets vary
depending on the subsector (e.g., gas saved in the distribution sector, prior to delivery to
consumers, has more value (or price per unit) than gas saved during production). However, in
ICF Consulting, Inc.
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the current analysis the gas price in different subsectors was held constant ($2/GJ or
4.78/tCO2 ) to make all the options comparable with the previous IEA GHG analyses. 11
5.3
Marginal Abatement Cost Curves
As suggested by the global MACC in Table 5.3, about 12 percent of natural gas sector
baseline emissions can be reduced cost-effectively (at 10 percent discount rate). Also, 33
percent can be reduced at a cost under $20 per tonne of CO2 equivalent.
The percentage of profitable reductions relative to the baseline emissions in this study is
substantially lower than the one projected in the previous IEA GHG assessment (12 percent
vs. 45 percent for 5 percent discount rate) (IEA GHG, 1999). This discrepancy can be
partially explained by the lower global emission reduction potential estimated at 53 percent in
the current study as compared to 75 percent in the previous IEA GHG analysis (which in turn
can be explained by different Technical Applicability assumptions). 12 Another reason for this
discrepancy is the difference of benefits that can be realized from one tonne of captured
methane. Based on the standard IEA GHG assumptions reflected in this report the price of
methane was set to $2/GJ, which translates into $109/tonne CH4 . At the same time, “profits”
listed in Annex 8 of the IEA GHG Programme report range from 34 to 8451 $/tonne CH4 ,
with most of these profits staying above $109/tonne.
Most of the reductions from the natural gas sector can be achieved in the FSU region,
followed by Middle East, North and Latin America. Annex I countries can supply more
positive-cost reductions, while Non-Annex I countries offer more cost-effective emission
reductions due to lower labour costs (Table 5.3).
11
Conversion: $2/GJ * 1.055 GJ/MBTU * 52.1 MBTU/tonne CH4 / 23 (CH 4 GWP) = $4.78/tonne CO 2 Eq.
The 1999 IEA GHG analysis has assumed uniform applicabilities of different options across the regions,
while the current analysis separately estimates the applicability of each option in each region.
12
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27
Table 5.3: Marginal Abatement Cost Curves for the Natural Gas Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
5
10
13
13
14
14
14
2
3
4
4
5
5
5
0.07
2
2
2
2
2
2
(20)
(10)
0
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.27
0
0
0
0
0
0
0.27
0
0.27
3
17
0.47
26
40
32
6
8
7
60
86
147
8
119
0.48
43
58
47
10
13
24
186
150
336
0
0
12
26
World
World (% of
baseline)
0
0.28
0
World
World (% of
baseline)
10
134
0.58
61
77
53
15
19
29
216
201
416
10
156
0.75
69
86
68
15
21
33
254
224
478
11
157
0.75
72
94
75
16
22
35
264
239
503
150
200
>200
14
5
2
14
5
2
17
6
3
11
166
0.75
72
94
75
16
22
35
273
240
513
11
168
0.76
72
96
77
17
22
35
278
242
520
11
168
0.76
73
96
77
17
22
35
278
243
521
11
168
0.76
73
96
77
17
22
35
278
243
521
14
217
1
92
123
98
23
28
45
359
308
667
40
41
41
41
52
107
33
38
40
MACC for 2000
258
316
364
382
391
397
397
397
510
0
11
26
0
0.27
0
0
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40
40
41
41
52
182
32
37
39
MACC for 2020
409
512
585
616
626
635
636
637
813
12
27
41
41
41
41
53
33
38
40
28
Net Specific Cost (US$(2000)/TCO2 Eq.)
Figure 5.1: Option-Based 2010 MACC for the Natural Gas Sector (at 10% Discount Rate)a
$200
$150
$100
$50
$0
-
100
200
300
400
500
600
($50)
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option.
ICF Consulting, Inc.
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6.
Methane from Solid Waste Management
6.1
Baseline Emissions
Baseline methane emissions from the solid waste management sector were compiled from the
following major sources:
•
•
•
Emissions and Projections of Non-CO2 Greenhouse Gases for Developed Countries 19902010 (U.S. EPA, 2001b);
Emissions and Projections of Non-CO2 Greenhouse Gases from Developing Countries:
1990-2020 (U.S. EPA, 2002); and
Most recent National Communications of Annex I and non-Annex I countries
(http://unfccc.int/resource/natcom/nctable.html).
Baseline emissions in North America and OECD-Europe regions were further adjusted by
adding back emission reductions that are expected to occur due to regulatory programs, such
as Land fill Rule in the U.S. (U.S. EPA, 2001b).
According to Table 6.1, methane emissions from the solid waste sector (landfills) are
estimated to increase in Non-Annex I countries much faster than in Annex I. While in 1990,
baseline emissions in Non-Annex I countries were much lower than emissions in Annex I
countries, by 2020 Non-Annex I baseline emissions are expected become very similar to
those in Annex I. The fastest growth in emissions is estimated to occur in China, followed by
Africa and South Asia.
Table 6.1: Baseline Methane Emissions from Landfills (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
1990
42
15
56
2000
55
16
97
2010
74
23
146
2020
101
33
214
44
81
9
74
35
254
165
33
14
568
254
822
34
85
8
85
43
247
167
40
19
557
339
896
32
92
5
100
54
272
168
50
25
592
450
1042
37
101
3
118
69
273
171
63
34
618
599
1217
The global baseline emission estimates used in the present study are fairly similar to those
reported in the 1999 IEA GHG assessment (739 MTCO2 in 1995, 970 MTCO2 in 2010, and
1418 MTCO2 in 2025) (IEA GHG, 1999). The faster increase of the baseline emissions in the
previous assessment can be attributed to the use of 1995 U.N. population projections that
assumed more rapid population growth than the current projections (U.N., 2000).
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6.2
Abatement Options
Abatement options in the landfill sector were quantified based on the U.S. EPA’s report U.S.
Methane Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions
(U.S. EPA, 1999b) and the EC study Economic Evaluation of Sectoral Emission Reduction
Objectives for Climate Change (EC, 2001). These two studies covered and updated most of
the solid waste management options presented in the previous IEA GHG analyses (IEA
GHG, 1997).
This study analyzes two main categories of solid waste management options: (1) options that
recover and utilize/oxidize (includes combustion) landfill gas, and (2) options that process
waste at facilities other than landfills. All these options except increased oxidation were
assumed to be overlapping and mutually excluding. The increased oxidation option was
applied to emissions that were left after other options had been applied because this option
produces no cost offsets and is costly in comparison with flaring. Consequently, the increased
oxidation option is unlikely to be selected as an equal alternative to the rest of solid waste
management options. In the EC analysis, increased oxidation was also applied last, after
waste diversion and landfill gas collection/utilization options (EC, 2001).
Solid waste management abatement options do not appear to have any permanent
technological barriers or limitations. Consequently, all the options were assumed to be
technically applicable to 100 percent of baseline landfill emissions in all the regions.
Two waste diversion options, paper recycling and incineration were not included in this
study. Paper recycling and waste incineration options require large upfront investments into
waste collection and processing infrastructure and certain structural adjustments in waste
management processes. Data that is needed for adequate quantification of these options in
different regions is not readily available. Also, waste incinerators raise various environmental
concerns, especially in developing countries.
According to Table 6.2, the largest reductions can be potentially achieved by options that are
low cost or cost-effective, such as Heat Production, Direct Gas Use, and Anaerobic
Digestion.
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Table 6.2: Characteristics of the Solid Waste Sector Abatement Options (Discount Rate is
10%)a
Id
Name
LF1
Anaerobic Digestion-1
(includes income from
compost)
Anaerobic Digestion-2
(includes additional cost
for waste separation)
Composting 1
LF2
LF3
LF4
LF10
Composting 2 (includes
additional cost for waste
separation)
Mechanical Biological
Treatment
Heat Production
Increased Oxidation
Direct Gas Use
(profitable at base
price)13
Direct Gas Use
(profitable above base
price)
Electricity Generation
LF11
Flaring
LF5
LF6
LF7
LF8
LF9
RE (%)
TA
(%)b
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/TCO2 Eq)
Source
95
100
107.50
(3.59)
EC (2001)
95
100
14.99
85.52
EC (2001)
100
100
30.10
43.98
EC (2001)
100
100
29.73
44.40
EC (2001)
95
100
18.45
69.32
EC (2001)
70
44
100
100
171.31
80.73
(2.51)
47.28
EC (2001)
EC (2001)
75
100
142.63
1.62
U.S. EPA (1999b,
2001a, 2003)
75
100
128.74
3.07
U.S. EPA (1999b,
2001a, 2003)
75
100
58.83
15.26
75
100
111.65
5.03
U.S. EPA (1999b,
2001a, 2003)
U.S. EPA (1999b,
2001a, 2003)
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each
region used as weights.
6.3
Marginal Abatement Cost Curves
A relatively large proportion of emission reductions in the solid waste sector can be achieved
at a negative cost (Table 6.3). Three cost-effective options include Heat Production, Direct
Gas Use (profitable at base price) and Anaerobic Digestion-1. Most of the cost-effective and
total reductions can be attained in Annex I countries.
13
Profitability of the direct gas use option depends on a landfill size.
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Table 6.3: Marginal Abatement Cost Curves for the Landfills Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
43
47
47
50
58
63
15
16
16
16
19
20
84
93
93
93
117
124
(20)
(10)
0
0
0
0
0
0
0
23
4
24
0
0
0.84
0
0
0
0
0
0
0.84
0
0.84
0
0
2
0
0
75
0
0
0
77
0
77
10
16
4
19
11
110
31
9
5
174
91
266
18
52
4
59
34
186
95
30
16
371
266
637
0
7
25
61
World
World (% of
baseline)
1
71
0
World
World (% of
baseline)
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
20
58
4
66
37
217
117
33
16
434
294
728
200
>200
63
20
124
63
20
124
63
20
124
21
58
4
66
37
217
117
33
16
435
296
731
26
74
4
75
42
234
132
37
20
489
350
839
27
78
5
85
43
237
140
42
21
506
379
885
27
78
5
85
45
240
144
42
21
513
381
894
27
78
5
85
45
240
144
42
21
513
381
895
27
78
5
85
45
240
144
42
21
513
381
895
81
85
86
86
86
234
67
70
70
MACC for 2000
549
601
630
633
723
762
770
770
770
8
26
61
0.51
76
0
6
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20
58
4
66
37
186
117
33
16
403
294
696
150
81
85
86
86
86
300
67
70
71
MACC for 2020
740
810
842
846
977
1033
1043
1043
1043
25
61
80
85
86
86
86
67
69
70
33
Net Specific Cost (US$(2000)/TCO2 Eq.)
Figure 6.1: Option-Based 2010 MACC for the Landfills Sector (at 10% Discount Rate)a
$90
$80
$70
$60
$50
$40
$30
$20
$10
$0
($10) -
200
400
600
800
1,000
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option.
ICF Consulting, Inc.
34
7.
Methane from Wastewater Management
7.1
Baseline Emissions
Historic regional emissions 1990-2000 from wastewater management were compiled from
the following major sources:
•
•
•
Emissions and Projections of Non-CO2 Greenhouse Gases for Developed Countries 19902010 (U.S. EPA, 2001b);
Emissions and Projections of Non-CO2 Greenhouse Gases from Developing Countries:
1990-2020 (U.S. EPA, 2002); and
Most recent National Communications of Annex I and non-Annex I countries
(http://unfccc.int/resource/natcom/nctable.html).
Emissions in the years 2010 and 2020 for each region (i ) (EWWi (t)) were estimated by
applying adjusted rates of future region-specific population (Pi) growth to baseline emissions
in 2000 as follows:
EWWi (t) = EWWi (2000) * P (t) / P (2000) * Ki, where
Ki = { [ EWWi (1995) / EWWi (1990) * P (1990) / P (1995) ] +
[ EWWi (2000) / EWWi (1995) * P (1995) / P (2000)] } / 2
The adjustment factor Ki ranges regionally from 0.94 to 1.07 and reflects the region-specific
ratios between changes in population and changes in wastewater-related methane emissions.
If Ki is larger than 1, then, historically, emissions grew faster than population. Regional
population projections used in this study were compiled based on United Nations data (U.N.,
2000).
Table 7.1: Baseline CH4 Emissions from Wastewater Management (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
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1990
29
1
105
2000
38
1
112
2010
49
2
117
2020
60
2
124
36
23
0
55
12
27
19
66
117
107
384
490
39
25
0
64
16
32
17
76
139
115
444
559
40
26
0
72
20
35
16
84
162
120
504
624
39
25
0
81
24
38
17
93
185
121
567
688
35
According to Table 7.1, the greatest wastewater emissions are generated in South Asia
(primarily India) and China.
The global baseline methane emissions from wastewater treatment used in this study are
substantially lower than the estimates presented in the previous IEA GHG methane mitigation
assessment (i.e., 805 MTCO2 in 1990 and 1115 MTCO2 in 2010) (IEA GHG, 1999). This
difference is explained by the fact that only some of the national- level reports used to
compile the baseline emissions in Table 7.1 include wastewater from industrial sources. If the
industrial wastewater contributes about 50 percent of the total (similar to the U.S.
proportion), than the global baseline emissions reported in this study would be similar to
those in the IEA GHG 1999 report. It should be noted that estimates of global wastewaterrelated methane emissions are subject to a great uncertainty. For example, according to the
IPCC GHG Inventory Guidelines current emissions from wastewater handling range from
690 to 920 MTCO2 (IPCC, 1997).
7.2
Abatement Options
The 1999 IEA GHG report discusses in detail several potential wastewater methane
abatement options, including composting of sludge, electricity generation from recovered
methane, switching to aerobic digestion, incineration, pyrolysis to oil, and landfilling (IEA
GHG, 1999). Electricity generation from recovered methane was the only option selected for
the current analysis. This selection was based on the extensive search for cost and technology
data across the range of existing facilities and literature sources. The electricity generation
option is the one most commonly applied in existing treatment plants in both OECD and nonOECD countries and has fairly transparent and reliable cost estimates (Appendix B).
Costs and benefits of the electricity generation option represent original estimates developed
based on a number of sources that reflect average conditions across the range of U.S.
wastewater treatment facilities (Appendix B). Costs of the electricity generation option reflect
expenditures associated with the assembly and maintenance of methane collection and
electricity generation equipment, and exclude the costs of constructing and maintaining an
entire wastewater treatment plant. The option’s capital cost per one tonne of CH4 used in this
analysis falls within the cost range from $50 to $1500/tC H4 from the previous IEA GHG
assessment (IEA GHG, 1999).
Table 7.2: Characteristics of the Wastewater Sector Abatement Option (Discount Rate is
10%)a
Id
Name
W1
Electricity
Generation from
Recovered
Methane
RE (%)
TA (%)b
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/TCO2 Eq)
Source
70
90
392.99
-3.67
Metcalf and Eddy,
1991; U.S. EPA.
1996, etc.b
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each
region used as weights.
b
additional references are provided in Appendix B.
For the purposes of this study, the wastewater management option is assumed to be
applicable to 90 percent of emissions in all the regions. This reflects the assumption that 10
ICF Consulting, Inc.
36
percent of emissions from wastewater (e.g., emissions from open wastewater pits, wastewater
discharged in rivers, and estuaries, etc.) cannot be captured and utilized.
7.3
Marginal Abatement Cost Curves
According to Table 7.3, electricity generation from recovered methane is cost-effective in all
the regions. This result is explained by relatively modest fixed and recurring costs (Appendix
B).
Table 7.3: Marginal Abatement Cost Curves for the Wastewater Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
150
MACCs for 2010
31
31
31
31
31
31
31
31
0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98
74
74
74
74
74
74
74
74
200
>200
31
0.98
74
31
0.98
74
0
0
0.11
0
0
0
0
0
0
0.11
0
0.11
25
16
0.11
45
12
22
10
53
102
75
318
393
25
16
0.11
45
12
22
10
53
102
75
318
393
0
0
63
63
World
World (% of
baseline)
0
0.1
0
World
World (% of
baseline)
Region
(20)
(10)
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
25
16
0.11
45
12
22
10
53
102
75
318
393
25
16
0.11
45
12
22
10
53
102
75
318
393
25
16
0.11
45
12
22
10
53
102
75
318
393
25
16
0.11
45
12
22
10
53
102
75
318
393
25
16
0.11
45
12
22
10
53
102
75
318
393
25
16
0.11
45
12
22
10
53
102
75
318
393
25
16
0.11
45
12
22
10
53
102
75
318
393
25
16
0.11
45
12
22
10
53
102
75
318
393
63
63
63
63
63
352
63
63
63
MACC for 2000
352
352
352
352
352
352
352
352
352
0
63
63
0
0.11
0
0
63
63
63
63
63
434
63
63
63
MACC for 2020
434
434
434
434
434
434
434
434
434
63
63
63
63
63
63
63
63
63
63
Based on the current assessment, most of the emission reductio ns in the wastewater sector
can be achieved in Non-Annex I countries, specifically in South Asia and China.
ICF Consulting, Inc.
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8.
Nitrous Oxide from Nitric Acid Production
8.1
Baseline Emissions
Baseline (1990-2020) N2 O emissions from nitric acid production were estimated for different
regions as follows:
•
Australia, North America, and OECD-Europe regions : Emissions were compiled from
the developed countries non-CO2 report (U.S. EPA, 2001b) and U.S. National
Communication to UNFCCC (UNFCCC, 2002, U.S. EPA, 2003).
•
Rest of Regions: Emissions in 1990-2000 were estimated based on the amount of
nitric acid produced in each region, assumed level of abatement, and standard
emission factors following the methodology described in the IEA GHG N2 O report
(IEA GHG, 2000a). The global amount of nitric acid produced in 2000 was updated
based on new SRI Consulting estimates (Laurient, 2001). Nitric acid production in
each region was estimated by scaling the global production proportionally to the
production of nitrogen fertilizers (FAO, 2002).
Emissions from 2000 to 2020 were estimated by applying the adjusted rates of future regionspecific population growth to 2000 baseline emissions. The estimation process was the same
as described in the IEA GHG N2 O report (IEA GHG, 2000a). 14
In comparison with the previous IEA GHG report, the current study suggests slightly lower
2000 N2O emissions from nitrous acid production: 164 vs. 182 MTCO2 per year. This
difference is explained by the fact that actual 2000 nitrous acid production (Laurient, 2001)
was lower than the projected value used in the 2000 IEA GHG (2000a) report. This
difference is maintained for the future years, with the IEA GHG N2 O report 2020 global
emission estimate equal to 215 MTCO2 versus the present study 2020 value of 203 MTCO2 .
14
As in the wastewater sector, the adjustment was based on comparative rates of growth in emissions and
population between 1990 and 2000.
ICF Consulting, Inc.
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Table 8.1: Baseline Nitrous Oxide Emissions from Nitric Acid Production (MTCO2
Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
1990
4
0.5
26
2000
2010
2020
5
1
41
6
1
52
7
1
55
8
23
1.6
4
4
25
30
7
15
57
91
148
7
18
1
4
8
21
25
8
26
47
117
164
7
16
1
5
11
23
23
9
37
47
144
190
7
16
1
5
14
25
22
10
42
48
156
203
Most of N2 O emissions from nitric acid production presently occur in Non-Annex I countries
and the gap between Annex I and Non-Annex I countries is expected to widen from 2000 to
2020.
8.2
Abatement Options
All the options for abating N2 O emissions from nitric acid production fall within a relatively
narrow cost range and are characterized by relatively high reduction efficiencies (RE) (Table
8.2). The Non-Selective Catalytic Reduction (NSCR) option (NAC7) is currently widely used
at existing facilities, while the rest of options are presently in experimental and R&D phases
(Continental Engineering, 2001). Some of the options (e.g., NAC3) are claimed to produce
additional economic benefits (e.g., increased nitrous acid production). However, none of
these benefits are assumed in the present study, due to the option’s experimental nature.
Due to the lack of information about potential technical barriers to the implementation of any
specific abatement option in the nitrous acid production sector, the Technical Applicability of
these options was set at 100 percent in all the regions. Options NAC1-NAC7 were treated in
this study as overlapping mutually excluding options, with their Economic Applicability
being the function of their net specific costs.
ICF Consulting, Inc.
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Table 8.2: Characteristics of the Nitric Acid Production Sector Abatement Options (Discount
Rate is 10%)a
Id
NAC1
NAC2
NAC3
NAC4
NAC5
NAC6
NAC7
Name
High Temperature
Catalytic Reduction
Method; Developer –
BASF
Low temperature
selective catalytic
reduction with propane
addition
Developer - ECN
High Temperature
Catalytic Reduction
Method;
Developer - Grand
Paroisse
High Temperature
Catalytic Reduction
Method;
Developer - HITK
Low Temperature
Catalytic Reduction
Method;
Developer - Krupp
Uhde
High Temperature
Catalytic Reduction
Method;
Developer - Norsk
Hydro
Non-Selective Catalytic
Reduction (NSCR)
RE (%)
TA (%)
Total AER in
2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
80
100
21.98
0.51
Kuiper
(2001)
95
100
24.89
1.19
Kuiper
(2001)
77.6
100
21.25
0.56
Kuiper
(2001)
100
100
27.33
0.59
Kuiper
(2001)
95
100
25.90
0.63
Kuiper
(2001)
90
100
24.86
0.43
Kuiper
(2001)
0.80
IEA GHG
(2000a), U.S.
EPA (2001d,
2003)
85
100
22.92
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each region
used as weights.
8.3
Marginal Abatement Cost Curves
All N2 O reductions in the nitrous acid production sector occur at a net cost between 0 and
$10/tCO2 Eq. (at 10% discount rate). Most of the reductions can be achieved in Non-Annex I
regions (Table 8.3).
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Table 8.3: Marginal Abatement Cost Curves for the Nitric Acid Production Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
150
MACCs for 2010
5
5
5
5
5
5
5
0.53 0.53 0.53 0.53 0.53 0.53 0.53
47
47
47
47
47
47
47
(20)
(10)
0
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6
14
1
4
10
20
20
8
33
63
107
169
0
0
0
89
World
World (% of
baseline)
0
0
0
World
World (% of
baseline)
6
14
1
4
10
20
20
8
33
63
107
169
>200
5
0.53
47
5
0.53
47
6
14
1
4
10
20
20
8
33
63
107
169
6
14
1
4
10
20
20
8
33
63
107
169
6
14
1
4
10
20
20
8
33
63
107
169
6
14
1
4
10
20
20
8
33
63
107
169
6
14
1
4
10
20
20
8
33
63
107
169
6
14
1
4
10
20
20
8
33
63
107
169
89
89
89
89
89
0
89
89
89
MACC for 2000
146
146
146
146
146
146
146
146
146
0
0
89
0
0
0
0
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14
1
4
10
20
20
8
33
63
107
169
200
89
89
89
89
89
0
89
89
89
MACC for 2020
181
181
181
181
181
181
181
181
181
0
89
89
89
89
89
89
89
89
89
41
Net Specific Cost (US$(2000)/TCO2 Eq.)
Figure 8.1: Option-Based 2010 MACC for the Nitric Acid Sector (at 10% Discount Rate)a
$1.40
$1.20
$1.00
$0.80
$0.60
$0.40
$0.20
$0.00
0
50
100
150
200
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option.
ICF Consulting, Inc.
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9.
Nitrous Oxide from Adipic Acid Production
9.1
Baseline Emissions
For this study, baseline 1990-2020 emissions in Australia, North America, and OECDEurope regions were compiled from the developed countries non-CO2 report (U.S. EPA,
2001b) and U.S. National Communication to UNFCCC (UNFCCC, 2002; U.S. EPA, 2003).
Historic emissions (1990-2000) for the rest of regions were based on the IEA GHG N2 O
report (IEA GHG Programme, 2000a), while future emissions in these regions were
calculated based on the average 1.75 percent per year increase suggested in the recent
industry-wide analysis (Chemical Week, 2001).
Unlike emissions from nitric acid production, emissions from adipic acid production only
occur in a few regions. The bulk of these emissions are generated in OECD-Europe and
North America (Table 9.1).
The 2000, 2010, and 2020 baseline emissions from adipic acid production used in this study
are significantly lower than those presented in the previous IEA GHG N2 O report (IEA GHG,
2000a). The downward revision of N2 O emissions from this source is explained by lower
estimates of current N2 O emissions and also by a reduced future growth assumption from
industry experts (1.75 vs. 2 percent per year).
Table 9.1: Baseline Nitrous Oxide Emissions from Adipic Acid Production (MTCO2
Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
1990
0
0
9
2000
0
0
7
2010
0
0
8
2020
0
0
9
3
0
8
0
0
17
77
4
0
97
21
118
6
0
8
5
0
8
23
9
0
38
28
66
8
0
9
6
0
10
29
10
0
48
33
81
9
0
11
7
0
14
33
12
0
56
39
95
9.2
Abatement Options
Of the two abatement options for N2 O emissions from adipic acid production, only one
(Thermal Reduction - AAC2) has documented cost estimates (Table 9.2). Another option
(Valorisation) is currently in the development phase and the correspond ing cost data are not
publicly available (Klinger, 2001).
Since the AAC2 option is currently being widely known and available, its technical
availability was assumed to be 100 percent in all the regions.
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Table 9.2: Characteristics of the Adipic Acid Production Sector Abatement Options
(Discount Rate is 10%) a
Id
Name
AAC1
Valorisation of
Nitrous Oxide
emitted by Adipic
Acid Unit
Thermal Reduction
AAC2
RE (%)
TA (%)
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
99
N/A
N/A
N/A
Klinger (2001)
IEA GHG (2000a), U.S.
EPA (2001d, 2003)
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each region
used as weights.
96
100
77.54
0.15
9.3
Marginal Abatement Cost Curves
Marginal abatement curves for the adipic acid production sector reflect the regional
distribution of baseline emissions. About 70 percent of the reductions can be achieved in
Annex I regions.
ICF Consulting, Inc.
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Table 9.3: Marginal Abatement Cost Curves for the Adipic Acid Production Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
0
0
0
0
0
0
0
0
0
0
0
0
8
8
8
8
8
8
(20)
(10)
0
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
7
0
9
5
0
10
28
10
0
54
23
78
0
0
0
96
World
World (% of
baseline)
0
0
0
World
World (% of
baseline)
>200
0
0
8
0
0
8
0
0
8
7
0
9
5
0
10
28
10
0
54
23
78
7
0
9
5
0
10
28
10
0
54
23
78
7
0
9
5
0
10
28
10
0
54
23
78
7
0
9
5
0
10
28
10
0
54
23
78
7
0
9
5
0
10
28
10
0
54
23
78
96
96
96
96
96
0
96
96
96
MACC for 2000
63
63
63
63
63
63
63
63
63
0
0
96
96
96
96
96
96
0
0
0
96
96
96
MACC for 2020
91
91
91
91
91
91
91
91
91
0
0
0
96
96
96
96
96
96
96
7
0
9
5
0
10
28
10
0
54
23
78
200
7
0
9
5
0
10
28
10
0
54
23
78
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0
9
5
0
10
28
10
0
54
23
78
150
96
96
45
10.
ODS Substitutes from Multiple Sources
10.1 Baseline Emissions
The ODS substitutes sector combines chemicals that are being introduced as substitutes for
ozone depleting substances (ODS), which are being phased out under the Montreal Protocol.
This study analyzes ODS emissions from the following sources: refrigeration and air
conditioning, aerosols (MDI15 and Non-MDI), solvents, foams, and fire extinguishing.
Baseline emission estimates (2000 – 2020) for all these sectors were obtained from the IEA
GHG 2001 report (IEA GHG, 2001). This report contains 1996, 2010, and 2020 emission
estimates for the four macro-regions (North America, Japan, Western Europe, and Rest of
World). The disaggregation of the Rest of World region into the remaining nine IEA GHG
regions was conducted in the current study using the projected regional GDPs (expressed in
constant $US 1997) from the EIA’s International Energy Outlook (EIA, 2003). The share of
emissions produced in each region was assumed to be the same as its GDP share. Emissions
in 2000 were estimated by linear interpolation between emissions in 1996 and 2010.
Resulting ODS-substitute emissions are presented in Tables 10.1 – 10.6.
Refrigeration and Air-Conditioning Systems
A number of HFCs are used in refrigeration and air-conditioning systems that, during
operation and repair, result in HFC emissions. Specifically, emissions occur during product
and equipment manufacturing, component failure, leaks and purges during operation, releases
during servicing, releases from the disposal of equipment or used refrigerant containers, and
venting of refrigerant. The use of refrigerant and air-conditioning equipment also generates
“indirect” emissions of greenhouse gases (primarily carbon dioxide) from the generation of
power required to operate the equipment.
Table 10.1: Baseline ODS Substitutes (HFC) Emissions from Refrigeration and Air
Conditioning (MTCO2 Eq.)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
15
2000
1
1
2
2010
3
2
7
2020
6
5
18
1
1
18
3
1
45
32
3
1
97
11
109
2
3
37
6
2
79
70
9
3
193
29
222
4
6
32
14
3
75
62
19
6
185
66
251
Metered Dose Inhalers
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46
According to Table 10.1, the largest emissions from refrigeration and air conditioning are in
North America and OECD-Europe, where conversion from CFC refrigerants to HFC
refrigerants has largely been completed. Over time, as CFC refrigeration and air-conditioning
equipment is replaced by HFCs in developing countries and as the sector experiences rapid
growth in these countries, the relative share of developing countries is projected to increase.
By 2020, Non-Annex I countries are projected to account for approximately 26 percent of all
emissions from this sector, while in 2000 their estimated share was 10 percent.
MDI Aerosols
Metered Dose Inhalers (MDIs) are medical devices used by individuals with asthma and
chronic obstructive pulmonary disease (COPD). HFC-propellant substitutes entered the
market as an alternative to CFC-based MDIs. HFC use in these medical devices is relatively
recent and is likely to grow as this alternative gains acceptance by the pharmaceutical
industry. Baseline emissions from MDIs are summarized in Table 10.2.
Table 10.2: Baseline ODS Substitutes (HFCs) Emissions from MDI Aerosols (MTCO2
Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
0.2
0.2
0.4
2010
1
1
2
2020
1
1
4
0.1
0.2
1
1
0.1
3
4
1
0.2
9
2
11
0.5
1
5
2
0.5
11
14
2
1
31
8
39
1
1
6
3
1
14
18
4
1
42
13
55
Table 10.2 indicates that the largest emissions from this sector occur in Annex I countries.
Industry has invested substantially into the use of HFC alternatives for MDI use, a costly
process that is still in developmental stages. This transition from CFC use to HFCs is
expected to continue to occur in this sector.
Non-MDI Aerosols
The aerosol industry still uses some quantities of HFC-152a and HFC-134a as propellants.
These gases are emitted from certain products developed by the pharmaceutical industry and
from specialty and consumer products (e.g., tire inflators, freeze spray, dust removal,
deodorants, hairspray, anti-perspirants). These HFCs began to enter the market after
developed countries began to phase out of CFCs. Baseline emissions from the non-MDIs
aerosols sector are summarized in Table 10.3.
ICF Consulting, Inc.
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Table 10.3: Baseline ODS Substitutes (HFCs) Emissions from Non-MDI Aerosols (MTCO2
Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
1
0.4
1
2010
2
1
4
2020
2
2
8
0.3
1
1
1
0.3
2
2
2
0.4
7
5
11
1
2
3
4
1
7
9
5
2
23
18
40
2
3
4
6
2
9
12
8
3
31
29
60
As shown in Table 10.3, North America and OECD-Europe regions are expected to remain
the largest emitters of HFCs from the aerosol the non-MDI aerosols sector. Some non-Annex
I regions, however, are projected to significantly increase their emissions. For example,
emissions in China are expected to grow eightfold between 2000 and 2020.
Solvents
In certain areas of the global solvents market, primarily precision cleaning end- uses,
hydrofluorocarbons (HFCs) are used for solvent applications. Baseline emissions from
solvents are summarized in Table 10. 4.
Table 10.4: Baseline ODS Substitutes (HFC) Emissions from Solvents (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
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2000
2010
2020
0
0
0
0
0
0
1
1
2
0
0
1
0
0
2
2
0
0
5
0
5
0
0
5
0
0
7
6
0
0
17
0
17
0.4
1
5
2
0.4
7
6
2
1
19
7
26
48
As indicated in Table 10.4, emissions associated with solvents are the highest in Annex I
countries primarily because HFCs are easily available to solvent users in these countries. The
highest demand of HFC-4310mee is within precision cleaning, a process requiring a high
level of cleanliness. Developing countries have relatively low emissions since HFCs are a
more costly solvent option; as Table 10.4 indicates, emissions from HFCs are not expected to
occur in Non-Annex I countries until 2020.
Foams
Hydrofluorocarbons (HFCs) are used as blowing agents during the manufacture of foams.
Most commonly used HFCs are HFC-134a and HFC-152a. Foam emission profiles depend
on the foam type (open cell or closed cell), assumptions concerning relative market growth,
and HFC use among foam types. Baseline emissions from foams are summarized in Table
10.5.
Table 10.5: Baseline ODS Substitutes (HFC-134a, HFC-245fa, HFC-365mfc) Emissions
from Foams (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
2010
2020
1
1
1
2
2
5
5
4
16
0.4
1
2
2
0.4
11
7
2
1
23
6
29
1
2
9
5
1
39
25
7
2
78
23
101
3
6
21
12
3
96
63
17
6
194
59
253
Table 10.5 indicates that the largest emitters from the foams sector are OECD-Europe and
North America. This is due to the earlier phaseout schedule developed under the Montreal
Protocol for developed countries. In the future, developing countries are expected to generate
an increasing share of HFC emissions from the foams sector according to their phase-out
schedule.
Fire Extinguishing
The principal greenhouse gases used in and potentially emitted from fire extinguishing
systems are HFC-227ea, HFC-236fa, HFC-23, and perfluoromethane (CF4 ). These high GWP
gases are substitutes for halons, ODS that have been, and in many countries are still, widely
used in fire-extinguishing applications. The majority of HFC emissions associated with fire
extinguishing come from total flooding systems, which are typically used for fixed-site
systems. Baseline emissions from fire extinguishers are summarized in Table 10.6.
ICF Consulting, Inc.
49
Table 10.6: Baseline ODS Substitutes (HFC and PFC) Emissions from Fire Extinguishing
(MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
0.3
0.2
1
2010
1
1
2
2020
2
2
6
0.2
0.3
1
1
0.2
2
2
1
0
6
3
9
1
1
4
2
1
7
7
3
1
21
10
30
1
2
4
5
1
7
7
6
2
23
22
46
As Table 10.6 indicates, the largest current sources of emissions from the fire-extinguishing
sector are North America and OECD-Europe, where the greatest number of halon systems
have been replaced by HFC systems. However, over time, as halon fire extinguishing systems
are replaced in developing countries, the large gap between the HFC emissions in developing
countries versus developed countries will be reduced.
10.2 Abatement Options
Abatement options for ODS substitute sectors are summarized in Tables 10.7 – 10.12. In
general, the technical applicability of ODS substitute sectors reflects the total emissions from
each stated end use as a percent of total baseline refrigeration and air-conditioning emissions
provided in IEA GHG (2001) report. For the leak repair and refrigerant recovery options, the
technical applicability is assumed to be 50 percent of related end-use emissions, while all
other options are assumed to be technically applicable to 100 percent of related end-use
emissions. For many options, the technical applicability varies by year due to changes in the
distribution of equipment stock by end use. The temporal changes in option-specific technical
applicability are documented in Appendix D.
In the refrigeration and air conditioning sector the following sets of options were treated in
this study as overlapping mutually excluding options – R1-R5; R6-R10; R11-13; R14-R15;
R16-R17. The remaining three options were considered to be non-overlapping.
Of all the options in this sector, the largest reductions could be achieved by the use of CO2 in
the motor vehicle air-conditioning sector (R17) and replacing direct expansion systems with
distributed systems in the retail food sector (R1 ). On average, the most cost-effective options
are replacing direct expansion systems with distributed systems in the retail food and cold
storage subsectors (Table 10.7).
ICF Consulting, Inc.
50
Table 10.7: Characteristics of Refrigeration and Air Conditioning Sector Abatement Options
by Subsector (Discount rate is 10%)a
Id
R1
R2
R3
Name
Replacing Direct
Expansion Systems
with Distributed
Systems
Ammonia
Secondary Loops
RE (%)
Total AER
in 2010
(MTCO2 Eq)
Retail Food
TA (%)b
NSC
(US $ 2000)
/tCO2 Eq)
Source
IEA GHG (2001)
100
11-31
28.64
-4.27
100
11-31
5.21
29.96
U.S. EPA (2001c)
IEA GHG (2001)
Leak Repair
U.S. EPA (2001c)
Campbell (2003)
90
6-15
7.16
4.22
IEA GHG (2001)
U.S. EPA (2001c)
R4
R5
Alternative
Systems
HFC Secondary
Loop Systems
100
11-31
7.35
20.54
100
11-31
7.71
19.25
IEA GHG (2001)
IEA GHG (2001)
U.S. EPA (2001c)
Cold Storage
R6
R7
R8
Replacing Direct
Expansion Systems
with Distributed
Systems
Ammonia
Secondary Loops
IEA GHG (2001)
100
6-27
23.21
-4.68
100
6-27
4.09
30.54
U.S. EPA (2001c)
IEA GHG (2001)
Leak Repair
U.S. EPA (2001c)
Campbell (2003)
90
3-14
5.72
4.22
IEA GHG (2001)
U.S. EPA (2001c)
R9
R10
Alternative
Systems
HFC Secondary
Loop Systems
100
6-27
5.88
20.49
100
6-27
6.01
19.81
IEA GHG (2001)
IEA GHG (2001)
U.S. EPA (2001c)
Industrial Process Refrigeration
R11
R12
Ammonia
Secondary Loops
IEA GHG (2001)
100
2-9
4.25
31.65
Leak Repair
U.S. EPA (2001c)
Campbell (2003)
90
1-5
4.14
4.22
IEA GHG (2001)
U.S. EPA (2001c)
R13
Alternative
Systems
ICF Consulting, Inc.
IEA GHG (2001)
100
2-9
6.34
20.38
51
Id
R14
Name
RE (%)
Total AER
in 2010
(MTCO2 Eq)
Domestic Refrigeration
TA (%)b
NSC
(US $ 2000)
/tCO2 Eq)
Refrigerant
Recovery
Source
Campbell (2003)
IEA GHG (2001)
95
1-3
2.26
3.97
Jiffy Lube (2003)
Robinair SPX
Corporation (2003)
R15
Use of
Hydrocarbons
100
2-7
6.79
5.06
IEA GHG (2001)
Motor Vehicle Air-Conditioning Systems
R16
Refrigerant
Recovery
Campbell (2003)
IEA GHG (2001)
95
8-34
25.22
4.09
Jiffy Lube (2003)
Robinair SPX
Corporation (2003)
R17
Use of Carbon
Dioxide
Baker (2003)
100
15-68
29.48
Campbell (2003)
153.45
IEA GHG (2001)
Other Applications
R18
Refrigerated
Transport Refrigerant
Recovery
Campbell (2003)
IEA GHG (2001)
95
4-10
13.53
4.35
Jiffy Lube (2003)
Robinair SPX
Corporation (2003)
R19
R20
Chillers/
Commercial AC Leak Repair
Residential A/C –
Leak Repair
90
0-4
4.21
4.22
90
0.2-0.5
0.77
4.22
Campbell (2003)
IEA GHG (2001)
U.S. EPA (2001c)
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each region
used as weights.
b
vary by region and by year.
Table 10.8: Characteristics of Aerosols MDI Sector Abatement Options (Discount Rate is
10%)
Id
Name
RE (%)
TA (%)
Total AER
in 2010
(MTCO2 Eq)
AMD1
Dry Powder Inhalers
(DPIs)
100
50
19.46
ICF Consulting, Inc.
NSC
(US $ (2000)
/tCO2 Eq)
Source
294.21
U.S. EPA
(2001c)
52
All three options in the aerosol non-MDI and solvent sectors were treated in this study as
overlapping mutually excluding options. All the aerosol non-MDI options are cost-effective
at 10 percent discount rate (Table 10.9).
Table 10.9: Characteristics of Aerosols Non-MDI Sector Abatement Options (Discount Rate
is 10%)
Id
ANM1
ANM2
ANM3
Name
Hydrocarbon
Aerosol Propellants
(Replacing HFC134a)
HFC-152a
(Replacing HFC134a with HFC152a)
Not In Kind (NIK)
Products (Replacing
HFCs with NIK
products)
RE (%)
TA (%)
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
100
40
5.63
-5.52
U.S. EPA
(2001c)
91
48
5.81
-2.40
100
100
28.17
-5.20
U.S. EPA
(2001c)
IEA GHG
(2001c)
U.S. EPA
(2001c)
IEA GHG
(2001)
Table 10.10: Characteristics of Solvents Sector Abatement Options (Discount Rate is 10%)
Id
Name
S1
Retrofit (Improved
Equipment and
Cleaning Processes
with Existing Solvents)
Not-In-Kind (NIK)
Technology Processes
and Solvent
Replacements
(Aqueous Cleaning)
Not-In-Kind (NIK)
Technology Processes
and Solvent
Replacements (Semiaqueous Cleaning)
Alternative Solvents
(HFEs)
S2
S3
S4
RE (%)
TA (%)
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $(2000)
/tCO2 Eq)
90
100
1.69
36.16
U.S. EPA
(2001c)
100
100
6.92
6.51
U.S. EPA
(2001c)
100
100
8.53
3.62
U.S. EPA
(2001c)
Source
UNEP (1999)
85
5
0.11
1.29
U.S. EPA
(2001c)
In the foams sector, one pairs of options (F3 and F4) were treated as overlapping mutually
excluding options, while the rest of option was modelled as non-overlapping. The technical
applicability of a given option within the foams sector was determined by the amount of
emissions from a given sector (i.e., HFC-134a from appliance sector). For example, if in a
ICF Consulting, Inc.
53
given year 20 percent of overall emissions from foams are HFC-134a emissions from
appliance foam, then the technical applicability of an abatement option aimed at appliances is
equal to 20 percent. The technical applicability for the foam sector options was determined
based on the IEA GHG engineered chemicals report (IEA GHG, 2001). The resulting
technical applicability values were further adjusted based on assumptions about future
replacement of HCFC-141b (UNEP, 1998; UNEP, 2002).
The technical applicability of the foam sector options was based on relative shares of
different emission sources in the foam sector (IEA GHG, 2001). The largest potential
abatement at the lowest average cost can be achieved by replacing HDF-245fa (or HFC365mfc) in sprays with hydrocarbons (Table 10.11).
In 2010 and 2020, 29 percent of overall foam emissions is expected to come from
polyurethane foams associated with the end uses other than appliances and sprays. HFCs
emitted from these polyurethane foams can be entirely abated by replacing HFC-134a/HFC245fa or HFC-365mfc with hydrocarbons. This abatement option is being investigated;
however, since there is no cost information publicly available, this abatement method is not
considered at this time.
Table 10.11: Characteristics of Foams Sector Abatement (Discount Rate is 10%)
Id
Name
F1
Replacing HFC-134a in
Appliances with
Hydrocarbons (HC)
F2
F3
F4
F5
a
Replacing HFC-245fa
or 365mfc in
Appliances with
Hydrocarbons (HC)
Replacing HFC-245fa
or 365mfc in Sprays
with Hydrocarbons
(HC)
Replacing HFC-245fa
or 365mfc in Spray
Foams with Water
blown in situ Carbon
Dioxide
Replacing HFC-134a
or HFC-152a in
Extruded Polystyrene
with Water blown in
situ Carbon Dioxide
RE (%)
TA (%)a
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
U.S. EPA (2001)
100
0-1
1.01
14.03
IEA GHG (2001)
UNEP (2002)
U.S. EPA (2001)
100
0-8
8.10
55.85
IEA GHG (2001)
UNEP (2002)
U.S. EPA (2001)
100
0-25
20.85
-2.55
IEA GHG (2001)
UNEP (2002)
U.S. EPA (2001)
100
0-25
4.47
24.33
IEA GHG (2001)
UNEP (1998,
2002)
IEA GHG (2001)
100
37-100
37.46
0.00
UNEP (1998,
2002)
vary by year.
The two options in the fire extinguishing sector were modelled here as non-overlapping as
they are applied to different types of fire extinguishing systems (Appendix B). Another
potential option in the fire extinguishing sector -- Leak Reduction and Recovery of HFC
Total Flooding Systems – is assumed to be practiced in the baseline scenario, and therefore is
ICF Consulting, Inc.
54
not included in the MACC. The rationale for this decision is based on the premise that
responsible halon management practices are standard convention in fire protection throughout
the world, and thus, the infrastructure (i.e., equipment and training) is already in place for
responsible management of HFCs.
Table 10.12: Characteristics of Fire Extinguishing Sector Abatement Options (Discount Rate
is 10%)
Id
Name
FE1
Inert Gas
Systems
FE2
a
RE
(%)
TA
(%)a
Total AER in
2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
100
15-65
10.32
110.82
100
1-4
0.72
-38.23
Source
IEA GHG (2001)
U.S. EPA (2001c)
Water Mist
IEA GHG (2001)
U.S. EPA (2001c)
vary by year.
The technical applicability of the fire extinguishing sector options varies by year and by
option as follows:
•
•
Water mist: This option is assumed to only be used in Class B (total flooding)
applications, where Class B fire hazards are assumed to account for an estimated 5
percent of total flooding markets, and where total flooding emissions are assumed to
account for 80 percent of total baseline emissions from this sector (U.S. EPA, 2001c).
However, as there are still technical constraints associated with this option that are
assumed to be resolved over time, the technical applicability of this option is assumed
to gradually inc rease to reach its maximum potential in 2020. Specifically, it is
assumed that this option can penetrate 1 percent of total flooding markets in 2000; 3
percent in 2010; and 5 percent in 2020. Thus, the TA for this option varies by
(1) assumed temporal changes and (2) the percent of the fire extinguishing market that
constitutes total flooding systems.
Inert gas : Because inert gas systems can most feasibly be used in new (as opposed to
existing) fire extinguishing systems, the technical applicability of this option is
assumed to gradually increase over time, as old systems are replaced and new systems
installed. Specifically, inert gas is assumed to be technically feasible in 20, 45, and
85 percent of Class A (total flooding) fire hazards in 2000, 2010, and 2020,
respectively. Based on U.S. EPA (2001c), Class A fire hazards are assumed to
represent 95 percent of the total flooding sector, and total flooding systems are
assumed to account for 80 percent of baseline emissions from the total fire
extinguishing sector.
The Technical Applicability of both options in the fire extinguishing sector was estimated in
accordance with assumed baseline emissions in the IEA GHG study (2001).
The Water Mist option is far more economic than the Inert Gas Systems option. Its abatement
potential, however, is lower due to limited technical applicability (Table 10.12).
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10.3 Marginal Abatement Cost Curves
Regional and Global MACCs for the ODS substitute six sectors are summarized in Table 10.13.
Most of the reductions can be achieved in the North America region followed by OECD-Europe.
Globally, cost-effective reductions comprise close to 21 percent of the baseline emissions.
Table 10.13: Aggregated Margin al Abatement Cost Curves for the ODS Substitute Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate – 10%
(MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
5
5
5
5
5
6
4
4
5
5
5
5
11
12
13
14
14
14
(20)
(10)
0
0
0
0
0
0
0.05
2
2
5
0.01
0
0
0.05
0
0
0.17
0.07
0
0.18
0.12
0.3
0.01
0.02
12
0.05
0.01
0.17
0.17
0.07
0
13
0.19
13
1
2
17
6
2
15
31
9
3
69
27
96
3
5
35
10
3
76
67
14
4
189
47
236
0
3
21
52
World
World (% of
baseline)
0.03
2
0
World
World (% of
baseline)
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
3
6
41
12
3
97
79
17
5
229
54
284
200
>200
6
5
14
6
5
15
6
5
16
3
6
41
12
3
100
83
17
5
238
55
293
3
6
42
12
3
100
83
17
5
239
56
294
3
6
44
13
3
103
85
17
5
247
58
305
4
6
44
13
3
103
85
18
5
247
59
306
4
7
47
14
4
113
95
20
6
271
64
335
4
7
50
15
4
118
104
21
6
289
68
357
65
67
68
68
68
19
55
63
65
MACC for 2000
100
103
109 110
110
111
111
146
152
1
11
57
0.78
11
0
2
ICF Consulting, Inc.
3
5
39
11
3
83
67
15
4
201
49
250
150
63
64
64
64
64
147
59
62
63
MACCs for 2010
366
385
435 450
451
477
482
510
542
21
53
65
69
69
70
70
56
63
65
56
Net Specific Cost (US$(2000)/TCO2 Eq.)
Figure 10.1: Option-Based 2010 MACC for ODS Substitutes from Multiple Sources (at 10%
Discount Rate)a
$350
$300
$250
$200
$150
$100
$50
$0
($50)
0
50
100
150
200
250
300
350
400
($100)
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region. Each
point represents a single option.
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11.
HFC-23 from HCFC-22 Production
11.1 Baseline Emissions
Trifluoromethane (HFC-23) is a byproduct generated and emitted during the production of
chlorodifluoromethane (HCFC-22). HCFC-22 is used in refrigeration and air-conditioning
systems and as a chemical feedstock for manufacturing synthetic polymers. Baseline HFC-23
emissions from HCFC-22 production (2000 – 2020) were derived from the IEA GHG Report
(IEA GHG, 2001). The regional disaggr egation of the “Rest of World” emissions from this
report was conducted based on 1999 HCFC-22 production data (Oberthur, S., 2001) (Table 11.1)
Table 11.1: Baseline HFC-23 Emissions from HCFC-22 Production (MTCO2 Equivalent)
Region
Afric a
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
0
0
4
2010
0
0
7
2020
0
0
7
0
0.4
13
3
0
29
28
3
1
71
11
82
0
1
4
4
0
9
9
4
2
23
17
40
0
1
2
4
0
5
5
4
2
12
17
29
As indicated in Table 11.1, production of HCFC-22 in developed countries is estimated to
decrease sharply based on the phase-out schedules developed under the Montreal Protocol. In
developing countries, emissions are assumed to increase from 2000 to 2010 and stay constant
afterwards (IEA GHG, 2001).
11.2 Abatement Options
A single abatement option for the HCFC-22 Production sector is described in Table 11.2.Table
11.2: Characteristics of HCFC-22 Production Sector Abatement Options (Discount Rate is 10%)a
Id
H1
Name
Thermal Oxidation
RE (%)
TA (%)
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
95
100
36.23
0.29
IEA GHG,
2001
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each region
used as weights.
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11.3 Marginal Abatement Cost Curves
According to Table 11.3, North America, OECD- Europe, and China, as largest emitters of
HFC-23, also have the largest mitigation potential. All the HFC-23 emissions can be reduced
at a cost below $10 per tonne of CO2 Eq.
Table 11.3: Marginal Abatement Cost Curves for the HCFC-22 Production Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
(20)
(10)
0
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
0
0
0
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
0
0
0
0
0
0
0
0
0
0
0
0
7
7
7
7
7
7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.56
4
4
0
9
9
4
0
22
14
36
0
0
0
90
World
World (% of
baseline)
0
0
0
World
World (% of
baseline)
Region
12.
0
0.56
4
4
0
9
9
4
0
22
14
36
>200
0
0
7
0
0
7
0
0
7
0
0.56
4
4
0
9
9
4
0
22
14
36
0
0.56
4
4
0
9
9
4
0
22
14
36
0
0.56
4
4
0
9
9
4
0
22
14
36
0
0.56
4
4
0
9
9
4
0
22
14
36
90
90
90
90
90
0
90
90
90
MACC for 2000
76
76
76
76
76
76
76
76
76
0
0
93
93
93
93
93
93
0
0
0
93
93
93
MACC for 2020
26
26
26
26
26
26
26
26
26
0
0
0
88
88
88
88
88
88
88
0
0.56
4
4
0
9
9
4
0
22
14
36
200
0
0.56
4
4
0
9
9
4
0
22
14
36
88
0
0.56
4
4
0
9
9
4
0
22
14
36
150
88
CF4 and C 2F6 from Aluminium Production
12.1 Baseline Emissions
Two perfluorinated compounds (PFCs), tetrafluoromethane (CF4 ) and hexafluoroethane
(C 2 F6 ), are produced during primary aluminium production. Baseline CF4 and C2 F6 emissions
from the aluminium production sector were compiled from the following major sources:
ICF Consulting, Inc.
59
•
•
•
Greenhouse Gas Emissions from the Aluminium Industry (IEA GHG Programme,
2000b);
International Aluminium Institute survey (IAI, 2001); and
European Aluminium Association (Nordheim, 1999).
For all aluminium producing regions, except OECD-Europe, Eastern Europe, and the Former
Soviet Union, historical aluminium production estimates for 2000 were obtained from
International Aluminium Institute surveys (IAI, 2001). Aluminium production estimates in
OECD-Europe, Eastern Europe and FSU for 2000 were obtained from the European
Aluminium Association (Nordheim, 1999). Regional- level, technology-specific production
projections for 2000 through 2020 were obtained from Greenhouse Gas Emissions from the
Aluminium Industry (IEA GHG Programme, 2000b).
CF4 and C2 F6 emission factors from primary aluminium production were estimated using the
Intergovernmental Panel for Climate Change (IPCC) Tier 2 methodology (IPCC, 2000). The
PFC emission factors were held constant at 2000 levels through 2020. Baseline emissions
from the aluminium production sector are summarized in Table 12.1.
Table 12.1: Baseline CF4 and C2 F6 from Aluminium Production (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
6
3
4
2010
8
4
7
2020
12
4
8
3
11
0.1
7
0.4
13
11
1
1
37
22
60
4
12
0.1
10
3
16
14
1
1
45
34
79
4
12
0.1
13
6
18
14
1
2
49
45
94
As indicated in Table 12.1, the world PFC emissions from the aluminium production sector in
2000 are estimated at 60 MTCO2 Eq. The largest emissions from the aluminium production
sector occur in the North American region, followed by the OECD-Europe region. PFC
emissions are dependent on the type of cell technology prevalent in a specific region (e.g.,
vertical stud Soderberg cells typically emit more PFC’s per tonne of aluminium produced
compared to centre-worked prebake cells). The regional distributions of cell technology type
(i.e., vertical/horizontal stud Soderberg, and centre/side-worked/point-fed prebake) are the
result of aluminium capacity expansion in different periods. For example, recent capacity
expansion in regions such as the Middle East have relied on point-fed prebake cells, which
are the best currently available technology.
The baseline emissions projections in this study differ to that reported by the previous IEA
GHG Programme study (e.g., 45, and 36 MTCO2 Eq. for 2010 and 2020, respectively) (IEA
GHG, 2000b). This study utilizes updated country-specific production data from the
ICF Consulting, Inc.
60
International Aluminium Institute, as well as PFC emission factors that are held constant
from 2000 through 2020. In the previous IEA GHG study, emissions forecasts under a
business-as-usual scenario assumed a decline in emission factors through 2020 to account for
additional efficiency improvements.
12.2 Abatement Options
Fixed costs for the aluminium sector options were estimated for each type of smelter cell
technology. As anode effects are reduced through the implementation of abatement options,
there is a corresponding increase in the quantity of aluminium produced, which has an
associated incremental operating cost above the level that is expected to occur should no
abatement option be applied. Country-specific operating costs were determined by applying
this incremental operating cost associated with each option to the regional cost to produce a
tonne of aluminium, as described in Greenhouse Gas Emissions from the Aluminium Industry
(IEA GHG, 2000b). Cost offsets for aluminium options are associated with the incremental
production of aluminium due to the reduction in anode effects (Appendix B). The four pairs
of aluminium sector abatement options applied to different production technologies (A1&A5;
A2&A6; A3&A7, A4&A8) were modelled as four non-overlapping groups of options.
Options within each pair were treated as overlapping sequential options with major retrofits
applied after minor retrofits are competed.
Table 12.2: Characteristics of CFC-23 CF4 and C2 F6 from Aluminium Production Sector
Abatement Options (Discount Rate is 10%) a
Id
Name
RE (%)
TA
(%)b
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
AL1
Major Retrofit for Vertical
Stud Soderberg
11
0-100
2.43
47.61
IEA GHG (2000)
Technologies
AL2
Major Retrofit for
Horizontal Stud Soderberg
13
0-83
0.61
52.15
IEA GHG (2000)
Technologies
AL3
Major Retrofit for SideWorked Prebake
4
0-100
1.16
-16.17
IEA GHG (2000)
Technologies
AL4
Major Retrofit for CentreWorked Prebake
4
0-79
0.32
1.42
IEA GHG (2000)
Technologies
AL5
Minor Retrofit for Vertical
Stud Soderberg
42
0-100
9.26
-0.55
IEA GHG (2000)
Technologies
AL6
Minor Retrofit for
Horizontal Stud Soderberg
17
0-83
0.78
4.88
IEA GHG (2000)
Technologies
AL7
Minor Retrofit for SideWorked Prebake
21
0-100
6.16
-6.90
IEA GHG (2000)
Technologies
AL8
Minor Retrofit for CentreWorked Prebake
21
0-100
1.72
-12.26
IEA GHG (2000)
Technologies
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each region
used as weights.
b
vary by region and by year.
ICF Consulting, Inc.
61
The change in technical applicability from 2000 through 2020 for the cell technology-specific
abatement options reflect changes in the regional distributions of cell technology type, due to
differing regional rates of capacity expansion (IEA GHG, 2000b).
12.3 Marginal Abatement Cost Curves
The largest reductions of PFC emissions from the aluminium sector can be achieved in the
largest aluminium producing countries – FSU, North America, OECD- Europe, and China.
Most of the reductions can be obtained under $10 per tonne of CO2 Eq. (Table 12.3).
Table 12.3: Marginal Abatement Cost Curves for the Aluminium Production Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
(20)
(10)
0.27
0.55
0
1
0.55
0.09
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
0
10
20
30
40
50
100 150
MACCs for 2010
2
2
2
2
2
2
2
2
0.55 0.55 0.55 0.55 0.55 0.55 0.55 0.55
2
2
2
2
2
3
3
3
0
0
0
0.2
0.21
0.19
0
0
0
0.74
0.68
1
0.13
0.08
0
2
0.21
0.19
0
0.2
0.08
0.94
3
4
0.81
0.47
0
2
0.21
2
0
0.2
0.31
4
7
11
2
6
14
World
World (% of
baseline)
1
3
8
2
5
13
World
2
6
World (% of
baseline)
2
6
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
ICF Consulting, Inc.
0.92
4
0.01
2
0.21
3
3
0.23
0.36
11
7
19
0.92
4
0.01
2
0.21
3
3
0.23
0.36
11
7
19
>200
2
0.55
3
2
0.55
3
0.92
4
0.01
2
0.21
3
3
0.23
0.36
12
8
20
0.95
5
0.01
2
0.21
4
3
0.23
0.42
13
8
22
0.95
5
0.03
2
0.21
4
3
0.23
0.44
14
9
22
0.95
5
0.03
2
0.21
4
3
0.23
0.44
14
9
22
0.95
5
0.03
2
0.21
4
3
0.23
0.44
14
9
22
0.95
5
0.03
2
0.21
4
3
0.23
0.44
14
9
22
24
24
24
MACC for 2000
15
15
15
25
27
28
28
28
28
15
17
18
18
18
18
26
29
30
30
30
30
14
25
25
25
MACC for 2020
22
22
23
23
25
26
26
26
26
14
24
25
27
28
28
28
28
24
0.92
4
0.01
2
0.21
3
3
0.23
0.36
12
7
19
200
24
62
Net Specific Cost (US$(2000)/TCO2 Eq.)
Figure 12.1: Option-Based 2010 MACC for CFC-23, CF4 and C2 F6 from Aluminium
Production (at 10% Discount Rate)a
$60
$50
$40
$30
$20
$10
$0
($10)
-
5
10
15
20
25
($20)
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option.
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13.
SF6 from Multiple Sources
13.1 Baseline Emissions
Emissions of SF6 are associated with the following key sources: magnesium production;
electric transmission and distribution; and manufacture of electric gas insulated switch (GIS)
gear. Estimates of baseline emissions and MACCs for each of these sources are provided
below.
Magnesium Production
Sulphur hexafluoride (SF6 ) is used in magnesium production and processing as a cover gas to
prevent the violent oxidation of molten magnesium in the presence of air. Baseline SF6
emissions from the magnesium production sector (2000 – 2020) were obtained from the
previous IEA GHG Report (2001). Emissions were disaggregated by region based on USGS
county-specific projections of magnesium production (USGS, 1998-2001) (Table 13.1).
Table 13.1: Baseline SF6 Emissions from Magnesium (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
0
0
6
2010
0
3
8
2020
0
6
17
0
3
3
1
2
13
4
0
0
23
9
31
0
3
4
1
2
17
6
0
0
33
10
43
0
7
12
1
4
30
16
0
0
71
22
93
The largest emissions from the magnesium production sector occur in the North American
region, which is explained by large production capacities, and primary use of SF6 , as opposed
to alternate cover gas compounds.
Electric Transmission and Distribution
Sulphur hexafluoride, due to its arc-quenching characteristics and dielectric strength, is used
as an insulating gas in high- voltage switchgear, circuit breakers and gas insulated substations.
Fugitive SF6 emissions occur through leaky equipment seals, and during the service and
maintenance of equipment.
Baseline SF6 emissions from the electric transmission and distribution sector (2000 – 2020)
were obtained from the previous IEA GHG Report (2001). Emissions were disaggregated by
region based on county-specific projections of electricity production (EIA, 2001) (Table
13.2).
ICF Consulting, Inc.
64
Table 13.2: Baseline SF6 Emissions from Electric Transmission and Distribution (MTCO2
Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
1
0.4
3
2010
1
0.3
3
2020
1
0.3
4
1
2
4
2
1
3
3
2
1
13
9
23
1
1
4
2
1
2
3
2
1
10
9
19
1
2
4
2
1
2
3
2
1
11
12
23
The largest emissions from the electric transmission and distribution sector in 2000 occurred
in Japan and North America, followed by OECD-Europe and China. By 2020, China and
Japan are expected to become main emitters from this source.
Manufacture of Electric Gas Insulated Switch (GIS) Gear
Due to its arc-quenching characteristics and temperature reducing properties, sulphur
hexafluoride is used as an insulating gas in high voltage gas- insulated equipment. Fugitive
SF6 emissions occur during the manufacture and testing of this equipment.
Baseline SF6 emissions from the electric GIS gear sector (2000 – 2020) were obtained from
the previous IEA GHG Report (2001). Emissions were disaggregated by region based on
county-specific projections of electricity production (EIA, 2001) (Table 13.3).
ICF Consulting, Inc.
65
Table 13.3: Baseline SF6 Emissions from Electric Gas Insulated Switch Gear (GIS)
Manufacture (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
0
0
2
2010
0
0
1
2020
0
0
2
0
0
7
0
0
0.3
4
0
0
11
2
13
0
0
4
0
0
0.2
4
0
0
8
1
10
0
0
4
0
0
0.2
4
0
0
8
2
10
Japan is estimated to be the largest source of SF6 emissions from electric switchgear,
followed by OECD- Europe.
13.2 Abatement Options
Abatement options for SF6 emission sectors are presented in Tables 13.4 – 13.6.
The technical applicability of the magnesium sector option increases from 70 percent in 2010
to 90 percent in 2020 (this option was not available in 2000), reflecting both the rise in
magnesium casting (i.e., resulting from increased use of cast parts as vehicle components to
reduce weight and fuel consumption) and increased use of SO2 cover gas technology, as
process feed systems and pollution control technology are improved (IEA GHG, 2001)
(Appendix D).
Although recent research has identified fluorinated species, such as Novec-612™ and HFC134a (Tranell et al., 2001, Bartos, 2003) as potential replacement cover gases, these options
have not been modelled in this magnesium sector analysis due to the limited availability of
accurate cost data.
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Table 13.4: Characteristics of Magnesium Sector Abatement Options (Discount Rate is 10%)a
Id
MG1
Name
Sulphur Dioxide
(SO2) – Alternate
Cover Gas
RE (%)
TA (%)b
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
100
0-90
30.00
0.74
IEA GHG
(2001)
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each region
used as weights.
b
- vary by year.
In the electric transmission and distribution sector, increasing electricity demand is likely to
result in the expansion of electric grid systems, particularly in developing regions.
Additionally, since the use of SF6 leak detection and recovery techniques are becoming
standard gas handling practices, their applicability within the electric transmission and
distribution sector will likely increase through 2020 (IEA GHG, 2001).
Table 13.5: Characteristics of Electric Transmission and Distribution Sector Abatement
Options (Discount Rate is 10%)
Name
RE (%)
TA (%)a
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
Leakage Reduction
and Recovery
100
30-60
5.78
3.64
IEA GHG
(2001)
Id
ET1
a
– vary by year
Table 13.6: Characteristics of Electric Gas Insulated Switch Gear (GIS) Manufacture Sector
Abatement Options (Discount Rate is 10%)
Id
Name
EG1
Improved SF6
Recovery
a
– vary by year
RE (%)
TA (%)a
Total AER in
2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
100
30-60
2.88
0.73
IEA GHG
(2001)
An increase in the technical applicability of the GIS option between 2000 and 2020 reflects
the growth of GIS manufacture as well as the increasing use of improved recovery techniques
(Appendix D) (IEA GHG, 2001).
13.3 Marginal Abatement Cost Curves
Marginal abatement cost curves for the SF6 options are based on the sum of abated emissions
for all three SF6 emission sources described above. Most of the reductions can be achieved in
the North America, China, and OECD-Europe. All the reductions have a net specific
abatement cost of under $10 per US (2000) (Table 13.7).
ICF Consulting, Inc.
67
Table 13.7: Aggregated Marginal Abatement Cost Curves for the SF6 Sources
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
(20)
(10)
0
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
World
World (% of
baseline)
0
0
0
World
World (% of
baseline)
ICF Consulting, Inc.
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100 150
MACCs for 2010
0.22 0.22 0.22 0.22 0.22 0.22 0.22
2
2
2
2
2
2
2
7
7
7
7
7
7
7
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
200
>200
0.22
2
7
0.22
2
7
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
0.24
3
5
0.92
1
12
6
0.49
0.25
29
10
39
54
54
54
54
54
54
0
54
54
54
MACC for 2000
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
MACC for 2020
104 104
104
104
104
104
104
104
104
0
82
82
82
82
82
82
82
82
82
68
Net Specific Cost (US$(2000)/TCO2 Eq.)
Figure 13.1: Option-Based 2010 MACC for SF6 Sources (at 10% Discount Rate)a
$4
$3
$2
$1
$0
0
10
20
30
40
50
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option.
ICF Consulting, Inc.
69
14.
PFC Emissions from Semiconductors
14.1 Baseline Emissions
The semiconductor manufacturing process results in PFC emissions from plasma etching
(roughly 30% of emissions) and chemical vapor deposition (CVD) chamber cleaning (70% of
emissions). The baseline 2010 and 2020 emissions from this sector in the North American
region were obtained from the previous IEA GHG Programme Report (IEA GHG, 2001). The
2000 emissions were estimated by interpolating between 1996 and 2010 emissions.
Current and projected emissions in OECD-Europe, Japan and Rest of World (ROW) were
assumed to be proportional to the current shares of those regions in the global manufacturing
of semiconductors (Strategic Marketing Associates, 2003). For example, the 2010 OECDEurope emissions were calculated as: 9.53 (MTCO2) * 0.17/0.23 = 7.05 (MTCO2), where
9.53 – baseline SF6 emissions in North America and 0.23 and 0.17 – global manufacturing
shares of North America and OECD- Europe, respectively.
Further disaggregation of ROW emissions was conducted based on expert judgement (Shep
Burton, 2003) (Table 14.1).
Table 14.1: Baseline PFC Emissions from Semiconductors (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
0.1
0.1
1
2010
0.2
0.2
2
2020
0.2
0.3
3
0.1
0.1
9
0.1
0.1
6
5
5
0.7
21
7
28
0.2
0.2
14
0.2
0.2
10
7
7
1.0
31
11
41
0.2
0.2
18
0.2
0.2
13
9
9
1.3
41
14
55
Emissions from Japan, North America, OECD-Europe, and Rest of Asia account for about 90
percent of global emissions in 2010 (Table 14.1).
14.2 Abatement Options
Abatement options for the semiconductor sector are presented in Tables 14.2. All
semiconduc tor options were treated here as overlapping mutually excluding options. Changes
in the technical applicability for the semiconductor sector options were based on an
assumption that over time the allocation of emissions between chamber cleaning and etching
processes would change: the share of emissions from cleaning would increase.
ICF Consulting, Inc.
70
Table 14.2: Characteristics of Semiconductors Sector Abatement Options (Discount Rate is
10%) a
Id
SC1
SC2
SC3
SC4
SC5
SC6
Name
Chemical Vapor
Deposition Cleaning
Emission Reduction –
C3F8 Replacement
Chemical Vapor
Deposition Cleaning
Emission Reduction NF3 Remote Clean
Technology
Point-of-Use Plasma
Abatement (Litmas)
Thermal
Destruction/Thermal
Processing Units (TPU)
Catalytic Decomposition
System (Hitachi)
PFC Recapture/Recovery
RE (%)
TA (%)b
Total AER
in 2010
(MTCO2 Eq)
NSC
(US $ (2000)
/tCO2 Eq)
Source
100
70-90
17.02
0.00
U.S. EPA
(2001)
100
70-90
4.29
23.94
U.S. EPA
(2001)
100
10-30
2.91
14.86
U.S. EPA
(2001)
99
100
4.51
33.62
U.S. EPA
(2001)
99
100
6.37
23.09
100
100
6.24
23.89
U.S. EPA
(2001)
U.S. EPA
(2001)
a
RE – Reduction Efficiency. TA – Technical Applicability. AER – annual global emission reduction. NSC –
weighted average net specific cost for 10 percent discount rate, with absolute emission reductions in each region
used as weights.
b
vary by year.
14.3 Marginal Abatement Cost Curves
The largest emission reductions in the semiconductor sector can be achieved in Japan and
North America regions. Globally, zero-cost reductions comprise about 35 percent of the total
amount of reductions. These reductions are associated with the C3 F8 replacement “drop- in”
option, which is not associated with any additional costs (Table 14.2; Appendix B).
ICF Consulting, Inc.
71
Table 14.3: Marginal Abatement Cost Curves for the Semiconductors Sector
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
(20)
(10)
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
0
10
20
30
40
50
100 150
MACCs for 2010
0.08 0.08 0.09 0.17 0.19 0.19 0.19 0.19
0.09 0.09 0.1 0.18 0.21 0.21 0.21 0.21
0.83 0.83 0.97
2
2
2
2
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.08
0.08
6
0.08
0.08
4
3
3
0.41
13
4
17
0
0
41
World
World (% of
baseline)
0
0
10
0
0
36
World
World (% of
baseline)
0
0
0
0
Region
ICF Consulting, Inc.
0.08
0.08
6
0.08
0.08
4
3
3
0.41
13
4
17
0.09
0.09
7
0.09
0.09
5
3
3
0.48
15
5
20
200
>200
0.19
0.21
2
0.19
0.21
2
0.17
0.17
12
0.17
0.17
8
6
6
0.89
27
9
37
0.19
0.19
14
0.19
0.19
10
7
7
1
31
11
41
0.19
0.19
14
0.19
0.19
10
7
7
1
31
11
41
0.19
0.19
14
0.19
0.19
10
7
7
1
31
11
41
0.19
0.19
14
0.19
0.19
10
7
7
1
31
11
41
0.19
0.19
14
0.19
0.19
10
7
7
1
31
11
41
0.19
0.19
14
0.19
0.19
10
7
7
1
31
11
41
41
48
89
MACC for 2000
10
13
24
100
100
100
100
100
100
28
28
28
28
28
28
100
100
100
100
100
100
25
36
46
88
MACC for 2020
25
27
49
55
55
55
55
55
55
46
46
100
100
100
100
100
100
50
90
72
Net Specific Cost (US$(2000)/TCO2 Eq.)
Figure 14.1: Option-Based 2010 MACC for the Semiconductors Sector (at 10% Discount
Rate)a
$40
$35
$30
$25
$20
$15
$10
$5
$0
0
10
20
30
40
50
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option.
ICF Consulting, Inc.
73
15.
Combined Marginal Abatement Cost Curves
15.1
Combined Methane Baseline Emissions and Marginal Abatement Cost
Curves
Table 15.1 presents regional sums of baseline methane emissions from coal mining, natural
gas and oil systems, solid waste, and wastewater management. The largest baseline emissions
in 1990 occurred in the FSU region, followed by North America and China. By 2020, FSU is
estimated to still have the largest emissions, with China in the second and North America in
the third place.
From 2000 to 2020, baseline emissions are expected to grow in non-Annex I countries and
remain relatively flat in Annex I countries. While in 1990 Annex I emissions exceeded
emissions in non-Annex I countries by about 400 MTCO2 Eq., by 2020 emissions in nonAnnex I countries are estimated to exceed Annex I emissions by about 1000 MTCO2 Eq.
(Table 15.1).
Table 15.1: Combined Methane Baseline Emissions by Region (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
ICF Consulting, Inc.
1990
135
45
375
2000
165
50
412
2010
209
69
529
2020
268
88
667
150
825
12
241
162
562
291
158
164
1788
1333
3120
125
641
11
304
246
532
267
191
211
1555
1601
3156
131
686
8
406
343
604
266
242
294
1657
2129
3786
147
729
6
529
418
618
272
303
389
1731
2704
4435
74
Figure 15.1: Baseline Methane Emissions – 1990-2020 (MTCO2 Equivalent)
5000
4500
Africa
4000
Emissions (MTCO2)
Australia
3500
China
3000
Eastern & Central
Europe
FSU
2500
Japan
Latin America
2000
Middle East
North America
1500
OECD-Europe
1000
Rest of Asia
South Asia
500
0
1990
2000
2010
2020
Year
On the sectoral basis, the largest methane emissions are produced in the natural gas industry,
followed by the solid waste management. Emissions from coal mining that were the third in
volume in 1990 are estimated to remain at roughly the same level in 2020, while emissions
from waste management are expected to rise proportionally to population growth (Table
15.2).
Table 15.2: Global Methane Baseline Emissions by Sector (MTCO2 Equivalent)
Sector
Coal Mining
Natural Gas Production,
Transport, Distribution
Oil Production, Transport,
Distribution
Solid Waste Management
Wastewater Management
1990
624
2000
478
2010
566
2020
648
969
981
1270
1540
215
822
490
241
896
559
284
1042
624
342
1217
688
According to the combined regional MACC table, the largest cost-effective methane
emissions reductions in 2010 can be achieved in North America, followed by China and
South Asia (Table 15.3). Substantial reductions at a cost lower than $10/tCO2 Eq. can be also
achieved in the FSU, Latin America, and OECD-Europe regions.
ICF Consulting, Inc.
75
Table 15.3: Combined Methane MACCs by Region
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
(10)
0
0
0
0
62
12
159
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
109
116
116
120
128
133
39
41
42
42
45
46
333
342
342
342
367
373
0
0
3
0
0
75
0
0
0
77
0
77
45
59
5
93
64
175
51
80
119
347
577
924
70
251
6
179
122
315
136
129
157
816
1028
1844
2
24
49
1
72
791
0
2
25
0.51
77
1056
0
2
24
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0.84
Latin America
0
Middle East
0
North America
0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0.84
Non-Annex I
0
World
0.84
World (% of
baseline)
0
World
World (% of
baseline)
World
World (% of
baseline)
74
272
6
204
144
321
163
138
163
877
1107
1984
74
294
6
211
153
368
163
141
167
946
1131
2077
76
295
6
215
161
374
164
142
169
957
1148
2106
52
55
56
MACC for 2000
1563 1673 1749 1770
50
53
55
56
MACC for 2020
2139 2312 2417 2453
48
52
54
55
150
200
>200
137
47
375
137
47
375
140
48
375
80
319
6
224
166
391
178
146
172
1020
1203
2223
82
326
6
233
170
396
187
151
174
1043
1234
2277
82
331
6
239
176
402
191
153
175
1059
1254
2313
82
331
6
239
176
402
191
153
175
1059
1255
2314
85
380
6
259
203
423
198
158
185
1140
1320
2460
59
60
61
61
65
1869
1914
1946
1946
2058
59
61
62
62
65
2594
2659
2702
2703
2879
58
60
61
61
65
On a sector-by-sector basis, the largest cost-effective reductions can be achieved in the
wastewater management sector, followed by the solid waste management, natural gas and
coal sectors (Table 15.4). This result is partially explained by the assumed link between
growth in wastewater-related emissions and population and also by relatively low estimated
costs of collecting and utilizing methane at wastewater management facilities.
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76
Figure 15.2: Option-Based 2010 MACC for the Combined Methane Sector (at 10% Discount
Rate)a
$200
Net Specific Cost (US$(2000)/TCO2 Eq.)
$150
$100
$50
$0
-
500
1,000
1,500
2,000
2,500
($50)
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option. Options with NSC > $200/tCO2Eq. are excluded.
Table 15.4: Combined Methane MACCs by Sector
Year: 2010; Discount Rate – 10% (MTCO 2 Equivalent/year)
Sector
Coal Mining
Natural Gas
Production,
Transport,
Distribution
Oil Production,
Transport,
Distribution
Solid Waste
Management
Wastewater
Management
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
150
363
363
363
363
363
363
363
(20)
0
(10)
0.19
0
118
0
0.27
147
336
416
478
503
513
520
0
0
0.02
116
116
116
116
116
0.84
77
266
637
696
728
731
0
0.11
393
393
393
393
393
ICF Consulting, Inc.
200
363
>200
363
521
521
667
116
143
143
143
839
885
894
895
895
393
393
393
393
393
77
15.2
Combined Nitrous Oxide Baseline Emissions and Marginal Abatement
Cost Curves
The largest emissions of N2 O from industrial processes are generated in OECD-Europe and
China, followed by North America and South Asia. The global N2 O emissions estimated for
this study in both 1990 and 2020 are lower tha n those included in the IEA GHG N2 O Report
(267 MTCO2 Eq. in 1990 and 307 MTCO2 Eq. in 2020) (IEA GHG, 2000a). This difference is
explained by downward revisions of the 1990 emissions in key countries, slower projected
population growth, and lower industry forecasts of the acidic acid production.
Table 15.5: Combined Nitrous Oxide Baseline Emissions by Region (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
ICF Consulting, Inc.
1990
4
0.5
35
2000
5
1
48
2010
6
1
60
2020
7
1
64
11
23
10
4
4
42
107
11
15
154
112
266
13
18
9
9
8
29
48
17
26
85
145
230
15
16
10
11
11
23
52
19
37
95
177
271
16
16
12
12
14
39
55
22
42
104
195
298
78
Figure 15.3: Baseline Nitrous Oxide Emissions – 1990-2020 (MTCO2 Equivalent)
350
300
Africa
Australia
Emissions (MTCO2)
250
China
Eastern & Central
Europe
FSU
200
Japan
Latin America
150
Middle East
North America
100
OECD-Europe
Rest of Asia
50
0
1990
South Asia
2000
2010
2020
Year
Global baseline emissions from nitric acid production are estimated to grow steadily from
1990 to 2020, while emissions from adipic acid production declined sharply between 1990
and 2000 as a result of installation of abatement technologies. From 2000 to 2020 baseline
emissions from adipic acid production are expected to increase, as no additional abatement is
included in the “frozen mitigation technology” baselines adopted for this study (Table 15.6).
Table 15.6: Global Nitrous Oxide Baseline Emissions by Sector (MTCO2 Equivalent)
Sector
Adipic Acid Production
Nitric Acid Production
1990
118
148
2000
66
164
2010
81
190
2020
95
203
Levels of N2 O abatement in different regions are proportional to corresponding baseline
emissions (Tables 15.5 and 15.7). All N2 O emission reductions can be achieved at moderate
costs, under $10 per tCO2 Eq.
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79
Table 15.7: Combined Nitrous Oxide MACCs by Region
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
5
5
5
5
5
5
0.53 0.53 0.53 0.53 0.53 0.53
54
54
54
54
54
54
(20)
(10)
0
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
14
14
10
10
10
30
49
18
33
117
130
247
0
0
0
91
World
World (% of
baseline)
0
0
0
World
World (% of
baseline)
14
14
10
10
10
30
49
18
33
117
130
247
14
14
10
10
10
30
49
18
33
117
130
247
150
200
>200
5
0.53
54
5
0.53
54
5
0.53
54
14
14
10
10
10
30
49
18
33
117
130
247
14
14
10
10
10
30
49
18
33
117
130
247
14
14
10
10
10
30
49
18
33
117
130
247
14
14
10
10
10
30
49
18
33
117
130
247
14
14
10
10
10
30
49
18
33
117
130
247
14
14
10
10
10
30
49
18
33
117
130
247
91
91
91
91
91
0
91
91
91
MACC for 2000
209
209
209
209
209
209
209
209
209
0
0
91
0
0
0
0
91
91
91
91
91
0
91
91
91
MACC for 2020
272
272
272
272
272
272
272
272
272
0
91
91
91
91
91
91
91
91
91
Based on the assumed baseline scenarios, potential emission reductions in the nitric acid
production sector are almost twice as large as in the adipic acid production sector (Table
15.8).
ICF Consulting, Inc.
80
Table 15.8: Combined Nitrous Oxide MACCs by Sector
Year: 2010; Discount Rate – 10% (MTCO 2 Equivalent/year)
Sector
Adipic Acid
Production
Nitric Acid
Production
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
150
(20)
(10)
0
0
0
0
78
78
78
78
78
78
0
0
0
169
169
169
169
169
169
200
>200
78
78
78
169
169
169
Figure 15.4: Option-Based 2010 MACC for the Combined Nitrous Oxide Sector (at 10%
Discount Rate)a
1.40
Net Specific Cost (US$(2000)/TCO2 Eq.)
1.20
1.00
0.80
0.60
0.40
0.20
0.00
-
50
100
150
200
250
300
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option. Options with NSC > $200/tCO2 Eq. are excluded.
ICF Consulting, Inc.
81
15.3
Combined Engineered Chemicals Baseline Emissions and Marginal
Abatement Cost Curves
Baseline emissions of engineered chemicals in this study are adopted from the previous IEA
GHG analyses (IEA GHG, 2001 and IEA GHG, 2000b) (Table 15.9).
Table 15.9: Combined Engineered Chemicals Baseline Emissions by Region (MTCO2
Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
10
6
26
2010
17
14
49
2020
29
24
95
6
19
61
19
5
129
104
18
6
323
88
411
10
26
91
35
11
203
173
40
13
513
170
683
17
41
112
62
21
277
219
73
25
686
309
995
The largest combined emissions of these gases occur in North America and OECD-Europe,
followed by Japan and China.
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82
Figure 15.5: Baseline Emissions of Engineered Chemicals (MTCO2 Equivalent)
1200
Africa
1000
Australia
China
Emissions (MTCO2)
800
Eastern & Central
Europe
FSU
Japan
600
Latin America
Middle East
North America
400
OECD-Europe
Rest of Asia
200
South Asia
0
2000
2010
2020
Year
On a sectoral basis the largest emissions of engineered chemicals occur in the refrigeration
and air conditioning and foams sectors (Table 15.10).
Table 15.10: Global
Equivalent)
Baseline Emissions of Engineered Chemicals by Sector (MTCO2
Sector
Aerosols (MDI)
Aerosols (Non-MDI)
Aluminium
Electric GIS Manufacturing
Electric T&D
Fire Extinguishing
Foams
HCFC-22 Production
Magnesium
Refrigeration and Air
Conditioning
Semiconductors
Solvents
2000
11
11
60
13
23
9
29
82
31
2010
39
40
79
10
19
30
101
40
43
2020
55
60
94
10
23
46
253
29
93
109
28
5
222
41
17
251
55
26
The largest emission reductions in the engineered chemicals sectors can be achieved in North
America, followed by OECD-Europe. About 18 percent of the global baseline emissions can
be reduced at below zero costs (Table 15.11). The volume of cost-effective emission
reductions in this study is compatible with that estimated in the previous IEA GHG
assessments (IEA GHG, 2000b and 2001).
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83
Table 15.11: Combined Engineered Chemicals MACCs by Region
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
MACCs for 2010
7
7
8
8
8
8
6
7
7
7
7
8
27
28
30
31
32
32
(20)
(10)
0
0.27
0.55
0
1
0.55
0.15
4
3
8
0.01
0
0
0.25
0.21
0.19
0.17
0.07
0
0.93
0.8
2
0.14
0.1
12
2
0.23
0.36
0.17
0.27
0.08
14
4
17
2
3
23
8
2
21
34
12
3
86
38
124
4
12
50
17
4
104
87
22
5
264
83
347
0
3
18
51
World
World (% of
baseline)
1
6
0
World
World (% of
baseline)
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
4
13
55
18
4
112
88
23
5
278
86
364
5
13
62
19
5
130
102
27
7
319
96
415
150
200
>200
8
8
32
9
8
34
9
8
35
5
13
64
19
5
134
108
28
7
331
98
429
5
14
65
19
5
135
108
28
7
333
99
432
5
15
67
20
5
138
110
29
7
342
102
443
5
15
67
20
5
138
110
30
7
342
103
445
5
15
70
21
6
148
120
31
7
366
108
474
6
16
73
22
6
153
129
32
8
384
112
496
63
65
65
65
65
37
53
61
63
MACC for 2000
201
207
225
230
232
233
233
268
274
1
9
49
3
17
0
2
56
57
57
57
57
186
50
55
56
MACC for 2020
543
564
636
657
661
688
693
721
753
19
55
66
69
69
70
70
57
64
66
Most of the reductions can be attained in the refrigeration and air conditioning sector,
followed by the foams sector (Table 15.12).
ICF Consulting, Inc.
84
Table 15.12: Combined MACCs of Engineered Chemicals by Sector
Year: 2010; Discount Rate – 10% (MTCO 2 Equivalent/year)
Sector
(20)
Aerosols (MDI) 0
Aerosols (NonMDI)
0
Aluminium
1
Electric GIS
Manufacturing
0
Electric T&D
0
Fire
Extinguishing
0.3
Foams
0
HCFC-22
Production
0
Magnesium
0
Refrigeration
and Air
Conditioning
0
Semiconductors
0
Solvents
0
ICF Consulting, Inc.
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
150
0
0
0
0
0
0
0
(10)
0
0
0
200
0
>200
19
0
4
40
11
40
19
40
19
40
19
40
20
40
22
40
22
40
22
40
22
40
22
0
0
0
0
3
6
3
6
3
6
3
6
3
6
3
6
3
6
3
6
3
6
0.57
0
0.72
21
0.72
58
1
59
3
64
6
64
6
64
7
72
9
72
9
72
11
72
0
0
0
0
36
30
36
30
36
30
36
30
36
30
36
30
36
30
36
30
36
30
12
0
0
35
17
0
122
17
16
134
20
16
162
37
16
166
41
17
167
41
17
168
41
17
168
41
17
198
41
17
198
41
17
85
Figure 15.6: Option-Based 2010 MACC for the Combined Engineered Chemicals Sector (at
10% Discount Rate)a
$300
$250
Net Specific Cost (US$(2000)/TCO2 Eq.)
$200
$150
$100
$50
$0
0
100
200
300
400
500
600
-$50
-$100
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option. Options with NSC > $300/tCO2 Eq. are excluded.
15.4 All-GHG Baseline Emissions and Marginal Abatement Cost Curves
In the absence of additional mitigation, the global combined emissions of non-CO2 gases
from the selected sources included in this study are projected to grow by 50 percent from
2000 to 2020 (Table 15.13 and Figure 15.7). In 2010, the largest combined non-CO2
emissions from the sources included in this study are estimated to occur in North America,
followed by FSU and China. Current emissions of Annex I and non-Annex I regions are
roughly the same, but by 2020 Non-Annex I regions are projected to emit about 25 percent
more than Annex I regions (Table 15.13).
ICF Consulting, Inc.
86
Table 15.13: All GHG Baseline Emissions by Region (MTCO2 Equivalent)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
2000
180
57
486
2010
232
84
638
2020
304
113
826
144
678
81
332
259
690
419
226
243
1963
1834
3797
156
728
109
452
365
830
491
301
344
2265
2476
4740
180
786
130
603
453
934
546
398
456
2521
3208
5728
Figure 15.7: Combined Non-CO2 Baseline Emissions (MTCO2 Eq.)
7000
Africa
6000
Australia
China
Emissions (MTCO2)
5000
Eastern & Central
Europe
FSU
4000
Japan
Latin America
Middle East
3000
North America
OECD-Europe
2000
Rest of Asia
South Asia
1000
0
2000
2010
2020
Year
On a gas-by- gas basis, baseline methane emissions from the energy production and waste
management sources will continue to exceed combined emissions of engineered chemicals in
2010-2020. Emissions of N2 O from industrial sources remain the distant third (Table 15.14).
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Table 15.14: All GHG Baseline Emissions by Gas (MTCO2 Equivalent)
Gas
Methane
N2O
Engineered Chemicals
1990
3120
266
Not available
2000
3156
230
411
2010
3786
271
683
2020
4435
298
995
According to Table 15.15, the global 2010 cost-effective emission reductions from the
sources included in the present report exceed 1000 MTCO2 , while the combined reductions
under $20 per tonne of CO2 Eq. are over 2500 MTCO2 Eq. or 55 percent of the total baseline
emissions.
Table 15.15: All GHG MACCs by Region
Regional and Global MACCs for Year 2010, Global MACCs for 2000, 2010, 2020; Discount Rate –
10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
World
World (% of
baseline)
World
World (% of
baseline)
(20)
(10)
0
0.27
0.55
0
1
0.55
0.15
66
15
167
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
150
MACCs for 2010
121
128
129
133
141
146
150
46
49
50
50
53
55
56
414
424
426
427
453
459
461
0.01
0
1
0.25
0.21
0.19
0.17
0.07
0
2
1
3
0.14
0.1
15
2
0.23
75
0.17
0.27
0.08
91
4
94
47
62
28
101
66
196
85
92
122
433
615
1048
88
277
66
206
136
449
272
169
195
1197
1241
2438
0.06
2
22
51
2
78
828
0.05
2
22
4
94
1242
0.06
2
22
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299
71
232
158
463
300
179
201
1272
1323
2595
93
321
78
240
168
528
314
186
207
1382
1357
2739
95
322
80
244
176
538
321
188
209
1405
1376
2782
55
58
59
MACC for 2000
1973 2089 2183 2209
52
55
57
58
MACC for 2020
2954 3148 3325 3382
52
55
58
59
200
>200
151
56
463
154
57
464
99
347
81
253
181
556
335
192
212
1470
1432
2902
101
355
83
263
185
564
346
198
214
1502
1466
2967
101
360
83
269
191
570
350
201
215
1518
1487
3005
101
360
86
270
192
580
360
202
215
1542
1493
3035
105
410
89
291
219
606
376
208
226
1641
1562
3203
61
63
63
64
68
2310
2356
2388
2423
2541
61
62
63
64
67
3527
3619
3667
3696
3904
62
63
64
65
68
88
Figure 15.8: Combined Emission Reductions by Region at or below Different Net Specific
Abatement Costs (expressed in $/tCO2 Eq.). Discount Rate – 10%, Year 2010.
600
500
MTCO2 Eq
400
>$100
$100
$50
$20
$0
300
200
100
0
Africa
Australia
China
Eastern &
Central
Europe
FSU
Japan
Latin
America
Middle East
North
America
OECDEurope
Rest of Asia South Asia
According to Figure 15.8 and Table 15.15, the largest non-CO2 reductions under $20 per
tonne of CO2 Eq. can be achieved in North America, followed by China, OECD-Europe and
FSU.
The largest cost-effective reduction can be obtained by abating emissions from methane
sources, followed by sources of engineered chemicals and N2 O (Figure 15.9). Most of the
potential cost effective reductions can be achieved in the wastewater management sector,
followed by solid waste management, and the natural gas sector. The solid waste and natural
gas sector lead other sectors in the reductions that can be obtained under 20 and 50 dollars
per tonne of CO2 equivalent.
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Figure 15.9: Total Reductions of Non-CO2 Emissions by Gas at Different Net Costs
3000
2500
MTCO2 Eq
2000
Engineered Chemicals
1500
N2O
CH4
1000
500
0
$0
$20
$50
$100
$/tCO2 Eq
Figure 15.10: Reductions of non-CO2 Emissions by Sector at Different Net Costs
900
800
700
MTCO2Eq
600
<$0/TCO2
<$20/TCO2
<$50/TCO2
500
400
300
200
100
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16.
Sensitivity Analysis
16.1
Sensitivity to Discount Rate
According to Table 16.1, the relative sensitivity of methane emission reductions to changes
in discount rates is noticeable only at negative net costs (Table 16.1). The ratio between the
below $(10) per tCO2 Eq. reductions at 5 and 15 percent discount rate is 40, while the same
ratio for the reductions below $(50) is only 1.1.
Table 16.1: Sensitivity of Methane Emission Reductions to Discount Rates at Base Energy
Price in 2010 (MTCO2 Equivalent/year)a
Discount
Rate(%)
2
5
10
15
20
a
(20)
67
73
1
1
1
(10)
75
80
77
2
2
Value of CO 2
0
10
20
1032 1918 2141
967 1870 2053
924 1844 1984
881 1865 1935
817 1817 1894
Eq. (US $ (2000)/TCO2 Eq.)
30
40
50
100
2220 2257 2267 2319
2183 2240 2255 2313
2077 2106 2223 2277
2046 2071 2089 2272
2023 2065 2071 2256
150
2321
2317
2313
2307
2279
200 >200
2321 2467
2318 2463
2314 2460
2313 2458
2311 2457
– format adopted from EPA (2003)
The nitrous oxide emission MACCs show the absence of any sensitivity to the discount rate
(Table 16.2). This outcome can be explained by the fact that all the N2 O abatement option
costs fall within a narrow cost range between $0 and $10 per tCO2 Eq.
Table 16.2: Sensitivity of Nitrous Oxide Emission Reductions to Discount Rates at Base
Energy Price (MTCO2 Equivalent/year)
Discount
Rate(%)
2
5
10
15
20
(20)
0
0
0
0
0
(10)
0
0
0
0
0
0
0
0
0
0
0
Value of CO 2
10
20
247
247
247
247
247
247
247
247
247
247
Eq. (US $ (2000)/TCO2 Eq.)
30
40
50
100
247
247
247
247
247
247
247
247
247
247
247
247
247
247
247
247
247
247
247
247
150
247
247
247
247
247
200
247
247
247
247
247
>200
247
247
247
247
247
Similarly, reductions of industrial gas emissions are not very sensitive to changes in discount
rates (Table 16.3).
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Table 16.3: Sensitivity of Engineered Chemicals Emission Reductions to Discount Rates at
Base Energy Price (MTCO2 Equivalent/year)
Discount
Rate(%)
2
5
10
15
20
(20)
13
2
2
1
1
(10)
17
18
17
16
3
0
144
142
124
101
101
Value of CO 2
10
20
348
400
345
380
347
364
347
360
345
359
Eq. (US $ (2000)/TCO2 Eq.)
30
40
50
100
431
432
441
474
424
432
433
444
415
429
432
443
412
424
430
443
385
414
424
443
150
474
474
445
444
443
200
474
474
474
474
445
>200
496
496
496
496
496
The apparent lack of sensitivity of MACCs to changes in the discount rate can be partially
explained by the cost increment selected to build the MACC tables ($10/tCO2 Eq.). The
sensitivity could be greater at the sectoral and option level, especially for options with high
fixed costs relative to recurring costs (see Equation 7).
16.2 Sensitivity to Energy Price
The sensitivity of MACCs to changes in base energy price was evaluated based on the
methane sources (Table 16.4). The greatest sensitivity can be observed for net costs under
$(0)/tCO2 Eq., where a tripling of the base energy price leads to the 75 percent increase of
emission reductions in the same cost category.
Table 16.4: Combined Global Methane MACCs Based on Different Energy Prices (MTCO2
Equivalent/year)
Year – 2010; Discount Rate = 10%
Relative
Energy Price
-50%
-25%
Base Energy
Price
25%
50%
100%
200%
(20)
1
1
(10)
80
78
0
711
832
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
10
20
30
40
50
100
150
1827 1946 2071 2083 2215 2275 2313
1839 1966 2074 2095 2219 2276 2313
200 >200
2314 2460
2314 2460
1
1
72
70
75
77
76
85
269
673
924
1002
1078
1240
1611
1844
1846
1883
1913
1967
2314
2314
2314
2312
2309
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1999
2023
2028
2049
2077
2082
2084
2090
2108
2106
2117
2119
2121
2130
2223
2227
2233
2237
2240
2277
2277
2277
2279
2277
2313
2313
2313
2312
2308
2460
2460
2459
2458
2454
92
17.
Discussion
17.1 Key Results
The current study confirms that abatement of non-CO2 gases can potentially play a significant
role in mitigating anthropogenic climate change. For example, the cost-effective annual
emission reductions from all the sources reviewed here (1048 MTCO2 Eq.) are three times
greater than the EU Kyoto Protocol target (annual average 2008-2012 reduction of 337
MTCO2 Eq. relative to 1990) and exceeds the combined targets of all countries that have
initially joined the Protocol (annual average 2008-2012 reduction of 915 MTCO2 Eq. relative
to 1990).
Methane emission sources offer the largest potential reductions followed by engineered
chemicals and N2 O. Among the regions, the largest combined reductions under
$(20)/tCO2Eq. (at 10 percent discount rate) can be achieved in North America, followed by
China, FSU and OECD-Europe. The lowest potential reductions can be potentially attained in
Australia and Japan.
Overall, the current analysis reflects the largest possible emission reductions that can be
obtained based on generic technical and economic characteristics of underlying abatement
options. Clearly, the combined reductions that can be realized by specific projects are likely
to be lower and carry higher costs due to various inefficiencies, implementation barriers, and
transaction expenses. The timing of emission reductions can also be different from the one
reflected in the current analysis. The period of time when a specific option will be actually
implemented in a given region depends of a variety of economic and non-economic factors.
Both, temporal changes in option costs and regional penetration could be explored as part of
comprehensive region-specific techno-economic scenarios, which can use the current study
as a source of starting conditions.
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Figure 17.1: Option-Based 2010 MACC for the All Sectors (at 10% Discount Rate)a
$300
$250
Net Specific Cost (US$(2000)/TCO2 Eq.)
$200
$150
$100
$50
$0
0
500
1,000
1,500
2,000
2,500
3,000
3,500
-$50
-$100
Reductions (MTCO2)
a
Based on regional net specific costs weighted by emission reductions attained by an option in each region.
Each point represents a single option. Options with NSC > $300/tCO2 Eq. are excluded.
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17.2
Uncertainties and Recommendations
Baseline Emissions
The current study uses the “frozen abatement technology” assumption to compile the baseline
emissions across regions, gases, and sources. The resulting baselines are different from the
baselines used in other non-CO2 studies (e.g., IEA GHG, 2001 and U.S. EPA, 2003) and
consequently can lead to dissimilar estimates of the abatement potential.
Recommendation: Separately analyze and interpret MACCs that are generated using
differently defined baseline emissions. For example, MACCs generated from the baselines
that include impacts of regulatory policies would be different from the MACCs that do not
assume that such policies are implemented in the baseline scenario. Also, MACCs that rely
on “technologically optimistic” baselines would offer less potential reductions tha n MACCs
using the “frozen abatement technology” assumption.
Technical Applicability
The current analysis used data from the selected regions (e.g., U.S or EU) or relied upon
some general assumptions to quantify the Technical Applicability of individual options in
different regions. Since the technological structure of individual emission sectors (e.g., waste
management systems) is different in various parts of the world, such an approach to
determining the Technical Applicability could lead to under or overestimation of emission
reductions.
Recommendation: Collect and use country-level information on option-specific Technical
Applicability.
Economic Applicability
The current analysis relies on a customized function to estimate how much emissions can be
reduced by each “competing” (overlapping) option. This function assigns higher potential
reductions to the options with lower net specific abatement cost and disregards (due to the
lack of consistent country- level data) regional and national barriers and incentives.
Recommendation: Collect and use country- level information on factors that lead to a greater
or lower preference for a particular abatement option in a given regio n.
Costs and Offsets
The estimates of costs and offsets for each abatement option were based on the bottom- up
analysis performed for the U.S. or EU point sources. Although recurrent costs and cost
offsets were scaled to reflect regional labour costs and energy prices such an approach may
have over- or under-estimated some net abatement costs.
Recommendation: Collect and use country- level information on costs and cost offsets.
Explore an approach to scale fixed costs based on the opportunity cost of capital in different
regions.
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18.
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ICF Consulting, Inc.
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Appendices:
Appendix A: Description of MACC Regions
Appendix B: Description of Abatement Options
Appendix C: Examples of Economic Applicability Functions
Appendix D: Temporal Changes in Technical Applicability of Industrial Sector
Options
Appendix E: Marginal Abatement Cost Curves for 2000 and 2020
ICF Consulting, Inc.
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Appendix A: Description of MACC Regions
Africa
Algeria
Angola
Benin
Botswana
Burkina Faso
Burundi
Cameroon
Cape Verde
Central African Republic
Chad
Comoros
Congo, Dem. Rep.
Congo, Rep.
Cote d'Ivoire
Djibouti
Egypt, Arab Rep.
Equatorial Guinea
Eritrea
Ethiopia
Gabon
Gambia, The
Ghana
Guinea
Guinea-Bissau
Kenya
Lesotho
Liberia
Libya
Madagascar
Malawi
Mali
Mauritania
Mauritius
Mayotte
Morocco
Mozambique
Namibia
Niger
Nigeria
Rwanda
Sao Tome and Principe
Senegal
Seychelles
Sierra Leone
Somalia
South Africa
Africa (continued)
Sudan
Swaziland
Tanzania
Togo
Tunisia
Uganda
Zambia
Zimbabwe
Annex I
Australia
Austria
Belarus
Belgium
Bulgaria
Canada
Croatia
Czech Republic
Denmark
Estonia
Finland
France
Germany
Greece
Hungary
Iceland
Ireland
Italy
Japan
Latvia
Liechtenstein
Lithuania
Luxembourg
Monaco
Netherlands
New Zealand
Norway
Poland
Portugal
Romania
Russian Federation
Slovak Republic
Slovenia
Spain
Sweden
Switzerland
A-1
Annex I (continued)
Turkey
Ukraine
United Kingdom
United States
Eastern and Central Europe
Albania
Bosnia and Herzegovina
Bulgaria
Croatia
Czech Republic
Hungary
Macedonia, FYR
Poland
Romania
Slovak Republic
Slovenia
Yugoslavia, FR (Serbia/Montenegro)
FSU
Armenia
Azerbaijan
Belarus
Estonia
Georgia
Kazakhstan
Kyrgyz Republic
Latvia
Lithuania
Moldova
Russian Federation
Tajikistan
Turkmenistan
Ukraine
Uzbekistan
Latin America
Antigua and Barbuda
Argentina
Aruba
Bahamas, The
Barbados
Belize
Bermuda
Bolivia
Brazil
Cayman Islands
Chile
Colombia
Costa Rica
Latin America (continued)
Cuba
Dominica
Dominican Republic
Ecuador
El Salvador
Grenada
Guatemala
Guyana
Haiti
Honduras
Jamaica
Mexico
Netherlands Antilles
Nicaragua
Panama
Paraguay
Peru
Puerto Rico
St. Kitts and Nevis
St. Lucia
St. Vincent and the Grenadines
Suriname
Trinidad and Tobago
Uruguay
Venezuela, RB
Middle East
Bahrain
Indonesia
Iran, Islamic Rep.
Iraq
Israel
Jordan
Kuwait
Lebanon
Oman
Qatar
Saudi Arabia
Syrian Arab Republic
United Arab Emirates
West Bank and Gaza
Yemen, Rep.
North America
Canada
United States
Virgin Islands (U.S.)
A-2
Non-Annex I
Afghanistan
Albania
Algeria
American Samoa
Andorra
Angola
Antigua and Barbuda
Argentina
Armenia
Aruba
Azerbaijan
Bahamas, The
Bahrain
Bangladesh
Barbados
Belize
Benin
Bermuda
Bhutan
Bolivia
Bosnia and Herzegovina
Botswana
Brazil
Brunei
Burkina Faso
Burundi
Cambodia
Cameroon
Cape Verde
Cayman Islands
Central African Republic
Chad
Channel Islands
Chile
China
Colombia
Comoros
Congo, Dem. Rep.
Congo, Rep.
Costa Rica
Cote d'Ivoire
Cuba
Cyprus
Djibouti
Dominica
Dominican Republic
Ecuador
Egypt, Arab Rep.
El Salvador
Equatorial Guinea
Non-Annex I (continued)
Eritrea
Ethiopia
European Union
Faeroe Islands
Fiji
French Polynesia
Gabon
Gambia, The
Georgia
Ghana
Greenland
Grenada
Guam
Guatemala
Guinea
Guinea-Bissau
Guyana
Haiti
Honduras
Hong Kong, China
India
Indonesia
Iran, Islamic Rep.
Iraq
Isle of Man
Israel
Jamaica
Jordan
Kazakhstan
Kenya
Kiribati
Kuwait
Kyrgyz Republic
Lao PDR
Lebanon
Lesotho
Liberia
Libya
Macao, China
Macedonia, FYR
Madagascar
Malawi
Malaysia
Maldives
Mali
Malta
Marshall Islands
Mauritania
Mauritius
Mayotte
A-3
Non-Annex I (continued)
Mexico
Micronesia, Fed. Sts.
Moldova
Mongolia
Morocco
Mozambique
Myanmar
Namibia
Nepal
Netherlands Antilles
New Caledonia
Nicaragua
Niger
Nigeria
Northern Mariana Islands
Oman
Pakistan
Palau
Panama
Papua New Guinea
Paraguay
Peru
Philippines
Puerto Rico
Qatar
Rwanda
Samoa
San Marino
Sao Tome and Principe
Saudi Arabia
Senegal
Seychelles
Sierra Leone
Singapore
Solomon Islands
Somalia
South Africa
Sri Lanka
St. Kitts and Nevis
St. Lucia
St. Vincent and the Grenadines
Sudan
Suriname
Swaziland
Syrian Arab Republic
Tajikistan
Tanzania
Thailand
Togo
Tonga
Non-Annex I (continued)
Trinidad and Tobago
Tunisia
Turkmenistan
Uganda
United Arab Emirates
Uruguay
Uzbekistan
Vanuatu
Venezuela, RB
Vietnam
Virgin Islands (U.S.)
West Bank and Gaza
Yemen, Rep.
Yugoslavia, FR (Serbia/Montenegro)
Zambia
Zimbabwe
Korea, Dem. Rep. (North)
Korea, Rep. (South)
OECD - Europe
Austria
Belgium
Channel Islands
Cyprus
Denmark
Faeroe Islands
Finland
France
Germany
Greece
Greenland
Hungary
Iceland
Ireland
Isle of Man
Italy
Luxembourg
Malta
Monaco
Netherlands
Norway
Portugal
San Marino
Spain
Sweden
Switzerland
Turkey
United Kingdom
A-4
Rest of Asia
American Samoa
Bangladesh
Bhutan
Brunei
Cambodia
Fiji
French Polynesia
Guam
Kiribati
Lao PDR
Malaysia
Maldives
Marshall Islands
Micronesia, Fed. Sts.
Mongolia
Myanmar
New Caledonia
New Zealand
Northern Mariana Islands
Palau
Papua New Guinea
Philippines
Samoa
Singapore
Solomon Islands
Sri Lanka
Thailand
Tonga
Vanuatu
Korea, Dem. Rep. (North)
Korea, Rep. (South)
South Asia
Afghanistan
Bangladesh
India
Nepal
Pakistan
A-5
Appendix B
Description of Abatement Options
List of Options
ID
Title
Coal Mining
C1, C2
Degasification and Pipeline Injection (DPI) and Enhanced Degasification and
Pipeline Injection (EDPI)
C3
Catalytic Oxidation of Ventilation Air Methane (VAM)
C4
Flaring
C5 to C7
Degasification and Power Production – A. CH4 -Gas Turbine (30% recovery),
Degasification and Power Production – B (50% recovery), Degasification and
Power Production – C (70% recovery)
Oil
O1, O2
Flaring instead of Venting (Offshore)/ Flaring instead of Venting (Onshore)
O3, O4
Associated Gas (vented) Mix Other Options/Associated Gas (flared) Mix Other
Options
Natural Gas
NG1
Altering Start-up Procedures During Maintenance
NG2
Catalytic Converter
NG3 to NG7, NG18
to NG22, NG31, and
NG32
NG8, NG9, NG12,
NG23
Directed Inspection and Maintenance (DI&M)
NG10, NG13, NG24,
NG27
Reducing the Glycol Circulation Rates in Dehydrators, Installation of Flash Tank
Separators
NG11, NG26
Portable Evacuation Compressor for Pipeline Venting
NG14, NG15, NG28,
NG29
Replacement of High-Bleed Pneumatic Devices with Low-Bleed Pneumatic
Devices or with Compressed Air Systems
NG16, NG30
Surge Vessels for Station/Well Venting
NG17
Use of Gas Turbines Instead of Gas Reciprocating Engines
NG25
Installing Plunger Lift Systems In Gas Wells
NG33
Electronic Monitoring at Large Surface Facilities
NG34, NG35
Replacement of Cast Iron/Unprotected Steel Pipeline/Replacement of
Unprotected Steel Services
Installation of Electric Starters, Dry Seals and Static Pacs on Compressors, Fuel
Gas Retrofit for Blowdown Valves
Solid Waste
LF1, LF2
Anaerobic digestion 1, Anaerobic digestion 2
LF3 to LF5
Composting (1 and 2), Mechanical Biological Treatment
LF6
Heat Production
B-1
ID
Title
LF7
Increased Oxidation
LF8, LF9
Upgrade to Synthetic Natural Gas, Direct Gas Use – Profitable at Base Price,
Direct Gas Use – Profitable above Base Price
LF10
Electricity Generation
LF11
Flaring
Wastewater Management
W1
Methane Mitigation Options from Anaerobic Digestion at Wastewater Treatment
Facilities (ADWT)
Nitric Acid Production
NAC1
BASF - High Temperature Catalytic Reduction Method (BASF – HTCR)
NAC2
ECN - Low temperature selective catalytic reduction with propane addition
(ECN – LTSCR)
Grand Paroisse - High Temperature Catalytic Reduction Method (Grand
Paroisse– HTCR)
NAC3
NAC4
HITK – High Temperature Catalytic Reduction Method (HITK – HTCR)
NAC5
Krupp Uhde - Low Temperature Catalytic Reduction Method (Krupp Uhde –
LTCR)
NAC6
Norsk Hydro - High Temperature Catalytic Reduction Method (Norsk Hydro –
HTCR)
NAC7
Non-Selective Catalytic Reduction (NSCR)
Adipic Acid Production
AA1
Valorisation of Nitrous Oxide emitted by adipic acid unit (Valorisation - Adipic)
AA2
Thermal Reduction
Refrigeration and Air Conditioning
R1 and R6
Replacing Direct Expansion Systems with Distributed Systems
R2, R7 and R11
Ammonia Secondary Loops
R3, R8, R12, R19,
and R20
Leak Repair for Large Equipment
R4, R9 and R13
Alternative Systems
R5 and R10
HFC Secondary Loops
R14, R16 and R18
Refrigerant Recovery
R15
Hydrocarbons in Domestic Refrigerators
R17
Carbon Dioxide in MVACs
MDI Aerosols
AMD1
Dry Powder Inhalers (DPIs)
B-2
ID
Title
Non-MDI Aerosols
ANM1
Hydrocarbon Aerosol Propellants (Replacing HFC-134a used by Non-MDI
aerosols with Hydrocarbons)
ANM2
HFC-152a (Replacing HFC-134a used by Non-MDI aerosols with HFC-152a)
ANM3
Not In Kind (NIK) Products (Replacing HFCs used by Non-MDI aerosols with
NIK products)
Solvents
S1
Retrofit (Improved Equipment and Cleaning Processes with the use of existing
solvents)
S2, S3
Not-In-Kind (NIK) Technology Processes and Solvent Replacements (NIK
Aqueous and Semi-aqueous Cleaning)
S4
Alternative Solvents (HFEs)
Foams
F1 to F3
Replacing HFC-134a and HFC-245fa or HFC-365mfc in Appliance and Spray
Polyurethane Foam with Hydrocarbons
F4, F5
Replacing HFC-134a or HFC-152a in Extruded Polystyrene and HFC-245fa in
Spray Foams with Water blown in situ Carbon Dioxide (CO2 /water)
Fire Extinguishing
FE1
Inert Gas Systems
FE2
Water Mist
HFC-23 Emissions from HCFC-22 Production
H1
Thermal Oxidation
Aluminium Production
AL1 to AL8
Minor/Major Retrofit for Vertic al/Horizontal Stud Soderberg and CentreWorked/Side-Worked Prebake Technologies
Magnesium
MG1
Sulphur Dioxide (SO2 ) – Alternate Cover Gas
Electric Transmission and Distribution
ET1
SF6 Leakage Reduction and Recovery
Electric Gas Insulated Switch Gear (GIS) Manufacture
EG1
Improved SF6 Recovery
Semiconductors
SC1, SC2
Chemical Vapor Deposition (CVD) Cleaning Emission Reduction Technologies,
C3F8 Replacement
SC3
Point-of-Use Plasma Abatement (Litmas)
B-3
ID
Title
SC4
Thermal Destruction/Thermal Processing Units (TPU)
SC5
Catalytic Decomposition System (Hitachi)
SC6
PFC Recapture/Recovery
B-4
SECTOR:
Coal Mining
OPTION NAME:
Degasification and Pipeline Injection (DPI) and Enhanced Degasification and
Pipeline Injection (EDPI)
OPTION ID:
C1, C2
Brief Description
Degasification and Pipeline Injection (DPI) option includes coalmine methane collection via vertical
wells drilled several years before coal is mined supplemented by horizontal boreholes and gob wells. The
recovered methane is then sold to a natural gas company. The Enhanced Degasification and Pipeline
Injection (EDPI) option is used incrementally with respect to DPI and is based on a more dense spacing of
wells and boreholes that increases the efficiency of coalmine methane recovery. In addition, mines use
enrichment technologies to enhance the quality of gob gas.
State of Development and Current Level of Usage
These options are well developed technologically and are widely used by coalmines in the United States,
Australia, and other countries.
Associated Risks and Uncertainties
Both options become feasible if they can produce methane of sufficient quality to be injected into a
natural gas pipeline. Unexpected changes in mining conditions, leading to declines in methane
concentration could lead to lowering the abatement and economic effectiveness of these options.
Potential Applicability in Different Regions
Technologically, both DPI and EDPI options can be applied in any mine with adequate coalmine methane
(CBM) concentrations and located in the proximity to natural gas pipelines. Regions such as China and
India currently lack the natural gas pipeline infrastructure that is sufficient for the wide use of the DPI and
EDPI options. This situation may change within the next 10-20 years as these regions continue to develop
their natural gas sector.
Option
Degasification and
Pipeline Injection
Enhanced
Degasification and
Pipeline Injection
Lifetime
(years)
Reduction
Efficiency
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
15
57
5.16
3.17
4.78
15
77
19.65
5.70
4.78
Key References
U.S.EPA. 1999. U.S. Methane Emissions 1990-2010: Inventories, Projections, and Opportunities for
Reductions. Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, D.C.
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-5
SECTOR:
Coal Mining
OPTION NAME:
Catalytic Oxidation of Ventilation Air Methane (VAM)
OPTION ID:
C3
Brief Description
Coalmines can remove ventilation air methane (VAM) from their systems using catalytic oxidizers.
These technologies simply destroy VAM or destroy VAM with capturing and using the thermal energy
that is liberated from this destruction . The energy released from oxidation can be used for space heating
or electricity generation. Specific VAM oxidation technologies include thermal flow-reversal reactors
(TRFF) and catalytic flow-reversal reactors (CFRR) (catalytic oxidation).
State of Development and Current Level of Usage
Both thermal flow-reversal reactors and catalytic flow-reversal reactors are currently available and can be
positioned at the vent shafts or ventilation fans of the mine. Canadian Mineral and Energy Technologies
(CANMET) has developed a catalytic flow-reversal reactor specifically for mine ventilation air.
However, neither the CFRR nor the TRFF are currently operated at the full commercial scale .
Associated Risks and Uncertainties
Certain aspects of CFRR and TRFF operation remain to be tested. For example, the ability to physically
capture most of ventilation air and feed it to the reactor units without mixing it with ambient air remains
uncertain. Also, one analysis assumed that the ratio of VAM released per unit of coal remains constant,
which is unlikely in real conditions. Furthermore, it is not certain at this time if some of the analyzed
ventilation airflow rates represent a single ventilation shaft or if they in fact are based on flows from
multiple shafts.
Potential Applicability in Different Regions
In the United States, some coalmines are testing CFRR systems. The energy released from oxidation is
used for space heating and electricity generation. This option is assumed to be applicable to at least 90%
of the underground mines in the U.S. There appear to be no technical barriers for using this option in all
the coalmining regions.
Option
CFRR
Lifetime
(years)
16
Reduction
Efficiency
(%)
98.5
Fixed Cost
($2000
US/tCO2 Eq)
41.57
Recurring
Cost ($2000
US/tCO2 Eq)
2.70
Cost Offset
($2000
US/tCO2 Eq)
2.84
Key References
Schultz, K. H., Shultz, H. L., Carothers, F. P., and Watts, R. A. 2001. An Analysis of the Global Market
for Methane Destruction, Coalbed Methane Outreach Program, U.S. Environmental Protection Agency,
Washington D. C.
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-6
SECTOR:
Coal Mining
OPTION NAME:
Flaring
OPTION ID:
C4
Brief Description
Gas flaring is commonly used to meet safety standards. For example, methane and other associated gasses
are routinely flared during processing and production of oil and gas, and are continuously flared from
landfill collection systems.
State of Development and Current Level of Usage
This flaring technology for the coalmine industry has been developed in Australia. Capricorn Coal
Development Joint Venture (Capricorn) installed a gob well flare that combusts methane from a number
of vertical gob wells at the rate of 102,000 m3 per day.
Associated Risks and Uncertainties
The main risks associated with this option involve unconfined deflagrations that are potentially isolated
within the flare system. The proposed design for the U.S. flare system mitigates the potential of flashback
from the flare by incorporating (1) an active positive pressure system, (2) an American Petroleum
Instit ute (API) recommended fluidic seal, (3) an API recommended liquid seal, and (4) a monitoring and
control system with valve and equipment activation capability. Also, there is a risk of natural and manmade sources of ignition. The flaring facility must be adequately protected from vandalism and
unauthorized entry.
Potential Applicability in Different Regions
While the flare installation may bring significant economic, safety, and operational benefits to a
coalmining companies, it would require the approval of national mine safety agencies (e.g., Mine Safety
and Health Administration in the United States). In general, flaring can be used in any region, provided
that safety requirements are met.
Option
Flaring
Lifetime
(years)
10
Reduction
Efficiency
(%)
99.99
Fixed Cost
($2000
US/tCO2 Eq)
2.81
Recurring
Cost ($2000
US/tCO2 Eq)
0.13
Cost Offset
($2000
US/tCO2 Eq)
0.00
Key References
Brunner, Daniel J. and Karl Schultz. September 1999. Gob Well Flaring: Design and Impact. CBM
Review. World Coal, Palladian Publications, Ltd, United Kingdom.
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-7
SECTOR:
Coal Mining
OPTION NAME:
Degasification and Power Production – C5 (30% recovery), C6 (50% recovery),
C7 (70% recovery)
OPTION ID:
C5 to C7
Brief Description
Coalmine methane is collected via vertical wells, horizontal boreholes, and gob wells and then is used to
power a gas turbine to produce heat and electricity. These three options differ in the level of methane
recovery, which is equal to 30, 50, and 70 percent.
State of Development and Current Level of Usage
The degasification and power production options are currently available. For example , most of major
European coal producers already have some recovery and power production based on coalmine methane.
Associated Risks and Uncertainties
Similar to options C1-C2, options C5-C7 are feasible when captured methane is of sufficient quality. The
quality requirements for the methane combusted for heat and electricity are, however, more relaxed in
comparison to methane sold to pipelines.
Potential Applicability in Different Regions
Technologically options C5-C7 can be applied at any mine with substantial methane flows and local
demand for electricity and heat. Based on European conditions in order to implement these options, the
mine has to produce at least 0.5 million tonnes of coal per year.
Option
Degasific ation and
Power Production A
(C5)
Degasification and
Power Production B
(C6)
Degasification and
Power Production C
(C7)
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
15
30
33.14
1.06
4.45
15
50
42.67
1.52
4.60
15
70
50.48
1.93
4.75
Key References
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-8
SECTOR:
Oil
OPTION NAME:
Flaring instead of Venting (Offshore)/ Flaring instead of Venting (Onshore)
OPTION ID:
O1, O2
Brief Description
Rather than venting methane emissions to atmosphere the methane is flared. Flaring serves as a better
alternative since it burns the gas, thus converting it to carbon dioxide.
State of Development and Current Level of Usage
These options are well developed technologically. In fact, flaring efficiencies may range from 95 to 99.8
percent. They are widely used in several regions, including the U.S. and Europe. For other regions, such
as Russia and Africa, where there is a relatively low level of sector investment, such options may not be
prevalent. This trend is specifically applicable to offshore flaring, which requires larger investment costs
due to the technical, environmental, and safety issues associated with offshore implementation.
Associated Risks and Uncertainties
Standard safety precautions need to be taken to manage the risk associated with flaring.
Potential Applicability in Different Regions
Flaring options, both onshore and offshore, are applicable to all regions. However, the implementation
may be limited due to facility-specific technical, environmental, and safety constraints.
Option
Flaring instead of
venting (offshore)
Flaring instead of
venting (onshore)
Reduction
Lifetime
Efficiency
(years)
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
15
98
760.2
22.81
0.00
15
98
30.41
0.91
0.00
Key References
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-9
SECTOR:
Oil
OPTION NAME:
Associated Gas (vented) Mix Other Options/Associated Gas (flared) Mix Other
Options
OPTION ID:
O3, O4
Brief Description
Mitigation techniques for vented associated gas includes, the re-injecting of gas into the field to maintain
formation pressure and enhance oil recovery, and the use of gas for platform or domestic consumption.
For flared associated gas, the option relates to techniques of improving flaring efficiencies, as well as the
use of the gas to be flared for re-injection into the oil field.
State of Development and Current Level of Usage
These options are well developed technologically. The re-injection and flaring of associated gas is
common practice in offshore OECD-European facilities (EC, 2001). In North America, associated gas is
typically captured for re-use (U.S. EPA, 1999). For developing oil regions, such as Eastern/Central
Europe and Africa, where there is a low level of sector investment, such options may not be prevalent and
most of associated gas is vented.
Associated Risks and Uncertainties
Due to infrastructure costs, the implementation of re-injection is only viable if the increased oil recovery
yields lead to improved oil revenues. Oil recovery yields vary from field to field, and are dependent on
the type of oil present, and geological formation. The reuse of associated gas, instead of flaring, may not
decrease methane emissions, since emissions resulting from the transportation and treatment of the gas
may be on the same order of magnitude as flaring (EC, 2001). Typically flare efficiencies range from 9599 percent. In certain developed regions, such as OECD-Europe, flare efficiencies may be close to the
upper bound of this range. Consequently, the scope for improvement from the implementation of this
option may be limited (EC, 2001).
Potential Applicability in Different Regions
Both options are potentially applicable to all the regions. However, the implementation of re-injection and
re-use techniques may vary based on regional geological and infrastructural conditions, respectively. For
example, in OECD-Europe at offshore facilities, existing infrastructure in the form of pipelines to onshore
facilities enables the reuse of associated gas. For the implementation of improved flaring options, the
presence of flaring infrastructure is required.
Option
Associated gas (vented)
mix with other options
Associated gas (flared)
mix with other options
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
15
90
50.68
1.01
4.78
15
95
60.82
2.03
4.78
B-10
Key References
U.S. Environmental Protection Agency, September 1999. “U.S. Methane Emissions 1990-2000:
Inventories, Projections, and Opportunities for Reductions.” U.S. EPA 430-R-99-013, Washington, D.C.
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-11
SECTOR:
Natural Gas
OPTION NAME:
Installation of Electric Starters; Dry Seals; and Static Pacs on Compressors/Fuel
Gas Retrofit for Blowdown Valves
OPTION ID:
NG8, NG9, NG12, NG23
Brief Description
Installation of dry seals on centrifugal compressors (NG8): ’Wet’ seal centrifugal compressors use highpressure oil to prevent gas from escaping around the rotating shaft. Some of the methane is absorbed by
the oil and subsequently vented to atmosphere when the oil is stripped of its gas prior to re-circulation.
‘Dry’ seals use high-pressure gas to ensure sealing. Dry seals emit far less gas compared to wet seal
systems, and are also more economical to operate and maintain.
The negative recurring cost of NG8 option is associated with reduced power consumption, improved
reliability, and lower maintenance.
Fuel gas retrofit of blowdown valves (NG9): When a compressor is “blown down”, i.e., taken off-line,
methane can leak from the blowdown valve or unit isolation valves depending on the system
pressurization. Using a fuel gas retrofit, the methane that would be vented during a blow down can be
routed to a fuel gas system.
Installation of Static -Pacs on reciprocating compressors (NG 12): A Static -Pac seal is installed on a
compressor rod around conventional compressor packing seals. When the compressor is off-line, but still
pressurized, the Static Pac activates to clampdown on the packing seals, such that a tight seal is developed
between the compressor rod and packing system, thus eliminating methane leakage around the rodpacking.
Installation of electric starters on compressors (NG23) : Small gas expansion turbine motors are used to
start internal combustion engines for compressors and generators. These starters use compressed natural
gas, which is vented to atmosphere, to provide the initial push to start the engine. An electric starter can
be used in its place that will prevent such wastage of natural gas.
State of Development and Current Level of Usage
These options are well developed technologically. The extent of their current use depends on the design
of regional systems. For example, transmission systems in Europe and Russia utilize centrifugal
compressors, many of which are already dry seal configurations; consequently, the use of dry seal
installations may not be necessary. Furthermore, the implementation of Static Pacs will only be applicable
to those systems that rely on reciprocating compressors, such as the U.S. system.
Associated Risks and Uncertainties
The operation and use of electric starters require the availability of a reliable power supply. In remote
locations, without any existing power supply, this may necessitate the installation of a generator or solar
batteries increasing capital costs.
Dry seal conversions may not be possible on some compressors because of housing design or operational
requirements (i.e., to operate at high temperatures and/or pressures). Furthermore, some older
compressors may be candidates for complete replacement rather than only seal replacement.
B-12
Using a Static -Pac may not be cost-effective if a fuel gas retrofit is installed, since emissions from
compressors would already be substantially reduced.
Potential Applicability in Different Regions
Dry seals conversions; fuel gas retrofits and the installation of Static -Pacs on compressor rod packings are
feasible in any region that uses reciprocating compressor technology, e.g., U.S. For regions that use
centrifugal compressors, such as Europe and Russia, the Static Pac option may not be applicable. The
installation of electric starters is possible at all regional locations/facilities if reliable electric supply
exists.
Option
P&T-Dry Seals on
Centrifugal
Compressors (NG8)
P&T-Fuel Gas
Retrofit for
Blowdown Valve
(NG9)
P&T-Reciprocating
Compressor Rod
Packing (Static -Pac)
(NG12)
Prod-Electric Starter
for Compressors
(NG23)
Lifetime
(years)
Reduction
Efficiency
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurrin
g Cost
($2000
US/tCO2
Eq)
Cost
Offset
($2000
US/tCO2
Eq)
5
69
96.68
-25.38
4.78
5
33
1.94
0.00
4.78
1
6
14.58
0.56
4.78
10
75
8,384
2,096
4.78
Key References
U.S. Environmental Protection Agency. “Reducing Emissions when taking compressors Off-line.”
Lessons Learned from Natural Gas STAR Partners, http://www.epa.gov/gasstar/reduce.
U.S. Environmental Protection Agency. “Reducing Methane Emissions from Compressor Rod Packing
Systems.” Lessons Learned from Natural Gas STAR Partners, http://www.epa.gov/gasstar/packing.htm
U.S. Environmental Protection Agency. “Replacing Wet Seals with Dry Seals in Centrifugal
Compressors” Lessons Learned from Natural Gas STAR Partners, http://www.epa.gov/gasstar/seals.htm
U.S. Environmental Protection Agency. Natural GasSTAR Program’s Partner Reported Opportunities
“Installing Electric Starters”, http://www.epa.gov/gasstar/pro/installelectricstarters.pdf
U.S. EPA 2003. International Analy sis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-13
SECTOR:
Natural Gas
OPTION NAME:
Installing Plunger Lift Systems In Gas Wells
OPTION ID:
NG25
Brief Description
Traditional remedial operations to prevent/remove gas well blockage resulting from fluid accumulation
include, swabbing, soaping, or venting the well to atmospheric pressure). However, these operations
typically result in large volumes of methane being emitted to the atmosphere. The installation of a plunger
lift can help remove these liquids cost-effectively and at the same time reduce methane emissions. A
plunger lift uses the well’s natural energy to lift the fluids out of the well and helps maintain the
production level.
State of Development and Current Level of Usage
This option is well developed technologically, but is not widely used. In the U.S., it is being implemented
by a growing number of companies at their wells sites.
Associated Risks and Uncertainties
The installation of plunger lifts has the potential to increase gas production; however, this may be
accompanied by an increase in the production of oil and water. While oil production can provide more
revenue, water production may require larger disposal costs. Furthermore, installing a plunger lift requires
the presence of a continuous tubing string that should be kept in good condition. If the tubing string
requires replacement, installation costs can increase considerably, thus impacting the economic
effectiveness.
Potential Applicability in Different Regions
Plunger lifts are applicable in all regions where natural gas wells that have sufficient gas volume and gas
pressure to move liquids with some assistance.
Option
Prod-Installing
Plunger Lift Systems
In Gas Wells
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
10
4
3,985
159.42
4.78
Key References
U.S. Environmental Protection Agency. “Installing Plunger Lift Systems in Gas Wells.” U.S. EPA
Lessons Learned from Natural Gas Star Partners. April 2001. EPA 430-B-01-004.
http://www.epa.gov/gasstar/plunger.htm
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-14
SECTOR:
Natural Gas
OPTION NAME:
Catalytic Converter
OPTION ID:
NG2
Brief Description
A catalytic converter burns the emitted methane from incomplete fuel combustion, thus reducing
emissions of natural gas into the atmosphere.
State of Development and Current Level of Usage
This option is well developed technologically. Other than possibly developed regions, such as Europe and
U.S., which have emission control requirements, the current level of usage for this option is not
widespread.
Associated Risks and Uncertainties
None.
Potential Applicability in Different Regions
This option is applicable to all regions.
Option
P&T - Catalytic
Converter
Reduction
Lifetime
Efficiency
(years)
(%)
10
56
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
91.46
4.82
0.00
Key References
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-15
SECTOR:
Natural Gas
OPTION NAME:
Use of Gas Turbines Instead of Gas Reciprocating Engines.
OPTION ID:
NG17
Brief Description
Turbines have a better combustion efficiency compared to reciprocating engines; consequently, replacing
reciprocating engines with turbines reduces methane emissions.
State of Development and Current Level of Usage
Turbines are well developed technologically, and are currently widely implemented in several regions,
including the OECD-Europe, Eastern and Central Europe, and FSU regions.
Associated Risks and Uncertainties
Natural gas turbines typically require a constant fuel source; consequently, the use of residual gases from
other natural gas processes as an energy supply may not be utilized. Furthermore, if the combustion
efficiency of the turbine is lower than the reciprocating engine that it replaces, it is possible that the
subsequent increased carbon dioxide emissions will negate the potential methane reductions (EC, 2001).
Pote ntial Applicability in Different Regions
This option can be implemented in all regions, except those that predominantly utilize turbine
compressors, such as the OECD-Europe, Eastern and Central Europe, and FSU regions.
Option
Lifetime
(years)
P&T- Use of Gas
Turbines Instead
of Gas
Reciprocating
Engines
20
Reduction Fixed Cost
Recurring
Cost Offset
Efficiency
($2000
Cost ($2000
($2000
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
90
152.04
7.60
0.00
Key References
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-16
SECTOR:
Natural Gas
OPTION NAME:
Altering Start-up Procedures During Maintenance
OPTION ID:
NG1
Brief Description
During monthly “cleaning” maintenance, turbines are typically shut down and operations switched to
another unit. To reduce the emissions associated with depressurizing the compressor, the turbines can be
cleaned while on-line (running). This procedure reduces the number of compressor depressurizations
required per year.
State of Development and Current Level of Usage
The option is well developed technologically, and is utilized by other industries for cleaning natural gas
turbines (EC, 2001); however, it is not widely implemented in the natural gas industry.
Associated Risks and Uncertainties
The proposed option involves the spraying of deionised water into the compressor while online (running)
(EC, 2001). Since this method is utilized in various other industries, there is little risk or uncertainty
associated with this application.
Potential Applicability in Different Regions
This option can be implemented in all regions that utilize natural gas centrifugal compressors.
Option
P&T-Altering
Start-Up
Procedure
during
Maintenance
Reduction
Lifetime
Efficiency
(years)
(%)
1
100
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
0.00
0.00
4.78
Key References
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-17
SECTOR:
Natural Gas
OPTION NAME:
Replacement of Cast Iron/Unprotected Steel Pipeline/Replacement of
Unprotected Steel Services.
OPTION ID:
NG34, NG35
Brief Description
Cast iron and unprotected steel pipeline link the natural gas distribution system and are prone to corrosion
and leaks. They should be replaced with pipeline made of non-corrosive material that will reduce methane
losses from the distribution system. Plastic or protected steel pipelines are good replacements.
Unprotected steel services are low pressure lines that link the distribution system to the consumer and are
similarly prone to corrosion and leaks. They should be replaced with services made of non-corrosive
material, such as plastic or protected services, which will reduce methane losses from the distribution
system.
State of Development and Current Level of Usage
These options are well developed technologically, and are widely implemented in several regions,
including the U.S. and Europe.
Associated Risks and Uncertainties
Replacing pipelines and services will involve high capital costs and extensive digging, which may be
inconvenient in populated areas.
Potential Applicability in Different Regions
This option can be implemented in all regions.
Option
D-Replace Cast
Iron/Unprotected
Steel Pipeline
(NG34)
D-Replace
Unprotected
Steel Services
(NG35)
Reduction
Lifetime
Efficiency
(years)
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
5
95
17,259
0.86
4.78
5
95
410,827
82.17
4.78
Key References
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-18
SECTOR:
Natural Gas
OPTION NAME:
Electronic Monitoring at Large Surface Facilities
OPTION ID:
NG33
Brief Description
Natural gas distribution systems supply gas to meet nearby customer demand. Since peak demand periods
are infrequent, distribution systems operate at high gas pressures to ensure that peak and non-peak
operating pressures are met. High system operating pressures contribute to higher operating costs and
increased gas leakage. By installing electronic monitoring systems, the distribution system pressure can
match real time demand more closely and thus reduce fugitive methane emissions.
State of Development and Current Level of Usage
This option is well developed technologically. It is used in the US and Europe. However, due to cost and
infrastructural requirements the level of usage in developing regions is low.
Associated Risks and Uncertainties
Currently, there are several electronic monitoring methods available, each with varying costs and
effectiveness based on the type of distribution system being upgraded. For example, for older systems
using cast iron piping, which leak more, the potential savings from reduced gas loss and leak repair costs
may justify the cost of more accurate automated control systems.
Potential Applicability in Different Regions
This technology is applicable in all regions. However, since the hardware required for electronic
monitoring includes connections to electrical power supply, the implementation will be subject to
infrastructural requirements. For developing regions such as China and Africa, their electricity
consumption is estimated to grow at a rate of 4.2 percent annually through 2020; consequently, this
growth will result in significant expansion of their local infrastructures (EIA, 2002).
Option
D-Electronic
Monitoring at
Large Surface
Facilities
Lifetime
(years)
Reduction
Efficiency
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
5
95
28.07
4.68
4.78
Key References
Energy Information Administration, March 2002, “International Energy Outlook, 2002.” DOE/EIA-0484
(2002).
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-19
SECTOR:
Natural Gas
OPTION NAME:
Portable Evacuation Compressor for Pipeline Venting
OPTION ID:
NG11, NG26
Brief Description
To conduct pipeline repairs and maintenance under safe working conditions requires that pipelines are
“blown down” (i.e., depressurized) to atmosphere to remove any gas present. This option relates to the
use of portable compressors to lower gas line pressure by up to 90 percent of its original value without
venting.
State of Development and Current Level of Usage
This option is well developed technologically, and is currently used in several regions, including the U.S.
and Europe. For other regions, such as Eastern Europe and Russia, usage levels for this option may be
low, due to a lack of sector investment.
Associated Risks and Uncertainties
Using a portable compressor is only possible if the compressor can physically connect to the pipeline.
Consequently, portable compressors require the presence of a downstream block valve that separates the
pressurized and non-pressurized sides of the pipeline. Furthermore, the use of these compressors is
generally only appropriate for situations where there is planned maintenance. During an emergency when
the pipeline requires immediate depressurization, mobilizing the compressor may be a problem.
Potential Applicability in Different Regions
Technologically, portable compressors can be used on any pipeline. However, the primary infrastructural
condition for use of the compressor is whether the pipeline has sufficient manifolding to enable the
compressor to connect to it. It is assumed that this infrastructural condition is present for all regions, and
that potential applicability is not affected.
Option
P&T-Portable
Evacuation
Compressor for
Pipeline Venting
(NG11)
Prod-Portable
Evacuation
Compressor for
Pipeline Venting
(NG26)
Reduction
Lifetime
Efficiency
(years)
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
15
72
318.58
2.28
4.78
15
72
318.58
2.28
4.78
B-20
Key References
U.S. Environmental Protection Agency. “Using Pipeline Pump-Down Techniques to Lower Gas Line
Pressure Before Maintenance.” Lessons Learned from Natural Gas STAR Partners,
http://www.epa.gov/gasstar/usepipepump.htm
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-21
SECTOR:
Natural Gas
OPTION NAME:
Directed Inspection and Maintenance (DI&M)
OPTION ID:
NG3 to NG7, NG18 to NG22, NG31, and NG32
Brief Description
Directed inspection and maintenance programs involve surveying facilities and equipment to identify
sources of leak. This information can be used to direct maintenance activities to make cost-effective
repairs.
Enhanced DI&M is a more aggressive DI&M program that involves increased survey and repair
frequencies. It costs more but also achieves greater gas savings.
State of Development and Current Level of Usage
This option is well developed technologically, and is widely used in several regions, including the U.S.
and Europe. For other regions, such as Russia, where there is a low level of sector investment, DI&M
may not occur to the levels experienced in the U.S. or Europe.
Associated Risks and Uncertainties
None.
Potential Applicability in Different Regions
All instrumentation used for screening and measurement is available to all regions.
Option
P&T-D I&M
(Compressor
Stations) (NG3)
P&T-D I&M
(Compressor
Stations:
Enhanced) (NG4)
P&T-D I&M
(Enhanced:
Storage Wells)
(NG5)
P&T-D I&M
(Pipeline:
Transmission)
(NG6)
P&T-D I&M
(Wells: Storage)
(NG7)
Prod-D I&M
(Chemical
Reduction
Lifetime
Efficiency
(years)
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
5
13
0.57
1.86
4.78
5
20
0.40
2.43
4.78
5
50
38.11
50.82
4.78
5
60
786.60
1,179.90
4.78
5
33
38.50
38.50
4.78
5
40
123.15
6.82
4.78
B-22
Inspection Pumps)
(NG18)
Prod-D I&M
(Enhanced)
(NG19)
Prod-D I&M
(Offshore)
(NG20)
Prod-D I&M
(Onshore) (NG21)
Prod-D I&M
(Pipeline Leaks)
(NG22)
D-D I&M
(Distribution)
(NG31)
D-D I&M
(Enhanced:
Distribution)
(NG32)
5
50
246.40
344.96
4.78
5
33
45.82
15.27
4.78
5
33
193.25
289.88
4.78
5
60
22.78
34.18
4.78
5
26
4.88
5.76
4.78
5
66
21.14
21.09
4.78
Key References
U.S. Environmental Protection Agency. 1997. “Directed Inspection and Maintenance at Compressor
Stations”. U.S. EPA Lessons Learned from Natural Gas Star Partners. October 1997. EPA 430-B-97-009.
http://www.epa.gov/gasstar/direct.htm.
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-23
SECTOR:
Natural Gas
OPTION NAME:
Reducing the Glycol Circulation Rates in Dehydrators/Installation of Flash Tank
Separators
OPTION ID:
NG10, NG13, NG24, NG27
Brief Description
Reducing glycol circulation rates in dehydrators: Tri-ethylene Glycol (TEG) is used in dehydrators to
absorb water from gas before it enters the pipeline. During this process, however, TEG also absorbs some
methane, which is then vented to the atmosphere when the glycol is regenerated. The amount of methane
absorbed is directly proportional to the TEG circulation rate. Maintaining the glycol circulation rate at an
optimal level will ensure that methane emissions are kept at a minimum.
Installation of flash tank separators: A flash tank separator operates by ‘flashing’ (or vaporizing) methane
that is absorbed in TEG. This is achieved by reducing the pressure of the TEG stream in the dehydrator.
The flashed methane can be collected for sale or use as a fuel gas.
State of Development and Current Level of Usage
This option is well developed technologically; however it is not widely implemented. For example, in the
U.S., most dehydrators do not have flash tank separators, and vent all of the methane to the atmosphere.
In the U.S., flash tanks are typically not used on dehydration units that process less than one million cubic
feet (MMCF) of gas per day. For units processing more than one but less than five MMCF/day,
approximately 60 percent utilize flash tanks, while for those that process more than five MMCF/day,
approximately 30 percent operate with flash tanks.
Associated Risks and Uncertainties
The costs to install flash tank separators are dependent on several facility-specific conditions such as, the
location, terrain, automation and instrumentation. Depending on these site-specific factors, installation
costs may increase by over 80 percent, which would impact the economic attractiveness of the option,
particularly in undeveloped regions.
B-24
Potential Applicability in Different Regions
The implementation of flash tank separators and the reduction of glycol dehydration rates are applicable
to all regions.
Option
P&T-Installation of
Flash Tank
Separators
(Transmission &
Storage) (NG10)
P&T- Reducing the
Glycol Circulation
Rates in Dehydrators
(not applicable to
Kimray pumps)
(NG13)
Prod-Installation of
Flash Tank
Separators
(Production) (NG24)
Prod-Reducing the
Glycol Circulation
Rates in Dehydrators
(not applicable to
Kimray pumps)
(NG27)
Reduction
Lifetime
Efficiency
(years)
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
5
61
32.59
0.00
4.78
1
30
0.00
0.87
4.78
5
54
100.98
0.00
4.78
1
31
0.00
1.72
4.78
Key References
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
U.S. Environmental Protection Agency. “Reducing the Glycol Circulation Rates in Dehydrators.” Lessons
Learned from Natural Gas STAR Program, U.S. Environmental Protection Agency.
http://www.epa.gov/gasstar/convertgas.htm
U.S. Environmental Protection Agency. “Installation of Flash Tank Separators.” Lessons Learned from
Natural Gas STAR Program, U.S. Environmental Protection Agency.
http://www.epa.gov/gasstar/convertgas.htm
B-25
SECTOR:
Natural Gas
OPTION NAME:
Replacement of high-bleed pneumatic devices with low-bleed pneumatic devices
or with Compressed Air Systems.
OPTION ID:
NG14, NG15, NG28, NG29
Brief Description
Natural gas-powered pneumatic devices are widely used for process control applications like pressure,
temperature, liquid level and flow-rate regulation. These pneumatic devices are designed to emit natural
gas as part of their normal operations, which depending on the type of device/operation can be quite large.
Such high-bleed pneumatic devices can be replaced with low-bleed devices that are designed to emit
about 80-90% less methane. Another option is to replace the high-bleed devices with compressed air
systems. This option will completely eliminate the methane emissions from these pneumatic devices.
State of Development and Current Level of Usage
These options are well developed technologically, and are implemented in many countries, including the
U.S. and Canada. In other regions, such as Europe, natural gas operated devices are not common, since
most pneumatics are controlled by electricity or pressurized air. Consequently, emissions from
pneumatics in Europe are negligible.
Associated Risks and Uncertainties
Compressed air systems require electric power and an air compressor to operate. Therefore a reliable
power supply and compressor are required to ensure consistent operation of the air system.
Potential Applicability in Different Regions
Facilities that are situated in remote locations may not have existing power supplies. In such locations, the
cost of installing a power generating facility may not be economical. Therefore, installations of
compressed air systems are more suitable for facilities that have existing power supply arrangements.
Consequently, regions where there is limited electrical infrastructure, such as China and Russia, may have
limited applicability. Furthermore, regions, such as Europe, that do not utilize natural gas operated
pneumatics may not require this option.
B-26
Option
P&T-Replace
High-bleed
pneumatic devices
with compressed air
systems (NG14)
P&T-Replace highbleed pneumatic
devices with lowbleed pneumatic
devices (NG15)
Prod-Replace Highbleed pneumatic
devices with
compressed air
systems (NG28)
Prod-Replace highbleed pneumatic
devices with lowbleed pneumatic
devices (NG29)
Reduction Fixed Cost
Lifetime
Efficiency
($2000
(years)
(%)
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
5
100
7.09
64.48
4.78
5
86
14.01
0.00
4.78
5
100
6.82
62.06
4.78
5
86
14.01
0.00
4.78
Key References
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
U.S. Environmental Protection Agency. “Convert Gas Pneumatic Controls to Instrument Air”. Lessons
Learned from Natural Gas STAR Program, U.S. Environmental Protection Agency.
http://www.epa.gov/gasstar/convertgas.htm
U.S. Environmental Protection Agency. “Options for Reducing Methane Emissions from Pneumatic
Devices in the Natural Gas Industry”. Lessons Learned from Natural Gas STAR Program, U.S.
Environmental Protection Agency. http://www.epa.gov/gasstar/pneumat.htm
B-27
SECTOR:
Natural Gas
OPTION NAME:
Surge Vessels for Station/Well Venting
OPTION ID:
NG16, NG30
Brief Description
A large quantity of methane is vented as a result of well blowdowns or station venting. Surge vessels
enable the capture of methane, thus avoiding venting, for rerouting to pipelines or fuel use.
State of Development and Current Level of Usage
This option is well developed technologically, but is not widely used, due to high capital costs.
Associated Risks and Uncertainties
Implementing surge vessels at compressor stations and well sites will involve high capital costs and
extensive digging, which may have safety implications.
Potential Applicability in Different Regions
This option is applicable to all regions.
Option
P&T-Surge Vessels
for Station/Well
Venting (NG16)
Prod-Surge Vessels
for Station/Well
Venting (NG30)
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
10
50
11,226
224.52
4.78
10
50
11,226
224.52
4.78
Key References
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-28
SECTOR:
Landfills of Solid Waste
OPTION NAME:
Anaerobic digestion 1, Anaerobic digestion 2
OPTION ID:
LF1, LF2
Brief Description
In landfills, the decomposition of organic material without oxygen occurs naturally. Anaerobic digestion
expedites this process by using a vessel that excludes oxygen and maintains the temperature, moisture
content and pH close to their optimum values. Methane from ana erobic digestion plants can be used to
produce heat and/or electricity. The solid residue from the process can be ‘cured’ under aerobic
conditions to form a substance that can be used as a soil improver, which has a market value. Costs
include the plant investment and operating costs, as well as the landfill disposal of low quality residues.
Income from compost, income from energy, and avoided landfilling are treated as negative costs.
Two variants of anaerobic digestion option were analyzed in the EC report (EC, 2001). One of them, with
lower costs and higher benefits, did not include the cost of source separating the waste prior to disposal in
the anaerobic digestion system (AD1). The other option incorporated this cost (AD2).
State of Development and Current Level of Usage
Anaerobic digestion is a well-developed technology and is widely used in EU countries . In some of the
FSU countries (e.g., Russia and Ukraine) this technology is tested at pilot facilities.
Associated Risks and Uncertainties
Anaerobic digestion is economically feasible if sufficient quantities of methane gas and high-quality
residue are produced to offset the project costs, and if a market exists for this methane and residue.
Anaerobic digestion requires a well-controlled environment. Consequently, if the environment is not
properly controlled, methane recovery may be insufficient to support the project costs. Similarly, to the
extent that contamination occurs, the value of the solid residue can be significantly diminished.
Potential Applicability in Different Regions
Technologically, anaerobic digestion can be applied in any location with sufficient market for energy
produced by anaerobic digestion plants If the methane from an anaerobic digestion facility is directly
combusted (e.g., in an industrial boiler), the technology requires an energy end user and adequate pipeline
infrastructure.
Option
Anaerobic Digestion 1
Anaerobic Digestion 2
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
15
95
400.98
67.61
8.74
15
95
484.91
125.89
5.25
Key References
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-29
SECTOR:
Landfills of Solid Waste
OPTION NAME:
Composting (1 and 2), Mechanical Biological Treatment
OPTION ID:
LF3 to LF5
Brief Description
Both composting and mechanical biological treatment involve degradation of the organic matter under
aerobic conditions. Composting can be done in private households (home composting) and in central
locations. If done in a central location, a number of methods are available, including windrow systems
and tunnel composting. In both households and central locations, composting requires separating organic
matter from the waste stream. Finished compost has a market value, as it can be used to enhance soil in
horticulture/landscape and agricultural sites.
Mechanical-biological treatment (MBT) does not involve separating out the organic matter. Rather, the
whole waste stream is composted in order to aerobically degrade the organic fraction. However, while
the technology eliminates the need for source separation, the inorganic matter that does not degrade
becomes residue that must be disposed of in a landfill. The process also does not create a useable byproduct.
EC study analyses two variants of the composting option (CM1 and CM2) : the first composting option is
a 25,000 ton/year tunnel plant, based on an existing plant in the UK; the second option is a 50,000 ton/yr
tunnel plant, based on an existing plant in the Netherlands.
State of Development and Current Level of Usage
Composting is a well-developed technology that is currently applied in many regions, and is being
heavily promoted in several EU countries. Implementation of mechanical biological treatment is much
less common, and the technology is currently applied in only a few regions globally.
Associated Risks and Uncertainties
Both options become economically feasible if source separation costs are minimal. In addition, the
composting process must be well managed in an aerobic environment, as methane formation may
otherwise occur. Finally, the potential market value of compost is likely to fluctuate by region and over
time.
Potential Applicability in Different Regions
Technologically, both composting and mechanical biological treatment can be applied in any region of
the world
Option
Composting 1
Composting 2
Mechanical Biological
Treatment
Lifetime
(years)
15
15
15
Reduction Fixed Cost
Recurring
Efficiency
($2000
Cost ($2000
(%)
US/tCO2 Eq) US/tCO2 Eq)
100
359.02
93.25
100
424.29
81.59
95
359.02
121.23
Cost Offset
($2000
US/tCO2 Eq)
0.00
0.00
0.00
B-30
Key References
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-31
SECTOR:
Landfills of Solid Waste
OPTION NAME:
Heat Production
OPTION ID:
LF6
Brief Description
Landfill gas is piped directly to a nearby end user to be used as a replacement or supplementary fuel
source. Examples of end uses include industrial boilers, brick kilns and lime or cement kilns. In these
projects, the sale of recovered gas becomes a cost offset.
State of Development and Current Level of Usage
Heat production from landfill gas is a well-developed technology that is commonly applied in North
America and European Union.
Associated Risks and Uncertainties
Heat production projects require a sufficient demand for landfill gas such that market prices for the gas
can support the project. In addition, the landfill must produce adequate levels of methane in order to
generate enough revenue to offset project costs. Finally, landfills must be located near the end consumer
in order to minimize pipeline costs.
Potential Applicability in Different Regions
Heat production can be applied in countries with landfills that produce significant quantities of methane
to offset project costs, and in which there is significant market demand for landfill gas as a heat source.
The technology may not be available in unmanaged landfills, since these landfills typically lack the
anaerobic conditions necessary for significant levels of methane formation.
Option
Lifetime
(years)
Heat Production
20
Reduction
Efficiency
(%)
70
Fixed Cost
($2000
US/tCO2 Eq)
7.30
Recurring
Cost ($2000
US/tCO2 Eq)
1.71
Cost Offset
($2000
US/tCO2 Eq)
6.03
Key References
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-32
SECTOR:
Landfills of Solid Waste
OPTION NAME:
Increased Oxidation
OPTION ID:
LF7
Brief Description
Improving the capping and restoration layers reduces methane emissions. A clay cap minimizes methane
leakage, while landfill cover soils above the cap oxidize escaping methane. Costs include installing the
clay cap and restoration layer, and annual maintenance costs.
State of Development and Current Level of Usage
Capping and covering is already a common practice in countries with modern landfills.
Associated Risks and Uncertainties
Costs are highly dependent on the availability of clay for improving the cap and soil for improving the
cover. Costs will increase significantly if these materials must be transported from far distances.
Potential Applicability in Different Regions
Increasing oxidation (IO) of landfill gas is applicable to countries with managed landfills that produce
methane. The technology is not applicable to countries in which waste is deposited in unmanaged
landfills, since these landfills already operate in an aerobic environment, and consequently produce little
methane.
Option
Increased Oxidation
Lifetime
(years)
50
Reduction Fixed Cost
Efficiency
($2000
(%)
US/tCO2 Eq)
44
465.43
Recurring
Cost ($2000
US/tCO2 Eq)
0.63
Cost Offset
($2000
US/tCO2 Eq)
0.00
Key References
EC. 2001. Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change.
European Commission, Brussels. (Available on the Internet at
http://europa.eu.int/comm/environment/enveco/climate_change/sectoral_objectives.htm)
B-33
SECTOR:
Landfills of Solid Waste
OPTION NAME:
Direct Gas Use – Profitable at Base Price, Direct Gas Use – Profitable above
Base Price
OPTION ID:
LF8, LF9
Brief Description
Landfill gas is piped directly to a nearby end user for use as a replacement of natural gas In these
projects, the sale of the landfill gas offsets the costs for the project. Costs include a gas collection and
flare system, gas treatment, gas compression to 50 pounds per square inch (psi), and a five-mile gas
pipeline to a customer.
Two variants of this option are analyzed: direct gas use is profitable at a base energy price of
$2.74/mmBtu (DG1) and direct gas use profitable above this base price (DG2). The cost and potential
reductions for both of these options were estimated as a function of landfill size (using a model of U.S.
landfills). Larger landfills, in which sufficient methane was generated to offset project costs, were more
likely to be profitable under the base price than smaller landfills.
State of Development and Current Level of Usage
Direct gas use projects are well developed and account for approximately one third of U.S. landfill gas-toenergy projects.
Associated Risks and Uncertaintie s
Direct gas projects require a sufficient demand for landfill gas such that market prices for the gas can
support the project. In addition, the landfill must produce adequate levels of methane in order to generate
enough revenue to offset project costs. Finally, landfills must be located near the end consumer in order to
minimize pipeline costs.
Potential Applicability in Different Regions
Direct gas projects can be applied in countries with landfills that produce significant quantities of
methane to offset project costs, and in which the end user is in relatively close proximity to the landfill.
The technology is not applicable to countries in which waste is deposited in unmanaged landfills, since
these landfills typically lack the anaerobic conditions necessary for significant levels of methane
formation.
Option
Direct Gas Use
(profitable at base
price)
Direct Gas Use
(profitable above
base price)
Lifetime
(years)
Reduction Fixed Cost
Efficiency
($2000
(%)
US/tCO2 Eq)
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
15
75
36.20
2.84
15
75
44.72
3.50
4.78
4.78
B-34
Key References
US EPA. 1999. U.S. Methane Emissions 1990-2010: Inventories, Projections, and Opportunities for
Reductions. Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, D.C.
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-35
SECTOR:
Landfills of Solid Waste
OPTION NAME:
Electricity Generation
OPTION ID:
LF10
Brief Description
Recovered methane is used to power a generating set and a connection is established to the electricity
distribution network. Costs include capital and O&M associated with the collection system, flare system,
and electricity production system. The analysis assumes electricity is produced using a reciprocating
internal combustion (IC) engine. Income from energy sales is included as a negative cost.
State of Development and Current Level of Usage
Electricity generation (EG) is a well-developed technology that is applied in the United States, European
Union, FSU, and some developing countries (e.g., India).
Associated Risks and Uncertainties
Electricity generation is feasible if sufficient electricity is generated to offset project costs. This condition
requires that landfills be sufficiently large so that they generate substantial quantities of methane. In
addition, the cost effectiveness of electricity projects largely depends on the market for electricity.
Adequate electricity price for sold electricity is a condition for cost-effective projects.
Potential Applicability in Different Regions
Landfill gas to electricity projects can be applied in countries with landfills that produce enough
electricity to offset project costs, and in which the market price for electricity is sufficiently high. The
technology is not applicable to countries in which waste is deposited in unmanaged landfills, since these
landfills typically lack the anaerobic conditions necessary for significant levels of methane formation.
Option
Electricity Generation
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
20
75
149.98
8.92
5.96
Key References
US EPA. 1999. U.S. Methane Emissions 1990-2010: Inventories, Projections, and Opportunities for
Reductions. Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, D.C.
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-36
SECTOR:
Landfills of Solid Waste
OPTION NAME:
Flaring
OPTION ID:
LF11
Brief Description
Recovered landfill gas is flared to control odor and gas migration. Costs include the capital and O&M for
the recovery and flaring equipment. Costs are based on the peak gas flow rate during the anticipated
operating lifetime of the collection system.
State of Development and Current Level of Usage
Flaring is a well-developed technology that is applied in many regions, including the United States and
European Union.
Associated Risks and Uncertainties
The cost of flaring equipment depends on individual landfill characteristics and gas recovery capacities.
Consequently, the cost effectiveness of flaring as a mitigation technology will fluctuate based on these
factors.
Potential Applicability in Different Regions
Flaring can be applied in countries with managed landfills that produce sufficient quantities of methane
such that flaring technologies are cost effective. Since developing countries typically have unmanaged
landfills with little methane production, flaring has limited applicability in these countries.
Option
Flaring
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
20
75
26.67
3.91
0.00
Key Refe rences
US EPA. 1999. U.S. Methane Emissions 1990-2010: Inventories, Projections, and Opportunities for
Reductions. Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, D.C.
U.S. EPA 2003. International Analysis of Methane and Nitrous Oxide Abatement Opportunities: Report
to Energy Modeling Forum, Working Group 21, U.S. Environmental Protection Agency, June 2003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports/index.htm)
B-37
SECTOR:
Wastewater Management
OPTION NAME:
Electricity Generation from Recovered Methane
OPTION ID:
W1
Brief Description
Anaerobic processes at wastewater treatment facilities present potential for capture and reuse of methane
emissions resulting from digester reactions (biogas). Biogas is typically utilized to generate heat or
electricity for reuse by the facility or is sold commercially to a local power company. Technologies such
as internal combustion engines, gas turbines, and fuel cells are often employed on-site in order to convert
biogas into desired end products.
State of Development and Current Level of Usage
In the U.S., methane abatement systems in anaerobic wastewater treatment making their way into
conventional use as means to supplement on-site power generation, and even to generate power for
purchase by local electric utilities. However, the overall frequency using this technology in industrial and
municipal wastewater treatment can be characterized as marginal at best. Comprehensive documentation
and sources of aggregate data on a national scale for these implementations are sparse and primarily
anecdotal. Industrial sources of interest are considerably more unclear, as treatment methods are often
not documented for public knowledge and effluent often contributes to municipal wastewater streams.
ICF developed a deterministic approach to estimate abatement quantities and costs based on national
estimates for municipal wastewater treatment that incorporates parameters derived from applicable
technology evaluations and frequency of use. While some of the parameters used in this analysis are open
for discussion (and in some cases are a result of industry-average “best guesses”), the developed approach
provides credible approximation of quantities and costs for this option.
Associated Risks and Uncertainties
This option is normally implemented when it is determined to be economically desirable in an
engineering cost-benefit study. The degree of return on investment normally justifies pursuit of biogas
reuse, however, it depends on regional energy prices. Variability in a facility’s annual operating
conditions and parameters is generally minimal.
Potential Applicability in Different Regions
Biogas reutilization is technically applicable wherever anaerobic digestion has been implemented.
Anaerobic digestion is more prominent in areas with a high density of environmentally sensitive
receptors, where real estate is tight, and odour control is a major requirement. Regions with higher urban
density are more likely candidates for such processes, as opposed to lagoons or aerobic processes.
Approach to Developing Technological and Cost Characteristics of the Wastewater Management
Option
Personal communication with an industrial manufacturer1 of anaerobic digesters indicates that
approximately 70% of all air emissions from wastewater treatment are actually captured by an anaerobic
digester installation.
1
Framatome ANP DE&S (formerly Duke Engineering & Services)
B-38
The fixed costs for the anaerobic digestion option were estimated based on the U.S. circumstances. The
total amount of (captured) methane emissions originating from anaerobic digestion, which represents the
total potential available nationally for abatement and reuse under this option, is estimated to be more than
909 kilotonnes of CH4 in 2000.
Based on methane LHV and assuming 50 percent average combustion efficiency in electrical conversion
equipment (including turbines, internal combustion engines, fuel cells, and combinations thereof), a
magnitude of approximately 4.2 billion kilowatt-hours (kWh) is a total amount of electricity that can be
generated by this option in the U.S.
In estimating the costs associated with the electricity generation option, it is imperative to separate the
costs of construction and maintenance of the anaerobic digester from the methane collection and
generation equipment. The costs associated with this option only reflect the collection and generation ,
and exclude the costs of constructing and operating the entire anaerobic system.
Cogeneration costs from a few sites in North America, which implement methane abatement and reuse
technologies, were compiled to generate a crude linear regression with plant capacity as the independent
variable [(r2 ) = 0.72]. Costs were inflated to reflect $ (2000) U.S. The regression was applied to the total
wastewater capacity available to this option and resulted in a unit capital cost of $262/tonne CH4 .
Recurring costs were estimated using an engineering estimate of 5 percent of capital costs2 , or about
$13/tonne CH4 .
The cost offset for the electricity generation option was set at the same level as for the option of using
landfill gas for electricity generation.
Option
Electricity
Generation from
Recovered Methane
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
30
70
11.39
0.57
5.96
Key References
Buckius, Howell. (1992) Fundamentals of Engineering Thermodynamics. New York: McGraw-Hill, Inc.,
p. 730
Intergovernmental Panel on Climate Change, Greenhouse Gas Inventory Reference Manual: Revised
1996 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 3 (Paris, France, 1997)
Energy Information Administration, Form EIA-861, "Annual Electric Utility Report", 2000.
Framatome ANP DE&S (formerly Duke Engineering & Services)
2
Dr. Kannan Vembu, P.E., pers. comm..
B-39
SECTOR:
Nitric Acid Production
OPTION NAME:
BASF - High Temperature Catalytic Reduction Method (BASF – HTCR)
OPTION ID:
NAC1
Brief Description
This is a high temperature catalytic reduction method proposed by BASF that decomposes N2O to
nitrogen (N2 ) and oxygen (O2 ) by using a catalyst. The catalyst composition is 'O3-80' : CuO on an Al2 O3
carrier. The catalyst is used directly behind the Pt/Rh gauzes in the ammonia burner. The catalyst
decomposes the N2 O gas at high temperatures (800 °C to 900 °C) to nitrogen (N2 ) and oxygen (O2 ).
State of Development and Current Level of Usage
The catalyst has been installed and is currently being tested inside a commercially operating plant.
Associated Risks and Uncertainties
There is an uncertainty to the claim by BASF that the catalyst leads to no NO conversion with a 0.3 to
0.5% error after being more than 2 years operational in 2 commercial scale plants. Possible safety
problems exist with Cu occurrence in the fertilizer product; sometimes a filter is needed.
Potential Applicability in Different Regions
The design of the BASF catalyst bed can be implemented in any standard HNO3 plant.
Option
BASF-HTCR
Reduction Fixed Cost
Recurring
Lifetime
Efficiency
($2000
Cost ($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq)
10
80
2.76
0.17
Cost Offset
($2000
US/tCO2 Eq)
0.00
Key References
Jos Kuiper. 2001. “High Temperature Catalytic Reduction of Nitrous Oxide Emission from Nitric Acid
Production Plants.” Continental Engineering, No. 1, Amsterdam, The Netherlands, October 2001.
NOVEM Project No. 375001/0080.
B-40
SECTOR:
Nitric Acid Production
OPTION NAME:
ECN - Low temperature selective catalytic reduction with propane addition (ECN
– LTSCR)
OPTION ID:
NAC2
Brief Description
ECN uses an extra reactor to convert the N2 O in the off-gas of the production process. Propane is used as
an additive in this reduction process. Propane is mixed with the off-gas stream before entering the reactor.
The product stream of the production process is not influenced because this method reduces the N2O in
the off-gas of the production process. The catalyst composition is a Fe-NH4-Zeolite-27 or 55-type
catalyst.
State of Development and Current Level of Usage
This option is in the lab test phase. A pilot plant scale test has been considered.
Associated Risks and Uncertainties
Only lab tests have been done, consequently, information is not available yet on the associated risks and
uncertainties.
Potential Applicability in Different Regions
This option can be potentially applied at any nitric acid production facility.
Option
ECN-LTSCR
Lifetime
(years)
10
Reduction Fixed Cost
Recurring
Cost Offset
Efficiency
($2000
Cost ($2000
($2000
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
95
3.64
1.81
0.00
Key References
Jos Kuiper. 2001. “High Temperature Catalytic Reduction of Nitrous Oxide Emission from Nitric Acid
Production Plants.” Continental Engineering, No. 1, Amsterdam, The Netherlands, October 2001.
NOVEM Project No. 375001/0080.
B-41
SECTOR:
Nitric Acid Production
OPTION NAME:
Grand Paroisse - High Temperature Catalytic Reduction Method (Grand Paroisse
– HTCR)
OPTION ID:
NAC3
Brief Description
The abatement method developed by Grande Paroisse uses the high temperature reduction catalyst to
convert N2 O into NO, resulting in higher HNO3 production. This process has only been proven in
laboratory scale tests. The catalyst composition is aluminum oxide and zirconium oxide.
State of Development and Current Level of Usage
This option is in the laboratory test phase.
Associated Risks and Uncertainties
Various laboratory tests have been conducted. Each test lasts 24 hours and the total of 33 tests have been
completed. Since this method is in the test phase its risk and uncertainties are still unknown.
Potential Applicability in Different Regions
The design of the Grand Paroisse catalyst bed can be implemented in any standard HNO3 plant.
Option
Grand Paroisse HTCR
Reduction Fixed Cost
Lifetime
Efficiency
($2000
(years)
(%)
US/tCO2 Eq)
10
77.6
3.09
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
0.16
0.00
Key References
Jos Kuiper. 2001. “High Temperature Catalytic Reduction of Nitrous Oxide Emission from Nitric Acid
Production Plants.” Continental Engineering, No. 1, Amsterdam, The Netherlands, October 2001.
NOVEM Project No. 375001/0080.
B-42
SECTOR:
Nitric Acid Production
OPTION NAME:
HITK – High Temperature Catalytic Reduction Method (HITK – HTCR)
OPTION ID:
NAC4
Brief Description
This is a high temperature catalytic reduction technology by HITK (Hermsdorfer Institut für Technische
Kerami) that decomposes N 2O to nitrogen (N2 ) and oxygen (O2 ) by using a catalyst. The catalyst
composition is metal oxide preferably La, Cr, Mn, Fe, Co, Ni and Cu. The catalyst is used directly behind
the Pt/Rh gauzes in the ammonia burner. The catalyst decomposes the N 2 O gas at high temperatures (800
°C to 900 °C) to nitrogen (N2 ) and oxygen (O2 ).
State of Development and Current Level of Usage
Laboratory tests were used for the patent. As of October 2001, final tests on the pilot plant stage were not
yet available.
Associated Risks and Uncertainties
As of October 2001, final tests on the pilot plant stage were not yet available , so the associated risks and
uncertainties are unknown.
Potential Applicability in Different Regions
The bedheight required for the HITK method is 145 mm and may not fit into the standard HNO3 plant.
Since no research of regional differences in production technologies were available for this study, the TA
was assumed to be equal to 100 percent.
Option
HITK- HTCR
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
10
100
3.18
0.22
0.00
Key References
Jos Kuiper. 2001. “High Temperature Catalytic Reduction of Nitrous Oxide Emission from Nitric Acid
Production Plants.” Continental Engineering, No. 1, Amsterdam, The Netherlands, October 2001.
NOVEM Project No. 375001/0080.
B-43
SECTOR:
Nitric Acid Production
OPTION NAME:
Krupp Uhde - Low Temperature Catalytic Reduction Method (Krupp Uhde –
LTCR)
OPTION ID:
NAC5
Brief Description
The low temperature selective catalytic N2 O-reduction method developed by Krupp Uhde uses a zeolite
type catalyst. The catalyst bed is installed in the tail-gas stream of a commercially operating plant. All
N2 O is reduced to N2 and O2 . There is an extra reactor needed after the ammonia burner. According to
Krupp Uhde, low temperature catalysts have a longer lifetime than the high temperature catalysts.
State of Development and Current Level of Usage
Development stage is at the pilot plant level.
Associated Risks and Uncertainties
The catalyst life test is needed.
Potential Applicability in Different Regions
The method is potentially applicable at all production facilities.
Option
Krupp Uhde LTCR
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
10
95
3.45
0.20
0.00
Key References
Jos Kuiper. 2001. “High Temperature Cata lytic Reduction of Nitrous Oxide Emission from Nitric Acid
Production Plants.” Continental Engineering, No. 1, Amsterdam, The Netherlands, October 2001.
NOVEM Project No. 375001/0080.
B-44
SECTOR:
Nitric Acid Production
OPTION NAME:
Norsk Hydro - High Temperature Catalytic Reduction Method (Norsk Hydro –
HTCR)
OPTION ID:
NAC6
Brief Description
Norsk Hydro has developed a high temperature catalytic reduction method, which decomposes N2O to
nitrogen (N2 ) and oxygen (O2 ) by using a catalyst (NH-1 or NH-2). Laboratory tests show 0.2 to 0.4 %
NO losses but this is below the detection limit. The catalyst is used directly behind the Pt/Rh gauzes in
the ammonia burner. The catalyst decomposes the N2O gas at high temperatures (800 °C to 900 °C) to
nitrogen (N2 ) and oxygen (O2 ).
State of Development and Current Level of Usage
The catalyst is installed inside a commercially operating plant. For the NH-2 catalyst pilot plant tests have
been done, and the commercial plant scale test was planned for early 2001. As of October 2001 the
catalyst had been in operation for 18 months.
Associated Risks and Uncertainties
This method has no known uncertainties.
Potential Applicability in Different Regions
The design of the Norsk Hydro catalyst bed can be implemented in any standard HNO3 plant.
Option
Norsk HydroHTCR
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
10
90
2.32
0.15
0.00
Key References
Jos Kuiper. 2001. “High Temperature Catalytic Reduction of Nitrous Oxide Emission from Nitric Acid
Production Plants.” Continental Engineering, No. 1, Amsterdam, The Netherlands, October 2001.
NOVEM Project No. 375001/0080.
B-45
SECTOR:
Nitric Acid Production
OPTION NAME:
Non-Selective Catalytic Reduction (NSCR)
OPTION ID:
NAC7
Brief Description
NSCR uses a fuel and a catalyst to consume free oxygen in the tail gas and to convert NO x to elemental
nitrogen. The gas from the NOx abatement is passed through a gas expander for energy recovery. NSCR
units produce stack gases in the 1000 to 1100o F range that requires more exotic materials of construction
for the expander and higher maintenance costs. Since all oxygen must be consumed before the nitrogen
oxides are reduced, excess fuel must be used resulting in methane emissions. NSCR can reduce N2O
emissions by 80-90 percent. However, this process requires additional fuel (natural gas) and, as a result of
combustion not only CO2 but also carbon monoxide, ammonia, uncombusted hydrocarbons 3 and even
small amounts of hydrocyanic acid are emitted. NSCR units are generally not preferred in modern plants
because of high operational temperatures.
State of Development and Current Leve l of Usage
NSCRs were widely installed in nitric plants built between 1971 and 1977. NSCR is a typical tail gas
treatment in the U.S. and Canada with less application in other parts of the world. It is estimated that
approximately 20 percent of nitric acid plants in the U.S. use NSCR.
Associated Risks and Uncertainties
Process requires additional fuel (natural gas) and, as a result of combustion, CO2 as well as other harmful
emissions are produced.
Potential Applicability in Different Regions
NSCR is potentially applicable in all regions.
Option
NSCR
Reduction Fixed Cost
Lifetime
Efficiency
($2000
(years)
(%)
US/tCO2 Eq)
20
85
6.29
Recurring
Cost ($2000
US/tCO2 Eq)
0.16
Cost Offset
($2000
US/tCO2 Eq)
0.00
Key References
IEA Greenhouse Gas R&D Programme. 2000a. Abatement of Emissions of Other Greenhouse Gases –
Nitrous Oxide. International Energy Agency, Cheltenham, UK.
3
Release of additional methane might reduce the GHG abatement effect of this option.
B-46
SECTOR:
Adipic Acid Production
OPTION NAME:
Valorisation of Nitrous Oxide Emitted by Adipic Acid Unit
OPTION ID:
AA1
Brief Description
Valorization is the thermal conversion of N2 O into nitrogen and oxygen. During this process NO x is also
produced. The aim of this technology is to encourage the production of NOx and minimize the conversion
of N2 O into nitrogen and oxygen. The NOx formed can be then recycled in the form of nitric acid, which
is a raw material in the upstream adipic acid manufacturing process.
State of Development and Current Level of Usage
A pilot aimed at endorsing the process on an industrial scale was designed and built in Chalampé, France
at the beginning of 1996. The first results of this pilot test on site were obtained during the summer of
1996. The design studies of the industrial facility were launched at the end of 1996 and the construction
of the plant started very quickly with a very tight schedule. The construction of the plant was finished at
the end of 1997 and the start-up of the plant followed in December 1997.
Associated Risks and Uncertainties
During the first year of operation, this prototype plant operated under harsh temperature conditions and
consequently has encountered a certain number of problems of material resistance. These problems
required serious maintenance operations to improve the thermal protection of certain sensitive points or
certain sensors - mainly the temperature probes. These modifications sometimes led to long downtimes
resulting in the plant shutting down for 3 months in the summer of 1998. Another difficulty comes from
the fact that this unit treats the process gases from several adipic acid production shops. Therefore,
occasionally, it must adapt to the rapid variations in flow or composition of the gases to be treated;
otherwise the unit would automatically trigger off a security shut down. Nevertheless, with the
advancement of automation, the operation of the plant can adapt to these variations, but the adjustment of
the automation system requires a great deal of experience and the operations need monitoring in various
conditions.
Potential Applicability in Different Regions
The valorisation of nitric acid is applicable for an adipic acid facility, which is lacking in nitric acid,
because it leads to a reduction in the overall consumption of the nitric acid in the facility.
Option
Valorisation
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
10
99
N/A
N/A
N/A
Key References
Klinger, Francois. “Valorisation of nitrous oxide emitted by adipic acid unit.” Control of N2 O emissions
from various sources. Session 7. Rodhia Alsachime. Chalempe France.
B-47
SECTOR:
Adipic Acid Production
OPTION NAME:
Thermal Reduction
OPTION ID:
AA2
Brief Description
Thermal N2 O reduction is the destruction of off-gases in boilers using flame burners with premixed
methane (or natural gas). The system eliminates 98 to over 99 percent of N2O and operates from 95 to
over 99 percent of the time. This option is currently available and in use. For example in the U.S., 34
percent of production uses thermal destruction.
State of Development and Current Level of Usage
Four adipic acid plants have thermal reduction technology installed in their facilities.
Associated Risks and Uncertainties
Cost effectiveness depends on individual plant’s ability to use recovered steam.
Potential Applicability in Different Regions
This option is potentially applicable in all regions.
Option
Thermal Reduction
Reduction
Lifetime
Efficiency
(years)
(%)
20
96
Fixed Cost
($2000
US/tCO2 Eq)
0.38
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
0.16
0.00
Key References
IEA Greenhouse Gas R&D Programme. 2000a. Abatement of Emissions of Other Greenhouse Gases –
Nitrous Oxide. International Energy Agency, Cheltenham, UK.
B-48
SECTOR:
Refrigeration and Air-Conditioning
OPTION NAME:
Refrigerant Recovery
OPTION ID:
R14, R16 and R18
Brief Description
The practice of recovering refrigerant at service or disposal for reuse or destruction can significantly
reduce emissions of HFCs. Recovery involves the use of a refrigerant recovery device that transfers
refrigerant into a storage container prior to servicing or dispos ing equipment. Once the recovery process
is complete, the refrigerant contained in the storage container may be recharged back into the source
equipment (for servicing jobs), cleaned through the use of recycling devices, purified for resale at a
reclamation facility, or disposed safely through the use environmentally-safe technologies (e.g.,
incineration) (U.S. EPA, 2001).
Because refrigerant recovery from equipment with large charge sizes is cost effective—given that the
refrigerant can be re-used or re-sold—this analysis assumes that such recovery jobs are already practiced
in the baseline. As such, this analysis considers only the recovery of refrigerant from small equipment
types (i.e., refrigerated transport, domestic refrigerators, and motor vehicle air-conditioning systems
[MVACs]), which is less cost-effective due to the smaller recoverable charges. Although the costs of
recovery vary by equipment type and recovery scenario (i.e., service and disposal), this analysis looks at
the costs of MVAC recovery at service, as this is believed to be the most commonly practiced recovery
scenario of those considered.
State of Development and Current Level of Usage
Refrigerant recovery equipment is widely available and used extensively in developed countries. Indeed,
in many developed countries, refrigerant recovery is required by law (e.g., European Union, Canada,
United States). In developing countries, however, refrigerant recovery is not widely practiced because of
a lack of available capital and infrastructure (e.g., access to recovery/recycling devices reclamation
facilities), as well as a lack of national legislation requiring such practice.
Associated Risks and Uncertainties
Risks and uncertainties associated with recovery are minimal. Proper equipment instructions must be
followed so that a minimal amount of refrigerant will escape to the atmosphere during the recovery
operation, and to ensure technician safety. There is uncertainty associated with the reduction efficiency of
this option, as the amount of refrigerant emissions will depend on technician technique and equipment
type. Additionally, there is uncertainty associated with the total percent of emissions from equipment that
can be avoided by recovering at service and disposal. This analysis assumes that 50 percent of emissions
from small equipment types can be avoided by practicing this option (the remaining 50 percent of
emissions from these equipment types is assumed to occur from leakage during operation).
Potential Applicability in Different Regions
Refrigerant recovery is widely practiced in developed countries in the baseline. It is not, however,
assumed to have penetrated a significant portion of the refrigeration and air-conditioning markets in
developing countries. Thus, the greatest growth opportunity for this option is in developing countries.
4
“Small appliances” include domestic refrigerators, icemakers, vending machines, dehumidifiers, and water coolers.
These scenarios include recovery/recycling of (1) MVACs at service, (2) MVACs at disposal, (3) small appliances
at service, and (4) small appliances at disposal.
5
B-49
Option
Recovery—
Domestic
Refrigeration
(R14)
Recovery—
Refrigerated
MVACs (R16)
Recovery—
Refrigerated
Transport (R18)
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
a
b
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)c
10
95
26.19
3.40
3.05
10
95
26.19
3.40
3.05
10
95
26.19
3.40
3.05
a
Based on R-134a MVAC recovery/recycling unit manufactured by Robinair (model #347002K)
(Robinair SPX Corporation, 2003).
b
Annual cost is based on assumption of 150 recovery jobs/year, each requiring 10 minutes of technician’s
time, valued at $14/hr (Jiffy Lube, 2003).
c
This analysis assumes that 0.55 kg can be recovered per job and that value of refrigerant is $4/kg (Baker
2002; Campbell 2003).
Key References
Baker, James. 2002. Mobile Air Conditioning Sector Update. Presentation at the 19th Meeting of the
Ozone Operations Resource Group (OORG), The World Bank, Washington, DC, March 28, 2002.
Campbell, Nick. 2003. Production Sector Update. Presentation at the 20th Meeting of the Ozone
Operations Resource Group (OORG), The World Bank, Washington, DC, April 25, 2003.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
Jiffy Lube. 2003. Personal communication with service technician, Jiffy Lube Service Center #273, MD,
USA, July 25, 2003.
Robinair SPX Corporation. 2003. Personal communication with sales representative, July 24, 2003.
U.S. EPA (Environmental Protection Agency). 2001. U.S. High GWP Gas Emissions 1990-2010:
Inventories, Projections, and Opportunities for Reductions. U.S.EPA #000-F-97-000. Office of Air and
Radiation, U.S. Environmental Protection Agency. Washington, DC, June 2001.
B-50
SECTOR:
Refrigeration and Air-Conditioning
OPTION NAME:
Replacing Direct Expansion Systems with Distributed Systems
OPTION ID:
R1 and R6
Brief Description
Distributed refrigeration systems are gaining in popularity because they offer the ability to reduce
refrigerant charge and eliminate the need for a dedicated mechanical room containing multiple
compressor racks. Distributed systems feature multiple smaller units located closer to the refrigerated
display cases.
Replacing HFC direct expansion systems with HFC distributed systems in retail food and cold storage
applications can reduce HFC emissions. Unlike direct expansion systems with central refrigeration rooms
containing multiple compressor racks, distributed systems feature multiple smaller units located closer to
the refrigerated display cases, connected by a water loop to a single cooling unit that is located on the roof
or outside of the store (U.S. EPA 2001, Copeland 2003). Distributed systems significantly reduce the
refrigerant inventory and minimize the length of refrigerant tubing and the number of fittings that are
installed in direct expansion systems, thereby reducing leaks of HFCs (Alliance, 1999). In addition, these
systems are more energy efficient than direct expansion systems, leading to further reductions in global
warming impacts and long-term cost-savings (ORNL BTC, Sand et al., 1997).
State of Development and Current Level of Usage
Distributed systems are most commonly used in retail food refrigeration and are widely available (U.S.
EPA, 2001).
Associated Risks and Uncertainties
Risks and uncertainties associated with this option are minimal. One risk associated with this option is
that, because refrigerant charge is placed throughout the building, the amount of refrigerant charge that
could potentially be released into the building is large. Thus, the use of flammable or highly toxic
refrigerants is not feasible. In the case of retail food applications, store operators in the U.S. and some
other countries will not accept the safety and legal risks, and safety codes prohibit such large quantities of
flammable refrigerant to be used in a publicly occupied space (Alliance, 1999).
Potential Applicability in Different Regions
Distributed systems may be used to replace HFC systems equally across all regions.
Option
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
Replacing DX with
Distributed Systems —
20
100
Retail Food (R1)
Replacing DX with
Distributed Systems —
20
100
Cold Storage (R6)
Note: All cost information is from U.S. EPA (2001).
82.15
-6.84
1.58
82.15
-6.84
1.58
B-51
Key References
Alliance. 1999. Global Comparative Analysis of HFC and Alternative Technologies for Refrigeration,
Air Conditioning, Foam, Solvent, Aerosol Propellant, and Fire Protection Applications. Final Report to
the Alliance for Responsible Atmospheric Policy. Arthur D. Little, Inc., Cambridge, MA; Reference
Number 49648.
Copeland Corporation. 2003. “Emerson Climate Technologies.” Available at http://www.copelandcorp.com/press/2003/2003_26.htm
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
ORNL BTC (Oak Ridge National Laboratory, Building Technology Center). "Improvements in
Commercial Refrigeration," Available online at http://www.ornl.gov/ORNL/BTC/imp-comref.html
Sand, J.R., S.K. Fischer, and V.D. Baxter. 1997. Energy and Global Warming Impacts of HFC
Refrigerants and Emerging Technologies. Prepared by Oak Ridge National Laboratory for Alternative
Fluorocarbons Environmental Acceptability Study and U.S. Department of Energy. Oak Ridge, TN, pp. 4,
5, 7, 26, 40-42, 58-61, 73-77, 83-85, 122.
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S. EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
B-52
SECTOR:
Refrigeration and Air-Conditioning
OPTION NAME:
Ammonia Secondary Loops
OPTION ID:
R2, R7 and R11
Brief Description
Secondary loop systems circulate a secondary coolant or brine from the central refrigeration system to the
display cases, thereby operating at reduced charges and achieving isolating lower leak rates (U.S. EPA,
2001). Because these systems isolate customers from the refrigerant, they can use a variety of refrigerants,
including ammonia. By using ammonia as the primary refrigerant in secondary loop system in place of
HFCs, HFC emissions can be reduced. This technology option is assumed to be appropriate for retail
food, cold storage, and industrial process end use sectors (U.S. EPA, 2001).
State of Development and Current Level of Usage
The use of ammonia is very common in certain countries and strongly restric ted in others (ECOFYS,
2000). For example, for many decades ammonia has been used in almost all dairies, breweries,
slaughterhouses, and large freezing plants nearly all over Europe, while its use is heavily regulated in
North America (ACHR News, 2000). The use of ammonia systems in supermarkets is growing in many
European countries (e.g., Italy, Luxembourg, Switzerland, Germany) (Lohbeck, 1999).
Associated Risks and Uncertainties
Ammonia is toxic and an explosion hazard at 16 to 25 percent in air, which creates a problem in confined
spaces. However, because ammonia has a strong odor, refrigerant leaks are easily detectable.
Additionally, because ammonia is lighter than air, dispersion is facilitated in the event of a release
(UNEP, 1999). To ensure safety, modern ammonia systems are fully contained hermetic systems with
fully integrated controls that regulate pressure throughout the system. Modern systems are also equipped
with emergency diffusion systems and a series of safety relief valves to protect the equipment and its
pressure vessels from over-pressurization and possible failure (ASHRAE, 1993). These safety features
have been considered in developing cost estimates for this option.
Potential Applicability in Different Regions
Because different countries have different sets of building codes, fire codes, and other safety standards
relating to the use of ammonia in building equipment, some countries (e.g., the United States) would need
to revise codes to allow for the expanded use of ammonia in new equipment types. Additionally, actual
market penetration for this option will vary by region based on acceptance of ammonia by manufacturers,
end users, regulators, and insurance companies, which will in turn depend on risk—be they real or
perceived.
Option
Ammonia
Secondary LoopsRetail Food (R2)
Ammonia
Secondary Loops-
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
20
100
115.98
12.89
1.58
20
100
115.98
12.89
1.58
B-53
Cold Storage (R7)
Ammonia
Secondary LoopsIndustrial Process
Refrigeration (R11)
20
100
115.98
12.89
1.58
Note: All cost information is from U.S. EPA (2001).
Key References
ACHR News (Air Conditioning Heating Refrigeration News). 2000. An Argument for NH3 ’s Superiority
over Other Refrigerants. Business News Publishing Company, July 27, 2000.
ASHRAE (American Society of Heating, Refrigerating and Air-Conditioning Engineers, Inc.). 1993.
Ammonia as a Refrigerant: Position Paper. Approved by ASHRAE Board of Directors January 28, 1993.
(Available at: http://www.ashrae.org/about/amm%5Fpapr.htm).
ECOFYS. 2000. Economic Evaluation of Emission Reductions of HFCs, PFCs and SF6 in Europe.
Special report contributing to the study, “Economic Evaluation of Sectoral Emission Reduction
Objectives for Climate Change,” on behalf of the Commission of the European Union Directorate General
Environment. April 25, 2000.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
Lohbeck, Wolfgang. 1999. “The Greenfreeze Wave Keeps on Rolling,” GTZ PROKLIMA Yearbook
1997-1999. GTZ Project PROKLIMA, Division Environmental Management, Water, Energy, Transport.
Eschborn, 1999.
UNEP (United Nations Environment Programme). 1999. Report of the TEAP HFC and PFC Task Force.
October 1999.
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S. EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
B-54
SECTOR:
Refrigeration and Air-Conditioning
OPTION NAME:
Leak Repair for Large Equipment
OPTION ID:
R3, R8, R12, R19, and R20
Brief Description
Many types of repairs can be performed to reduce leaks in refrigeration and air-conditioning equipment,
ranging from simple, inexpensive repairs to more expensive, major system repairs (Calm, 1999; U.S. EPA
1995; U.S. EPA 1998). This analysis focuses only on the major repairs, including installing new purge
systems, replacing or removing the motor, installing new refrigerant metering, and replacing flare joints,
gaskets, or seals (U.S. EPA, 2001). Because this option is so costly, it is assumed to only be used on
equipment with large charge sizes (e.g., chillers, retail food, cold storage, industrial process refrigeration,
commercial air-conditioning, and residential air-conditioning).
State of Development and Current Level of Usage
Major modifications to large refrigeration and air-conditioning systems are well developed
technologically and are widely used, particularly in developed countries. With technological
improvement, new leak reduction technologies are emerging, which may effectively lower the cost of this
option over time.
Associated Risks and Uncertainties
There is uncertainty associated with the reduction efficiency of this option, as the age of equipment and
quality of repair will cause the lowest achievable leak rate to vary on a case-by-case basis. In addition,
there is uncertainty associated with the total percent of emissions from equipment that can be avoided by
this option. This analysis assumes that 50 percent of emissions from large equipment types can be
avoided through this option (the remaining 50 percent of emissions from these equipment types is
assumed to occur at service and disposal—if recovery is not practiced).
Potential Applicability in Different Regions
This option can be applied widely throughout all regions, though it is assumed to have already penetrated
a significant share of the markets in developed countries, where maximum allowable leak rates are often
regulated by law.
Option
Leak Repair—
Chillers/Commercial
AC (R19)
Leak Repair—Retail
Food (R3)
Leak Repair—Cold
Storage (R8)
Leak Repair—
Industrial Process
Refrigeration (R12)
Leak Repair—
Reduction
Lifetime
Efficiency
(years)
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)a
5
90
27.55
0.00
$3.05
5
90
27.55
0.00
$3.05
5
90
27.55
0.00
$3.05
5
90
27.55
0.00
$3.05
5
90
27.55
0.00
$3.05
B-55
Residential A/C
(R20)
a
Assumes value of $4.00/kg for R-134a (Campbell, 2003).
Note: All cost information is from U.S. EPA (2001), unless otherwise specified.
Key References
Calm, J. 1999. “Emissions and Environmental Impacts from Air-Conditioning and Refrigeration
Systems.” Joint IPCC/TEAP Expert Meeting on Options for the Limitation of Emissions of HFCs and
PFCs, the Netherlands, May 1999.
Campbell, Nick. 2003. Production Sector Update. Presentation at the 20th Meeting of the Ozone
Operations Resource Group (OORG), The World Bank, Washington, DC, April 25, 2003.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
U.S. EPA (Environmental Protection Agency). 1995. Options for Reducing Refrigerant Emissions from
Supermarket Systems. Prepared by ICF Incorporated. Washington, DC, June 1995.
U.S. EPA (Environmental Protection Agency). 1998. Regulatory Impact Analysis: The Substitutes
Recycling Rule. Prepared by ICF Incorporated. Washington, DC, May 1998.
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S. EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
B-56
SECTOR:
Refrigeration and Air-Conditioning
OPTION NAME:
Alternative Systems
OPTION ID:
R4, R9 and R13
Brief Description
Alternative systems, such as those that use carbon dioxide (CO2 ), ammonia, hydrocarbons, or a
combination of these as refrigerants, can be used in place of HFC refrigerants in cold storage, industrial
process refrigeration, and retail food applications (IEA GHG, 2000; Lohbeck, 1999). Because of the
technical features of these systems, and because most of these systems are new to the market, the
associated capital costs remain higher than conventional HFC systems. However, many of these systems
may be associated with long-term cost savings resulting from increased energy efficiency. For example,
research conducted on low temperature commercial refrigeration systems have found carbon dioxide
systems to have a higher efficiency than state-of-the-art R-404A systems (Girotto and Neska, 2002).
Moreover, by adapting system design it is believed that system efficiency can be further improved (for
both low and medium temperature refrigeration) (Girotto and Neska, 2002).
State of Development and Current Level of Usage
While a growing number of applications are adopting alternative systems—such as supermarkets in
Scandinavian countries, Italy, Luxembourg, Switzerland, and Germany—many new technologies
designed to use these natural refrigerants are still undergoing field tests and design improvements
(Lohbeck, 1999; Girotto and Neksa, 2002).
Associated Risks and Uncertainties
Carbon dioxide has disadvantages as well, and certain issues would be of concern, such as safety
(OSHA’s recommended 8-hour time-weighted average is 5,000 parts per million [ppm]), cost of
designing and purchasing equipment, potential loss of operational efficiency and the associated increase
in indirect emissions, refrigerant containment, long-term reliability, and compressor performance
(Environment Canada, 1998; ACGIH, 1999). To ensure safety, commercialized CO2 systems currently in
use in retail food applications in Denmark are equipped with built-in alarms that sound when CO2
concentrations exceed 4,000 parts per million (ppm). However, a great deal of uncertainty still exists
concerning the performance, efficiency, safety, and cost of such alternative systems.
Potential Applicability in Different Regions
While these systems are still in their early stages of development, potential exists for these options to be
adopted throughout all regions. However, due to the safety risks associated with this option, adoption may
be smaller in some countries than in others (e.g., stakeholders and end users in the U.S. may be less
willing to accept such risks, be they real or perceived).
Option
Alternative
Systems—Retail
Food (R4)
Alternative
Systems—Cold
Reduction Fixed Cost
Lifetime
Efficiency
($2000
(years)
(%)
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
15
100
188.10
(1.41)
2.76
15
100
188.10
(1.41)
2.76
B-57
Storage (R9)
Alternative
Systems—
Industrial Process
Refrigeration
(R13)
15
100
188.10
(1.41)
2.76
Source: IEA GHG (2001).
Key References
ACGIH (American Conference of Governmental Industrial Hygienists, Inc.). 1999. Guide to
Occupational Exposure Values.
Environment Canada. 1998. Powering GHG Reductions Through Technology Advancement. Clean
Technology Advancement Division, Environment Canada, pp.185-188.
Girotto, S. and P. Neksa, 2002. “Commercial Refrigeration Systems with Refrigerant CO2 Theoretical
Considerations and Experimental Results.” Proceedings from the Conference on New Technologies in
Commercial Refrigeration, International Institute of Refrigeration, Urbana Champaign, Illinois, USA,
July 22-23, 2002.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
Lohbeck, Wolfgang. 1999. “The Greenfreeze Wave Keeps on Rolling,” GTZ PROKLIMA Yearbook
1997-1999. GTZ Project PROKLIMA, Division Environmental Management, Water, Energy, Transport.
Eschborn, 1999.
B-58
SECTOR:
Refrigeration and Air-Conditioning
OPTION NAME:
Carbon Dioxide in MVACs
OPTION ID:
R17
Brief Description
A transcritical vapor cycle using carbon dioxide as the refrigerant in motor vehicle air-conditioners
(MVACs) represents a potentially significant emission reduction opportunity. Transcritical carbon
dioxide systems are under study and development by many vehicle manufacturers in cooperation with
global component and system suppliers. Transcritical carbon dioxide systems have potential energy
efficiency that is comparable to HFC-134a systems vehicles and the lowest GWP of any candidate
refrigerant (Andersen et al., 2000). The arrangement of components of such a system would need to
accommodate the extremely high pressure levels of supercritical carbon dioxide (about 2,000 psig).
Research and development is also underway to develop “low-pressure” carbon dioxide, a
compression/sorption hybrid system (Alliance, 1999).
State of Development and Current Level of Usage
Carbon dioxide systems require additional development in performance and safety before they can be
commercialized and replace HFC-134a. The first systems could be available within 4 to 7 years
(Andersen et al., 2000; U.S. EPA, 2001).
Associated Risks and Uncertainties
Several risks and uncertainties are associated with this option. The major concerns include safety, cost of
designing and purchasing equipment, compressor performance, refrigerant containment, long-term
reliability, and the potential loss of operational efficiency and associated increases in indirect emissions ,
(U.S. EPA, 2001; Environment Canada, 1998; ACGIH, 1999). Substantial new engineering and testing
efforts are still required prior to the commercialization of this option. Safety systems to detect and vent
carbon dioxide that is accidentally released into the passenger compartment may be necessary. New
equipment and technician training would also be required to safely repair systems (Andersen et al., 2000).
As a positive feature, carbon dioxide MVACs are expected to be more efficient than conventional HFC134a systems, reducing indirect emissions by approximately 1 percent (Baker, 2003).
Potential Applicability in Different Regions
If and when carbon dioxide systems in MVACs are commercialized, this option could technically be
adopted equally throughout all regions. However, actual market penetration of this option will vary by
region based on user acceptance of carbon dioxide, which will in turn depend on perceived risk. Thus, it
is likely that some regions (e.g., the United States) may resist readily adopting this technology.
Option
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq)a US/tCO2 Eq)b US/tCO2 Eq)c
Carbon dioxide
12
100
1,066.34
0.00
3.05
in MVACs
a
Based on average added cost of US$112 (approximately EUR 110) (Baker 2003).
b
Although efficiency gains are expected, no annual cost savings were assumed in this analysis, due to a
lack of available cost data (Baker, 2003).
c
Based on R-134a value of $4.00/kg (Campbell, 2003).
B-59
Key References
ACGIH. (American Conference of Governmental Industrial Hygienists, Inc.). 1999. Guide to
Occupational Exposure Va lues.
Alliance. 1999. Global Comparative Analysis of HFC and Alternative Technologies for Refrigeration,
Air Conditioning, Foam, Solvent, Aerosol Propellant, and Fire Protection Applications. Final Report to
the Alliance for Responsible Atmospheric Polic y. Arthur D. Little, Inc., Cambridge, MA; Reference
Number 49648.
Andersen, S., W. Atkinson, J. Baker, S. Oulouhojian, and J.E. Phillips. 2000. Technical Options For
Motor Vehicle Air Conditioning Systems. Prepared for the Society of Automotive Engineers (SAE), U.S.
Environmental Protection Agency (EPA), and the Mobile Air Conditioning Society Worldwide (MACS).
Baker, James. 2003. Mobile Air Conditioning Sector Update. Presentation at the 20th Meeting of the
Ozone Operations Resource Group (OORG), The World Bank, Washington, DC, April 25, 2003.
Campbell, Nick. 2003. Production Sector Update. Presentation at the 20th Meeting of the Ozone
Operations Resource Group (OORG), The World Bank, Washington, DC, April 25, 2003.
Environment Canada. 1998. Powering GHG Reductions Through Technology Advancement. Clean
Technology Advancement Division, Environment Canada, pp.185-188.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases –
Engineered Chemicals. International Energy Agenc y, Cheltenham, United Kingdom, February
2001. Report Number PH3/35.
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
B-60
SECTOR:
Refrigeration and Air-Conditioning
OPTION NAME:
HFC Secondary Loops
OPTION ID:
R5 and R10
Brief Description
Secondary loop systems, which operate at reduced charge sizes and have lower leak rates, can be used in
retail food and cold storage applications to reduce emissions of HFCs (U.S. EPA, 2001). These systems
circulate a secondary coolant or brine (e.g., ice slurry) from the central refrigeration system to the display
cases, isolating customers from the refrigerant (Alliance, 1999; U.S. EPA, 2001; UNEP, 1999). Other
positive features of this technology include enhanced reliability, more efficient defrost, lower
maintenance requirements, and longer shelf life than conventional (direct expansion) systems (U.S. EPA,
2001).
State of Development and Current Level of Usage
HFC secondary loop systems are well developed technologically.
Associated Risks and Uncertainties
Energy penalties are associated with this option. However, technological improvements such as highefficiency evaporative condensers and display cases with high temperature brines are expected to increase
system efficiency in future (EPA, 2001).
Potential Applicability in Different Regions
HFC systems can be applied equally throughout all regions.
Option
HFC Secondary
Loop Systems—
Retail Food (R5)
HFC Secondary
Loop Systems—
Cold Storage (R10)
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
20
100
30.93
12.89
1.58
20
100
30.93
12.89
1.58
Note: All cost information is from U.S. EPA (2001).
Key References
Alliance. 1999. Global Co mparative Analysis of HFC and Alternative Technologies for Refrigeration,
Air Conditioning, Foam, Solvent, Aerosol Propellant, and Fire Protection Applications. Final Report to
the Alliance for Responsible Atmospheric Policy. Arthur D. Little, Inc., Cambridge, MA; Reference
Number 49648.
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
B-61
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
UNEP (United Nations Environment Programme). 1999. Report of the TEAP HFC and PFC Task Force.
October 1999.
B-62
SECTOR:
Refrigeration and Air-Conditioning
OPTION NAME:
Hydrocarbons in Domestic Refrigerators
OPTION ID:
R15
Brief Description
Different blends of hydrocarbon (HC) refrigerants can replace HFC refrigerant in new manufactured
household refrigerators and freezers.
State of Development and Current Level of Usage
Since 1992, hydrocarbon refrigeration has increasingly penetrated the domestic markets in Western
Europe. Today, domestic refrigerators using HC refrigerant are manufactured and/or sold in Germany,
Spain, Sweden, England, France, Turkey, Argentina, Australia, Brazil, China, Cuba, India, Indonesia , and
Japan (Lohbeck, 1999). It is estimated that 120 million HC refrigerators have been manufactured
worldwide (Lindborg, 2003).
Associated Risks and Uncertainties
While the use of hydrocarbon refrigerant is typically associated with safety hazards, the small charge
sizes of HC domestic refrigeration systems (on the order of 0.02 kilograms) does not pose health risks
(Brownstein, 2000). However, several cases of fire have been reported in Australia, Italy, and China, half
of which occurred during production (Lindborg, 2003). Based on expert opinion, the manufacturing cost
of these systems is comparable to those of HFC systems and is associated with energy savings (Lohbeck,
2003; Maclaine-Cross and Leonardi, 1997).
Potential Applicability in Different Regions
Hydrocarbon systems in domestic refrigeration can technically be adopted equally throughout all regions.
However, to date, actual market penetration of this option has not occurred in North America, as a result
of the perceived risk and lack of acceptance of HC as a refrigerant.
Option
HCs in domestic
refrigeration
Reduction Fixed Cost
Lifetime
Efficiency
($2000
(years)
(%)
US/tCO2 Eq)
15
100
38.49
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
0.00
0.00
Source: IEA GHG (2001).
Key References
Brownstein, I. 2000. “Eliminating CFCs: It’s Up to Us,” Peace and Environmental News.
Hydro Cool Online. 2002. “Cool Technologies: Working Without HFC’s,” Updated June 2002.
Available at http://www.hydrocoolonline.com/news.asp?n=LN009
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
B-63
Lindborg, Anders. 2003. Personal communication with Anders Lindborg, Ammonia Partnership AB,
Nyponv, Sweden, July 30, 2003.
Lohbeck, Wolfgang. 1999. “The Greenfreeze Wave Keeps on Rolling,” GTZ PROKLIMA Yearbook
1997-1999. GTZ Project PROKLIMA, Division Environmental Management, Water, Energy, Transport.
Eschborn, 1999.
Maclaine-Cross, I.L. and E. Leonardi. 1999. “Why Hydrocarbons Save Energy.” AIRAH Journal, June
1997, Volume 51, No. 6; pp 33-37.
B-64
SECTOR:
MDI Aerosols
OPTION NAME:
Dry Powder Inhalers (DPIs)
OPTION ID:
AMD1
Brief Description
Dry Powder Inhalers (DPIs) can replace metered dose inhalers (MDIs) for use in treating asthma and
chronic obstructive pulmonary disease. This alternative consists of a micronised dry powder that is
inhaled and deposited in the lungs from DPIs. “However, due to stringent performance and toxicology
specifications, the success of this alternative is limited to patients who are able to inhale robustly enough
to transport the powder to the lungs” (U.S. EPA, 2001).
State of Development and Current Level of Usage
DPIs have been successfully used with most anti-asthma drugs but their usage is minimal, especially in
the United States, where usage is estimated to represent less than two percent of all inhaled medication in
1999 (U.S. EPA, 2001). However, DPIs usage is higher in Europe, for example in Sweden, where they
account for 85 percent of inhaled medication. The use of DPIs is estimated to be growing at a rate of 15
percent annually (U.S. EPA, 2001).
Associated Risks and Uncertainties
DPIs are not suitable for young children, the elderly , and persons with severe asthma (U.S. EPA, 2001).
Potential Applicability in Different Regions
Unlike MDIs, powdered drug particles contained in DPIs tend to aggregate and may cause problems in
areas with hot and humid climates (U.S. EPA, 2001). This option is assumed to be only technically able
to abate half of MDI aerosol emissions due to limitations in breathing ability of patients’ (IEA GHG,
2001).
Option
Dry Powder
Inhalers
Lifetime
(years)
Reduction
Efficiency
(%)
Fixed Cost
($2000
US/tCO2 Eq)
15
100
0.00
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
294.21
0.00
Key References
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
B-65
SECTOR:
Non-MDI Aerosols
OPTION NAME:
Hydrocarbon Aerosol Propellants (Replacing HFC-134a used by Non-MDI
aerosols with Hydrocarbons)
OPTION ID:
ANM1
Brief Description
Mixtures of propane, butane, and isobutene can be used as propellants in consumer products.
State of Development and Current Level of Usage
After the U.S. ban on CFCs in aerosols in 1977, many consumer products, such as spray deodorants and
hair sprays, were either reformulated with hydrocarbon propellants or replaced with not-in-kind (NIK)
substitutes such as pump sprays or solid and roll-on deodorants. Hydrocarbons are much more affordable
than HFC-134a and HFC-152a and are currently the primary propellant in the Non-MDI aerosol market
(U.S. EPA Report, 2001).
Associated Risks and Uncertainties
Flammability and VOC emissions are associated risks with the use of hydrocarbon aerosol propellants.
Potential Applicability in Different Regions
This option is feasible in all regions; however, the option may not be technically feasible for all HFC134a propellants due to the flammability risks associated with hydrocarbons. Since HFC-134a is the
propellant of choice for non-flammable technical aerosol applications, it is assumed that HFC-134a
comprises 80 percent of total non-MDI aerosol emissions (IEA GHG, 2001). This option is assumed to
abate only 50 percent of HFC-134a emissions to account for flammability constraints.
Option
Hydrocarbons
(Non-MDI)
Lifetime
(years)
Reduction
Efficiency
(%)
10
100
Fixed Cost
Recurring
Cost Offset
($2000
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
0.44
-5.60
0.00
Key References
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
B-66
SECTOR:
Non-MDI Aerosols
OPTION NAME:
HFC-152a (Replacing HFC-134a used by Non-MDI aerosols with HFC-152a)
OPTION ID:
ANM2
Brief Description
HFC-152a is an HFC with a GWP of 120. This propellant is a good choice for applications where
hydrocarbons and dimethyl ether are too flammable (IEA GHG, 2001).
State of Development and Current Level of Usage
The aerosol market already includes the use of HFC-152a as an aerosol propellant. Chemical
manufacturers are marketing HFC-152a for products such as electronic equipment dusters, boat and safety
“air” horns, and tire inflators (U.S. EPA, 2001). HFC-152a is also used as a propellant for laboratory and
experimental uses (IEA GHG, 2001).
Associated Risks and Uncertainties
Since HFC-152a carries moderate flammability risks, its use might be unacceptable for some applications
(U.S. EPA, 2001; IEA GHG, 2001).
Potential Applicability in Different Regions
This option is applicable in all regions and it is assumed to be technically able to abate the 60 percent of
HFC-134a emissions due to the moderate flammability risks. HFC-134a emissions are assumed to
account for 80 percent of total non-MDI aerosol emissions (IEA GHG, 2001).
Option
HFC-152a
(Non-MDI)
Lifetime
(years)
Reduction
Efficiency
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
10
91
0.75
-2.52
0.00
Key References
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
B-67
SECTOR:
Non-MDI Aerosols
OPTION NAME:
Not In Kind (NIK) Products (Replacing HFCs used by Non-MDI aerosols with
NIK products)
OPTION ID:
ANM3
Brief Description
NIK replacements, such as liquid pumps and solid applicators, sticks, roll-on systems, brushes,
nebulizers, and bag-in-can/piston-can systems, are successful HFC replacements (U.S. EPA, 2001).
State of Development and Current Level of Usage
Not-in-Kind (NIK) substitutes already exist in the the aerosols market world-wide; their most significant
penetration of the market initially occurred after the CFCs in aerosols were banned (U.S. EPA, 2001).
Associated Risks and Uncertainties
Consumer acceptance of NIK technology is sometimes uncertain (IEA GHG, 2001). However, there are
no safety/health risks associated with this abatement option.
Potential Applicability in Different Regions
Technologically, this option is feasible in all regions. Future market penetrations of NIK technology may
be limited since most products that could switch to NIK technology already have made the transition.
Option
Lifetime
(years)
NIK (Non-MDI)
10
Reduction
Efficiency
(%)
100
Fixed Cost
Recurring
Cost Offset
($2000
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
0.34
-5.26
0.00
Key References
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
B-68
SECTOR:
Solvents
OPTION NAME:
Retrofit (Improved Equipment and Cleaning Processes with the use of existing
solvents)
OPTION ID:
S1
Brief Description
Retrofitting solvent equipment helps manage and restrict emissions through various engineering controls
and techniques, such as increasing freeboard height, installing freeboard cooling coils and heating coils to
raise vapor temperature, adding a cover to the machine, reducing room draft, and installing a carbon
adsorber to adsorb solvent on the carbon (Durkee, 1997).
State of Development and Current Level of Usage
High quality design equipment can be retrofitted in a cost effective manner; however, this option is not
viable for older equipment that should instead be replaced. Retrofitting equipment is occurring worldwide on newer vapor degreasers.
Associated Risks and Uncertainties
Proper employee training on the use of retrofitted equipment and frequent scheduled checks of stabilizer
level with adjustments should be implemented to minimize safety risks in the workplace.
Potential Applicability in Different Regions
Technologically, this option is applicable in all regions.
Option
Retrofit
Reduction
Lifetime
Efficiency
(years)
(%)
10
90
Fixed Cost
($2000
US/tCO2 Eq)
370.37
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
0.00
27.83
Key References
Durkee, J.B. 1997. Chlorinated Solvents NESHAP -- Results to Date, Recommendations and
Conclusions. International Conference on Ozone Layer Protection Technologies. November 12-13,
1997. Baltimore, MD.
B-69
SECTOR:
Solvents
OPTION NAME:
Not-In-Kind (NIK) Technology Processes and Solvent Replacements (NIK
Aqueous and Semi-aqueous Cleaning)
OPTION ID:
S2, S3
Brief Description
Aqueous and semi-aqueous cleaning processes use water and detergents as a solvent and a hydrocrarbon
solvent combined with a surfactant, respectively, to remove contaminants. Both aqueous and semiaqueous processes involve washing, rinsing, drying, and wastewater disposal stages. These alternative
cleaning processes have lower material costs because little to no chemical solvents are consumed;
however, these processes also consume more energy to for heated rinses and drying. Costs associated
with water disposal and recycling can also be moderately exepensive (EPA, 2001; UNEP, 1999).
State of Development and Current Level of Usage
According to industry experts, many enterprises in the electronics and metal cleaning sub-sectors have
already switched to aqueous and semi-aqueous NIK alternatives world-wide.
Associated Risks and Uncertainties
VOCs are used with semi-aqueous cleaning, which introduces the risk of flammability, a concern that
might be frequently rectified by improving equipment design. Uncertainties of NIK processes lie in the
costs of additional requirements such as wastewater treatment and electric or other utility needs that arise
from more energy intensive drying processes, especially for aqueous cleaning (U.S. EPA, 2001).
Potential Applicability in Different Regions
This option is applicable to all regions.
Option
NIK (Aqueous)
(S2)
NIK (SemiAqueous) (S3)
Lifetime
(years)
Reduction Fixed Cost
Efficiency
($2000
(%)
US/tCO2 Eq)
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
10
100
40.00
0.00
0.00
10
100
22.22
0.00
0.00
Key References
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
UNEP (United Nations Environment Programme). 1999. 1998 Report of the Solvents, Coatings, and
Adhesives Technical Options Committee (STOC): 1998 Assessment. United Nations Environment
Programme, Ozone Secretariat, April 1999.
B-70
SECTOR:
Solvents
OPTION NAME:
Alternative Solvents (HFEs)
OPTION ID:
S4
Brief Description
In recent years, developments in HFE solvents have gained acceptance as an effective alternative for use
in solvent cleaning. HFEs have successfully replaced PFCs, HFCs, CFC-113, 1,1,1-trichloroethane, and
HCFCs primarily in precision cleaning operations. Their low toxicity, non-flammability, zero ozone
depleting potential, and low GWPs of 390 and 55, (GWPs for commercially available HFE-7100 and
HFE-7200, respectively) are clear advantages for their use, although their use is more costly on a per
kilogram basis (U.S. EPA, 2001; UNEP, 1999a).6 PFCs are assumed to be only used in the United States;
however, the baselines used for this study did not explicitly estimate PFCs emissions from solvents;
consequently, this option is only applicable to HFC solvent emissions.
State of Development and Current Level of Usage
HFEs and the various azeotropic formulations based on HFEs are already used in solvent industries of
developed nations. HFEs are a viable alternative in critical cleaning applications “where compatibility
with the substrate to be cleaned is essential” (U.S. EPA, 2001).
Associated Risks and Uncertainties
Due to compatibility issues, some uncertainty exists regarding the likelihood and ease with which those in
the industry who use particular azeotropes or blends of HFCs will change to an HFE alternative solvent.
Potential Applicability in Different Regions
Since HFEs are not always a technically feasible substitute for HFC 4310mee solvents due to applicationspecific requirements, this option is assumed to be only applicable to a small percentage of HFC 4310mee
users in the U.S., developed nations, and to countries in the rest of the world (UNEP, 1999b).
Option
Alternative
Solvents (HFEs)
Reduction Fixed Cost
Recurring
Lifetime
Efficiency
($2000
Cost ($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq)
10
85
0.00
1.29
Cost Offset
($2000
US/tCO2 Eq)
0.00
Key References
UNEP (United Nations Environment Programme). 1999a. 1998 Report of the Solvents, Coatings, and
Adhesives Technical Options Committee (STOC): 1998 Assessment. United Nations Environment
Programme, Ozone Secretariat, April 1999.
6
HFC-4310mee has a GWP of 1,500, a factor of 4 to 30 times higher than these HFEs according to IPCC’s Third
Assessment Report (2001).
B-71
UNEP (United Nations Environment Programme). 1999b. The Implications to the Montreal Protocol of
the Inclusion of HFCs and PFCs in the Kyoto Protocol. HFC and PFC Task Force of the Technology and
Economic Assessment Panel (TEAP). United Nations Environment Programme, October 1999.
U.S. EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
B-72
SECTOR:
OPTION NAME:
Foams
Replacing HFC-134a and HFC-245fa or HFC-365mfc in Appliance and Spray
Polyurethane Foam with Hydrocarbons
OPTION ID:
F1 to F3
Brief Description
Blowing agent alternatives to HFCs include hydrocarbons (HCs) such as propane, butane, isobutane, npentane, isopentane, cyclopentane, and isomers of hexane.. Compared to HFCs, HCs have lower GWPs
and are more cost-effective.
State of Development and Current Level of Usage
This option is well developed technologically. It is widely adopted in the appliance sector, especia lly in
Europe. However, because of the associated risks and uncertainties, this method is not very popular in the
spray foam industry (UNEP, 2002).
Associated Risks and Uncertainties
Key risks and uncertainties associated with the use of HCs are their flammability, performance, and
contribution to the ground level ozone and smog. HCs require stringent safety precautions in
manufacturing, storage, handling, transport, and customer use, which necessitate factory upgrades and
employee training. In order to reduce fire risks, a larger quantity of flame-retardants and/or the use of a
more expensive fire-retardant might be required for some applications (U.S. EPA, 2001). All costs
associated with the increase use of fire retardants are included in our cost estimates.
Foams blown with HCs only yield approximately 85 percent of the insulating value of HCFC. Producing
a thicker foam can compensate for this energy efficiency difference, but will increase the cost of
production. Other performance considerations include dimensional stability and solubility. Addressing
these factors might require a more expensive and more limited polyol formulation 7 (U.S. EPA, 2001).
Potential Applicability in Different Regions
Technologically, this abatement option has no regional applicability limitations.
Option
Appliance:
HFC-134a to HC
(F1)
Appliance:
HFC-245fa or
HFC-365mfc to
HC (F2)
Spray:
HFC- 245fa HFC-
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
25
100
105.79
-3.19
0.00
25
100
144.40
32.35
0.00
25
100
7.81
-3.82
0.00
7
Financial information used in this analysis include: costs associated with changes in foam density, testing costs,
training costs, costs associated with the quantity and type of polyol, indirect costs from energy efficiency differences
and other costs associated with transitioning to non-HFC alternatives.
B-73
365mfc to HC
(F3)
Key References
U.S.EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
UNEP, 2002. Report of the Technology and Economic Assessment Panel. Progress Report. Montreal
Protocol on the Substances that deplete the Ozone Layer.
B-74
SECTOR:
Foams
OPTION NAME:
Replacing HFC-134a or HFC-152a in Extruded Polystyrene and HFC-245fa in
Spray Foams with Water blown in situ Carbon Dioxide (CO2 /water)
OPTION ID:
F4, F5
Brief Description
A chemical reaction between water and polymeric isocyanate generates carbon dioxide (CO2 ) blowing
agent to be used in foam blowing. CO2 used in this process is generated in situ (UNEP, 1998). .
However, formulations manufactured with CO2 blowing agent have poorer water proofing capabilities.
The water proofing quality can improve with an increased content of the polymeric isocyanurate, which
requires machinery retrofit or purchase of the new equipment (UNEP 1998).
State of Development and Current Level of Usage
This option is fairly well developed and the research on its improvement is still going on. Patent filings by
manufacturers continue, as fewer options exist after HCFCs are phased out. CO 2 /water blown foam
applications are widely used in Europe.
Associated Risks and Uncertainties
Foams produced using CO2 /water blowing agents are subject to technological and performance
limitations such as: thickness (currently no greater than 100-120mm), lower thermal conductivity, lower
dimensional stability, and higher density versus HCFC- and HFC- blown foams 8 (UNEP, 1998; UNEP,
2002). Additionally, the use of CO 2 /water blown agents in PU foam applications increases the percentage
of open cell content, which results in poorer waterproofing performance of the final product (U.S. EPA,
2001).
Potential Applicability in Different Regions
Technologically, this abatement option has no regional applicability limitations.
Option
Spray: HFC-245fa
to CO2 (F4)
XPS: HFC-134a or
HFC-152a to CO2
(F5)
Lifetime
(years)
Reduction Fixed Cost
Recurring
Cost Offset
Efficiency
($2000
Cost ($2000
($2000
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
25
100
2.23
23.97
0.00
25
100
8.89
-0.14
0.00
Key References
U.S. EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
8
Financial information used in this analysis include: costs associated with changes in foam density, testing costs,
training costs, indirect costs from energy efficiency differences and other costs associated with transitioning to nonHFC alternatives.
B-75
UNEP, 2002. Report of the Technology and Economic Assessment Panel. Progress Report. Montreal
Protocol on the Substances that deplete the Ozone Layer.
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
UNEP, 1998. Report of the Flexible and Rigid Foams Technical Options Committee. United Nations
Environment Programme.
B-76
SECTOR:
Fire Extinguishing
OPTION NAME:
Inert Gas Systems
OPTION ID:
FE1
Brief Description
Inert gas systems can be used in place of standard HFC systems in Class A (ordinary combustible) total
flooding applications, including electronics and telecommunications applications. Inert gas systems use
gases such as argon, nitrogen, carbon dioxide or a blend of these gases to extinguish fires (UNEP, 2001).
Substantially more agent is needed to extinguish fires using inert gases than using HFCs (U.S. EPA,
2001).
State of Development and Current Level of Usage
Inert gas systems are well developed and commercially available.
Associated Risks and Uncertainties
Several risks are associated with inert gas systems that may effectively render this option not technically
feasible for some applications. Specifically, the discharge times of these systems are on the order of 60
seconds or more, which is 4 to 6 times slower than standard HFC systems (Kucnerowicz-Polak, 2002;
UNEP, 2001). Therefore, inert gas systems are not recommended for areas where a rapidly developing
fire can be expected. Furthermore, the additional space and weight needed to accommodate additional
steel cylinders of inert gas may prohibit the retrofit of many existing HFC systems, and new systems for
which the infrastructure is fixed (U.S. EPA, 2001). Additional space requirements, as well as the
associated heating and cooling costs, have been considered in developing cost estimates for this option
(U.S. EPA, 2001). Furthermore, because inert gas systems may not easily be used as a retrofit option, the
technical applicability of this option is assumed to increase over time, as old systems are replaced and
new systems built.
Potential Applicability in Different Regions
Inert gas systems can penetrate markets equally across all regions.
Option
Inert Gas Systems
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
10
100
98.57
3.57
0.00
Note: All cost information is from U.S. EPA (2001).
9
Financial information used in this analysis include: costs associated with changes in foam density, testing, training,
indirect costs from energy efficiency differences, and other costs associated with transitioning to non-HFC
alternatives.
10
Reflects the % of emissions from foams.
B-77
Key References
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
Kucnerowicz-Polak, B. 2002. Halon Sector Update. Presentation at the 19th Meeting of the Ozone
Operations Resource Group (OORG), The World Bank, Washington, DC, March 28, 2002.
UNEP (United Nations Environment Programme). 2001. Standards and Codes of Practice to Eliminate
Dependency on Halons: Handbook of Good Practices in the Halon Sector. UNEP Division of
Technology, Industry and Economics (DTE) under the OzonAction Programme under the Multilateral
Fund for the Implementation of the Montreal Protocol, in cooperation with The Fire Protection Research
Foundation. United Nations Publication ISBN 92-807-1988-1.
U.S. EPA (Environmental Protection Agency). 2001. U.S. High GWP Gas Emissions 1990-2010:
Inventories, Projections, and Opportunities for Reductions. U.S.EPA #000-F-97-000. Office of Air and
Radiation, U.S. Environmental Protection Agency. Washington, DC, June 2001.
B-78
SECTOR:
Fire Extinguishing
OPTION NAME:
Water Mist
OPTION ID:
FE2
Brief Description
Water mist systems use relatively small droplet sprays under low, medium, or high pressure to extinguish
fires. Unlike tradition water-spray systems or conventional sprinklers, water mist systems use specially
designed nozzles to produce much smaller droplets, requiring significantly less water to extinguish fires
(UNEP, 2001; Wickham, 2002). Theoretically, water mist systems can be used in all Class B (fuel)
hazards, where low temperature freezing is not a concern (U.S. EPA, 2001).
State of Development and Current Level of Usage
To date, water mist systems have been used in storage and machinery spaces, shipboard accommodation,
combustion turbine enclosures, light and ordinary hazard sprinkler applications, and flammable and
combustible liquid machinery (UNEP, 2001). Although these systems are commercially available,
research is underway to make them applicable to a wider range of fire extinguishing applications (see
below) (Wickham, 2002).
Associated Risks and Uncertainties
Several technical challenges remain to be resolved before water mist systems can reach their market
potential in Class B fire hazards. Thus far, water mist systems have been limited to fire extinguishing
applications for which fire test protocols have already been developed, based on empirically tested system
performance (i.e., in spaces greater than 2,000 m3 ) (IMO, 2001; Wickham, 2002). Researchers believe,
however, that solutions to these problems are within reach (Wickham, 2002).
Potential Applicability in Different Regions
Water mist systems can penetrate equally across all regions.
Option
Water Mist
Lifetime
(years)
10
Reduction Fixed Cost
Recurring
Efficiency
($2000
Cost ($2000
(%)
US/tCO2 Eq) US/tCO2 Eq)
100
-35.71
0.00
Cost Offset
($2000
US/tCO2 Eq)
0.00
Note: All cost information is from U.S. EPA (2001).
Key References
IEA Greenhouse Gas R&D Programme. 2001. Abatement of Other Greenhouse Gases – Engineered
Chemicals. International Energy Agency, Cheltenham, United Kingdom, February 2001. Report Number
PH3/35.
IMO (International Maritime Organization). 2001. Performance Testing and Approval Standards for Fire
Safety Systems: Fire Test Protocols for Fire-Extinguishing Systems, Submitted by Germany to the Subcommittee on Fire-Protection, 46th session, Agenda item 12, 30 November, 2001.
B-79
UNEP (United Nations Environment Programme). 2001. Standards and Codes of Practice to Eliminate
Dependency on Halons: Handbook of Good Practices in the Halon Sector. UNEP Division of
Technology, Industry and Economics (DTE) under the OzonAction Programme under the Multilateral
Fund for the Implementation of the Montreal Protocol, in cooperation with The Fire Protection Research
Foundation. United Nations Publication ISBN 92-807-1988-1.
U.S.EPA (Environmental Protection Agency). 2001. U.S. High GWP Gas Emissions 1990-2010:
Inventories, Projections, and Opportunities for Reductions. U.S.EPA #000-F-97-000. Office of Air and
Radiation, U.S. Environmental Protection Agency. Washington, DC, June 2001.
Wickham, Robert. 2002. Status of Industry Efforts to Replace Halon Fire Extinguishing Agents.
Wickham Associates. March 16, 2002. Available at http://www.epa.gov/ozone/snap/fire/status.pdf
B-80
SECTOR:
HFC-23 Emissions from HCFC-22 Production
OPTION NAME:
Thermal Oxidation
OPTION ID:
H1
Brief Description
Thermal oxidation is a cost-effective technology that oxidizes HFC-23 to CO2 , hydrogen fluoride, and
water. Because of the high temperatures required for complete destruction some units could experience
some downtime. A typical incinerator that burns only HFC-23, produces six pounds of CO2 for every
pound of HFC-23 burned. However, these CO 2 emissions are prevented from entering the atmosphere by
scrubbers that are used to remove the hydrogen fluoride from the waste stream.
State of Development and Current Level of Usage
Thermal oxidation is a well-developed technology and is used in several EU countries and the US.
Associated Risks and Uncertainties
This abatement option is technically able to abate 95 percent of emissions.
Potential Applicability in Different Regions
Technologically, thermal oxidation can be applied in any facility that produces HCFC-22.
Option
Thermal
Oxidation
Lifetime
(years)
Reduction
Efficiency
(%)
Fixed Cost
($2000
US/tCO2 Eq)
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
10
95
1.24
0.08
0.00
Key References
IEA GHG. 2001. Abatement of Other Greenhouse Gases – Engineered Chemicals. Greenhouse Gas R&D
Programme, International Energy Agency.
B-81
SECTOR:
Aluminium Production
OPTION NAME:
Minor/Major Retrofit for Vertical/Horizontal Stud Soderberg and CentreWorked/Side-Worked Prebake Technologies
OPTION ID:
AL1 to AL8
Brief Description
For all smelter technologies, the minor retrofit option relates to the installation of process computer
control systems or the refinement of existing process control algorithms. These systems enhance the
ability of smelters to identify and reduce anode effects through controlling alumina feeding and carbon
anode positioning.
The major retrofit option relates to the conversion or installation of alumina point-feed systems. The
major option is incremental to the minor option, since system improvements imparted through use of
point feeding cannot be realized without a process control system in-place. Point feed systems enable
greater control of alumina feeding to the cell, and thus reduce anode effects, which occur when alumina
levels in the cell drop to low levels.
State of Development and Current Level of Usage
These options are well developed technologically and are widely used in several regions. Many countries,
including Australia, Brazil, Canada, Norway, and the United States, have undertaken industrygovernment initiatives to reduce perfluorocarbon emissions. The reported technical initiatives undertaken
to reduce emissions include the options described herein (U.S. EPA, 1999).
Associated Risks and Uncertainties
While a small number of multinational firms dominate the aluminium industry (e.g., Alcoa, Alcan), there
are a number of producers controlled by smaller companies, traders, and governments who lack the
organisational, technical and financial resources of the larger firms. Consequently, the ability of these
smaller producers to implement applicable mitigation technologies may be hampered (IEA GHG, 2000).
Potential Applicability in Different Regions
Both abatement options are based on retrofitting existing cell technologies. Consequently, the
implementation of these options does not require a major change in the prevailing technology, and can,
thus, be applied to all cell technology types (IEA GHG, 2000).
B-82
Option
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)a
US/tCO2 Eq) US/tCO2 Eq)b US/tCO2 Eq)
Major Retrofit for
Vertical Stud
15
11
425.10
82.36 - 99.22
101.77
Soderberg (AL1)
Major Retrofit for
15
Horizontal Stud
13
390.56
67.10 - 63.87
61.12
Soderberg (AL2)
Major Retrofit for
308.84 Side-Worked Prebake
15
4
239.45
369.90
360.13
(AL3)
Major Retrofit for
275.63 Centre-Worked
15
4
378.10
369.53
359.23
Prebake (AL4)
Minor Retrofit for
Vertical Stud
15
42
12.34
21.57 - 25.99
26.65
Soderberg (AL5)
Minor Retrofit for
Horizontal Stud
15
17
32.46
48.85 - 51.32
46.74
Soderberg (AL6)
Minor Retrofit for
88.24 Side-Worked Prebake
15
21
51.04
105.69
102.89
(AL7)
Minor Retrofit for
157.5 Centre-Worked
15
21
116.62
211.16
205.28
Prebake (AL8)
a
Reduction efficiency for major retrofit options are reflect additional reductions after minor retrofit
options are applied. For example, combined reduction efficiency for Vertical Stud Soderberg options are
53 percent with Minor Retrofit providing 42 percent and Major Retrofit – additional 11 percent.
b
Recurring costs for Aluminum vary depending upon the region due to differences in operating costs.
Values for this category are presented as a range.
Key References
IEA Greenhouse Gas R&D Programme. 2000. Greenhouse Gas Emissions from the Aluminum Industry,
Greenhouse Gas Research & Development Program, International Energy Agency. Cheltenham, United
Kingdom, January 2000.
U.S. EPA. 1999, International Efforts to Reduce Perfluorocarbon (PFC) Emissions from Primary
Aluminum Production, U.S. EPA 430-R-99-001.
B-83
SECTOR:
Magnesium
OPTION NAME:
Sulphur Dioxide (SO2 ) – Alternate Cover Gas
OPTION ID:
MG1
Brief Description
SO2 can be used as a direct cover gas replacement for SF6 to prevent rapid oxidatio n and surface burning
when molten magnesium is exposed to air. While it is an old technology, recent developments in process
control technologies and feed systems, enable it to be applied with no harmful health, odor and/or
corrosive effects.
State of Development and Current Level of Usage
This option is well developed technologically and is widely used in China. In other regions, SF6 is
considered the primary cover gas mechanism.
Associated Risks and Uncertainties
SO2 is a toxic gas, and with its usage there are associated health and workplace exposure issues. The gas
is corrosive to casting equipment and would require corrosion protection when used. These risks can be
addressed through the use of proper technology, such as gas scrubbing, and the implementation of SO 2
safety training. Consequently, the capital cost of implementing this option may be high.
Potential Applicability in Different Regions
Due to the development of new control technologies, SO 2 has become a viable replacement option to SF6 .
Consequently, it is applicable to all regions (U.S. EPA, 2001).
Option
Sulfur Dioxide
Reduction
Lifetime
Efficiency
(years)
(%)
10
100
Fixed Cost
($2000
US/tCO2 Eq)
4.55
Recurring
Cost Offset
Cost ($2000
($2000
US/tCO2 Eq) US/tCO2 Eq)
0.00
0.00
Key References
IEA GHG. 2001. Abatement of Other Greenhouse Gases – Engineered Chemicals. Greenhouse Gas R&D
Programme, International Energy Agency.
U.S. EPA. 2001. U.S. High GWP Gas Emissions 1990-2010: Inventories, Projections, and Opportunities
for Reductions. U.S.EPA #000-F-97-000. Office of Air and Radiation, U.S. Environmental Protection
Agency. Washington, DC, June 2001.
B-84
SECTOR:
Electric Transmission and Distribution
OPTION NAME:
SF6 Leakage Reduction and Recovery
OPTION ID:
ET1
Brief Description
SF6 is emitted into the atmosphere from equipment leaks resulting from mechanical or structural
problems, as well as from during maintenance operations. Leak detection and repair abatement options,
such as gas sensors, and recycling gas cart systems provide methods to identify and reduce SF6 that leaks
from electrical switchgear equipment.
State of Development and Current Level of Usage
These options are well developed technologically and are used in all regions.
Associated Risks and Uncertainties
SF6 -containing equipment leakage may vary based on the type of equipment (i.e., size of operational
voltage, type of operational use (e.g., circuit breaker, transformers, and switchgear), manufacturer,
weather (i.e., equipment located in a region with extreme weather/temperature fluctuations may be subject
to mechanical stresses), etc. Consequently, application of these techniques may vary based on
region/country of use.
Potential Applicability in Different Regions
SF6 leakage reduction and recovery techniques are considered easy abatement options for conservative
gas handling practices, due to their availability, relatively low costs and ease of use. Both options are
applicable to all regions using SF6 gas-insulated electric equipment.
Option
SF6 Leakage
Reduction &
Recycling
Lifetime
(years)
10
Reduction Fixed Cost
Efficiency
($2000
(%)
US/tCO2 Eq)
100
10.96
Recurring
Cost ($2000
US/tCO2 Eq)
Cost Offset
($2000
US/tCO2 Eq)
0.07-3.54
0.00
Key References
IEA GHG. 2001. Abatement of Other Greenhouse Gases – Engineered Chemicals. Greenhouse Gas R&D
Programme, International Energy Agency.
B-85
SECTOR:
Electric Gas Insulated Switch Gear (GIS) Manufacture
OPTION NAME:
Improved SF6 Recovery
OPTION ID:
EG1
Brief Description
During the manufacture and testing of electric switchgear equipment, losses of SF6 may occur. SF6
recovery equipment, such as recycling gas cart systems provides a method to remove gas from the
electrical equipment, and filter it for reuse.
State of Development and Current Level of Usage
This option is well developed technologically and is used in all regions.
Associated Risks and Uncertainties
SF6 emissions during manufacturing and testing of gas-insulated equipment are estimated to be in the
range of 30-50 percent of total equipment charge size (IEA GHG, 2001). The use of recycling equipment
is estimated to reduce emissions down to at least 10 percent of charge size.
Potential Applicability in Different Regions
This option is applicable to all manufacturers of gas insulated electrical equipment. .
Option
Improved SF6
Recovery
Reduction Fixed Cost
Recurring
Lifetime
Efficiency
($2000
Cost ($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq)
15
100
1.84
0.01-0.6
Cost Offset
($2000
US/tCO2 Eq)
0.00
Key References
IEA GHG. 2001. Abatement of Other Greenhouse Gases – Engineered Chemicals. Greenhouse Gas R&D
Programme, International Energy Agency.
B-86
SECTOR:
Semiconductors
OPTION NAME:
NF3 Remote Clean Technology and C3 F8 Replacement
OPTION ID:
SC1, SC2
Brief Description
Semiconductor manufacturing applies on C2 F6 as a common dry chamber cleaning gas. At the same time
industry has developed a few NF3 -based clean recipes that could be used in place of C2 F6 . Two basic NF3
clean technologies include (1) the introduction of NF3 directly into the CVD process chamber (in situ) and
(2) dissociation of NF3 in a plasma upstream of the CVD process chamber (U.S. EPA, 2001). The NF3
GWP is only slightly lower than C2 F6 (8000 vs. 9200), so its main abatement effect is related to its overall
efficiency as compared to C2 F6 (less NF3 is needed to perform the same function as C2 F6.) (U.S. EPA,
2001).
The use of C3 F8 is another option/gas used for cleaning CVD chambers. When used, C3 F8 does not
achieve the same emission reduction that NF3 achieves. However, C3 F8 is a drop-in replacement for C2 F6
and may be cheaper in many instances (fabs must be "plumbed" for NF3 use and NF3 is almost 10x cost of
C3 F8 ). However, because NF3 results in shorter clean times, tool utilization may increase (and with it fab
productivity) so that the higher capital and somewhat (net) higher operating gas costs can be justified.
State of Development and Current Level of Usage
These options are well developed technologically and can be used by semiconductor fabrication facilities
(fabs) worldwide.
Associated Risks and Uncertainties
The option is feasible only for control of emissions from chamber cleaning processes which account, on
average, for approximately 70 percent of fab emissions.
Potential Applicability in Different Regions
Technologically, cleaning options can be applied in any fab with emissions from chamber cleaning
processes without existing abatement controls.
Option
C3 F8 Replacement
NF3 Remote Clean
Technology
Lifetime
(years)
5
5
Reduction Fixed Cost
Recurring
Cost Offset
Efficiency
($2000
Cost ($2000
($2000
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
100
0.00
0.00
0.00
100
90.76
0.00
0.00
Key References
U.S.EPA (Environmental Protection Agency). 2001. U.S. High GWP Gas Emissions 1990-2010:
Inventories, Projections, and Opportunities for Reductions. U.S.EPA #000-F-97-000. Office of Air and
Radiation, U.S. Environmental Protection Agency. Washington, DC, June 2001.
B-87
SECTOR:
Semiconductors
OPTION NAME:
Point-of-Use Plasma Abatement (Litmas)
OPTION ID:
SC3
Brief Description
The abatement system based on point-of-use plasma (POU) is placed downstream of each etch (process)
tool before gases enter the nitrogen waste stream. (U.S. EPA, 2001). This system uses a small plasma
source to break PFC molecules into components that can be removed using the fab’s gas scrubbing
system. To improve PFC destruction efficiency, molecular hydrogen, oxygen or water may be added to
the plasma with the PFC. This option has been demonstrated to attain the reduction efficiency of close to
100 percent when water vapour is used as an additive gas (U.S. EPA 2001).
State of Development and Current Level of Usage
This option is well developed technologically and is being adopted by fabs worldwide.
Associated Risks and Uncertainties
The option is feasible only to control emissions from etch processes, which account, on average, for
approximately 30 percent of fab emissions. The evaluations performed to date indicate no apparent
interference with the etch process.
Potential Applicability in Different Regions
Technologically, this option can be applied in any fab with emissions from etch processes without
existing abatement controls.
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
Plasma Abatement
5
100
50.81
1.45
0.00
Option
Key References
U.S. EPA (Environmental Protection Agency). 2001. U.S. High GWP Gas Emissions 1990-2010:
Inventories, Projections, and Opportunities for Reductions. U.S.EPA #000-F-97-000. Office of Air and
Radiation, U.S. Environmental Protection Agency. Washington, DC, June 2001.
B-88
SECTOR:
Semiconductors
OPTION NAME:
Thermal Destruction
OPTION ID:
SC4
Brief Description
The thermal destruction option can be used to abate PFC emissions from the etching and the CVD
chamber cleaning process. Its additional benefit is associated with the fact that it is placed downstream of
the process tools assuring that the system does not affect manufacturing processes and performance.
Several commercially available PFC thermal destruction systems can effectively reduce some PFCs
emissions , but only a few have been proven to abate all PFCs with the efficiency exceeding 90 percent.
These systems are placed downstream of one or more process tools (U.S. EPA 2001).
State of Development and Current Level of Usage
This option is well developed technologically and is being adopted by fabs worldwide, although other
options that reduce emissions through process improvements appear preferable and seem to carrying the
major burden associated with reducing PFC emissions.
Associated Risks and Uncertainties
The option is feasible for control of fab-wide emissions. The combustion devices require fuel and
consume large amounts of cooling water, which contributes to an additional waste stream. Thermal
oxidation may also produce NOx emissions, which can be regulated as air pollutants (U.S. EPA 2001).
Potential Applicability in Different Regions
Technologically, this option can be applied in any fab with emissions without existing fab-wide
abatement controls.
Option
Thermal Destruction
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
5
99
93.39
8.98
0.00
Key References
U.S. EPA (Environmental Protection Agency). 2001. U.S. High GWP Gas Emissions 1990-2010:
Inventories, Projections, and Opportunities for Reductions. U.S.EPA #000-F-97-000. Office of Air and
Radiation, U.S. Environmental Protection Agency. Washington, DC, June 2001.
B-89
SECTOR:
Semiconductors
OPTION NAME:
Catalytic Decomposition System (Hitachi)
OPTION ID:
SC5
Brief Description
Catalytic destruction systems are installed downstream of the process tools in a manner that minimizes
potential adverse impacts on manufacturing processes. Catalytic abatement systems operate at
temperatures that are lower than those used in thermal abatement, which reduces NO x emissions and fuel
use. Additional costs include the cost of periodic catalyst replacement. The reduction efficiency of this
option is around 98 percent (U.S. EPA 2001).
State of Development and Current Level of Usage
This option is well developed technologically and is being adopted by fabs worldwide.
Associated Risks and Uncertainties
The option is feasible for control of fab-wide emissions. The option design must reflect a minimum
concentration and flow of PFC within the exhaust stream. Consequently, off-the-shelf systems can be
applied only at facilities with certain stream or process types (U.S. EPA 2001).
Potential Applicability in Different Regions
Technologically, this option can be applied in any fab with emissions without existing fab-wide
abatement controls.
Option
Catalytic
Decomposition
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
5
99
67.35
5.32
0.00
Key References
U.S.EPA (Environmental Protection Agency). 2001. U.S. High GWP Gas Emissions 1990-2010:
Inventories, Projections, and Opportunities for Reductions. U.S.EPA #000-F-97-000. Office of Air and
Radiation, U.S. Environmental Protection Agency. Washington, DC, June 2001.
B-90
SECTOR:
Semiconductors
OPTION NAME:
PFC Recapture/Recovery
OPTION ID:
SC6
Brief Description
PFC recapture and recovery can be economically feasible for treating the waste streams of entire fabs and
is based on separating un-reacted and/or process-generated PFCs from other gases for further processing.
Currently available systems can remove about 90 percent of emissions. On average, the removal
efficiency of C2 F6 , CF4 , SF6 , and C3 F8 is high 90s (percent), while CHF3 and NF3 removal efficiencies are
between 50 to 60 percent. This analysis uses an average value of 90 (U.S. EPA 2001).
State of Development and Current Level of Usage
This option has been evaluated but has not yet been adopted widely by fabs worldwide.
Associated Risks and Uncertainties
The option is feasible for control of fab-wide emissions. The treatment process includes the possibility of
some recycling or reuse of the captured PFC gas. However, semiconductor manufacturing exhaust
requires considerable pre-treatment to remove undesirable substances. Since the current demand for
recycled PFCs is low, either destruction or reprocessing is more feasible (U.S. EPA 2001).
Potential Applicability in Different Regions
Technologically, this option can be applied in any fab with emissions without existing fab-wide
abatement controls.
Option
PFC Recapture
Reduction Fixed Cost
Recurring
Cost Offset
Lifetime
Efficiency
($2000
Cost ($2000
($2000
(years)
(%)
US/tCO2 Eq) US/tCO2 Eq) US/tCO2 Eq)
5
100
40.52
13.20
0.00
Key References
U.S.EPA (Environmental Protection Agency). 2001. U.S. High GWP Gas Emissions 1990-2010:
Inventories, Projections, and Opportunities for Reductions. U.S.EPA #000-F-97-000. Office of Air and
Radiation, U.S. Environmental Protection Agency. Washington, DC, June 2001.
B-91
Appendix C: Examples of Economic Applicability Functions
Equation used to estimate the raw values of Economic Applicability (EA0 ) of overlapping mutually
excluding options is as follows:
EA0 = - atan(x/k) / p +0.5
, where x is an option’s net specific cost, atan – arctangent function, p – number p, and k –
positive constant. The final values of EA are calculated by normalizing the raw values so that the
sum of source-specific EAs is equal to one
Figure C-1 below shows the Economic Applicability curves developed for a set of hypothetical options
using different values of k. For this study, the value of 10 was selected for k .
Figure C-1: Economic Applicability with Different Values of Constant k
0.1
0.09
0.08
Economic Applicability
0.07
0.06
k=5
k=10
0.05
k=20
0.04
0.03
0.02
0.01
0
-100
-90
-80
-70
-60
-50
-40
-30
-20
-10
0
10
20
30
40
50
60
70
80
90
100
Net Specific Cost
C-1
Figure C-2 shows the relationship between the abatement potentials of six hypothetical mutually
excluding options (with net specific costs equal to –10, -2, 5, 10, 20, 50 $/tCO2 Eq.). All the
options in this example are assumed to have the same value of Reduction Efficiency (RE) (50,
70, or 90 percent) and Technical Applicability (100 percent).
Figure C-2: Abatement Potentials (AP) of Six Mutually Excluding Options at Different Levels of
Reduction Efficiency (RE)
35%
30%
Abatement Potential (%)
25%
20%
15%
10%
5%
0%
-20
-10
0
10
20
30
40
50
60
Specific Abatement Cost ($/tCO2)
RE = 50%
RE = 70%
RE = 90%
C-2
Figure C-3 compares the Abatement Potentials (APs) of the options from the previous example
with the six sequential options, which have the same net specific abatement costs (RE of all the
options is 70% and TA is 100%). As one can expect, the cumulative abatement potential that can
be achieved by the sequential options is much greater than the one that can be achieved by
mutually excluding options at the same Reduction Efficiency.
Figure C-3: Abatement Potential of Six Hypothetical Mutually Excluding and Sequential Options.
(Reduction Efficiency is 70% and Technical Potential is 100%)
120%
100%
Abatement Potential
80%
60%
40%
20%
0%
-20
-10
0
10
20
30
40
50
60
Specific Cost ($/tCO2)
Mutually Excluding Options
Sequential Options
Mutually Excluding Options - Cumulative
Sequential Options - Cumulative
C-3
Appendix D: Temporal Changes in Technical Applicability of
Industrial Sector Options
Table D-1: Minimum 1 Values of Technical Applicability (%) in 2000, 2010, and 2020
Sector/Subsector
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Fire Extinguishing
Fire Extinguishing
Aerosols (Non-MDI)
Aerosols (Non-MDI)
Aerosols (Non-MDI)
Aerosols (MDI)
Solvents
Solvents
Solvents
Solvents
Foams
Foams
1
Abatement Option
Leak Repair - Chille rs
Replace DX with Distributed System - Retail Food
Secondary Loop - Retail Food
Ammonia Secondary Loop - Retail Food
Leak Repair - Retail Food
Other Alternative Refrigerants - Retail Food
Replace DX with Distributed System - Cold Storage
Secondary Loop - Cold Storage
Ammonia Secondary Loop - Cold Storage
Leak Repair - Cold Storage
Other Alternative Refrigerants - Cold Storage
Ammonia Secondary Loop - Industrial Process
Refrigeration
Leak Repair - Industrial Process Refrigeration
Other Alternative Refrigerants - Industrial Process
Refrigeration
Leak Repair - Commercial A/C
Leak Repair - Residential A/C
Refrigerant Recovery - Transport Refrigeration
Other Alternative Refrigerants - Transport
Refrigeration
Refrigerant Recovery - Small Appliances
Domestic HC - Small Appliances
Refrigerant Recovery - MVACs
CO2 for MVAC - MVACs
Inert Gases
Water Mist
Hydrocarbon Aerosol Propellants (Replacing HFC134a)
Not In Kind (NIK) Products (Replacing HFCs with
NIK products)
HFC-152a (Replacing HFC-134a with HFC-152a)
Dry Powder Inhalers (DPIs)
Retrofit (Improved Equipment and Cleaning Processes
with Existing Solvents)
Not-In-Kind (NIK) Technology Processes and Solvent
Replacements (Aqueous Cleaning)
Not-In-Kind (NIK) Technology Processes and Solvent
Replacements (Semi-aqueous Cleaning)
Alternative Solvents (HFEs)
Replacing HFC-245fa or 365mfc in Appliances with
Hydrocarbons (HC)
Replacing HFC-134a in Appliances with
2000
0.0
10.9
10.9
10.9
5.5
10.9
6.0
6.0
6.0
3.0
6.0
2010
0.0
23.4
23.4
23.4
11.7
23.4
14.1
14.1
14.1
7.1
14.1
2020
2.5
18.1
18.1
18.1
9.0
18.1
22.6
22.6
22.6
11.3
22.6
2.0
4.7
7.5
1.0
2.4
3.8
2.0
4.7
7.5
0.0
0.2
4.4
0.0
0.4
4.8
0.0
0.4
6.0
0.0
0.0
0.0
1.3
2.7
18.1
36.1
15.2
0.8
1.1
2.3
8.8
17.6
34.2
2.4
2.2
4.4
7.4
14.8
64.6
4.0
40.0
40.0
40.0
100.0
100.0
100.0
48.0
50.0
48.0
50.0
48.0
50.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
5.0
5.0
5.0
0.0
8.0
8.0
0.0
1.0
1.0
Minimum value of Technical Applicability across different regions.
D-1
Sector/Subsector
Abatement Option
Hydrocarbons (HC)
Foams
Replacing HFC-245fa or 365mfc in Sprays with
Hydrocarbons (HC)
Foams
Replacing HFC-245fa or 365mfc in Spray Foams with
Water blown in situ Carbon Dioxide
Foams
Replacing HFC-134a or HFC-152a in Extruded
Polystyrene with Water blown in situ Carbon Dioxide
HCFC-22 Production Thermal Oxidation
Semiconductors
Thermal Destruction/Thermal Processing Units (TPU)
Semiconductors
Catalytic Decomposition System (Hitachi)
Semiconductors
PFC Recapture/Recovery
Semiconductors
Point-of-Use Plas ma Abatement (Litmas)
Semiconductors
Chemical Vapor Deposition Cleaning Emission
Reduction - NF3 Remote Clean Technology
Semiconductors
Chemical Vapor Deposition Cleaning Emission
Reduction – C3F8 Replacement
Electric T&D
Leakage Reduction and Recovery
Aluminum
Major Retrofit for Vertical Stud Soderberg
Technologies
Aluminum
Major Retrofit for Horizontal Stud Soderberg
Technologies
Aluminum
Major Retrofit for Side-Worked Prebake Technologies
Aluminum
Major Retrofit for Centre-Worked Prebake
Technologies
Aluminum
Minor Retrofit for Vertical Stud Soderberg
Technologies
Aluminum
Minor Retrofit for Horizontal Stud Soderberg
Technologies
Aluminum
Minor Retrofit for Side-Worked Prebake
Technologies
Aluminum
Minor Retrofit for Centre-Worked Prebake
Technologies
Magnesium
Sulphur Dioxide (SO2) – Alternate Cover Gas
Electric GIS
Improved SF6 Recovery
Manufact.
2000
2010
2020
0.0
25.0
25.0
0.0
25.0
25.0
100.0
37.0
37.0
100.0
100.0
100.0
100.0
30.0
100.0
0.0
100.0
100.0
20.0
100.0
100.0
100.0
100.0
10.0
70.0
80.0
90.0
70.0
80.0
90.0
0.0
30.0
60.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
70.0
90.0
0.0
30.0
60.0
D-2
Table D-2: Maximum 2 Values of Technical Applicability (%) in 2000, 2010, and 2020
Sector/Subsector
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Refrigeration/AC
Fire Extinguishing
Fire Extinguishing
Aerosols (Non-MDI)
Aerosols (Non-MDI)
Aerosols (Non-MDI)
Aerosols (MDI)
Solvents
Solvents
Solvents
Solvents
Foams
Foams
Foams
2
Abatement Option
Leak Repair - Chillers
Replace DX with Distributed System - Retail Food
Secondary Loop - Retail Food
Ammonia Secondary Loop - Retail Food
Leak Repair - Retail Food
Other Alternative Refrigerants - Retail Food
Replace DX with Distributed System - Cold Storage
Secondary Loop - Cold Storage
Ammonia Secondary Loop - Cold Storage
Leak Repair - Cold Storage
Other Alternative Refrigerants - Cold Storage
Ammonia Secondary Loop - Industrial Process
Refrigeration
Leak Repair - Industrial Process Refrigeration
Other Alternative Refrigerants - Industrial Process
Refrigeration
Leak Repair - Commercial A/C
Leak Repair - Residential A/C
Refrigerant Recovery - Transport Refrigeration
Other Alternative Refrigerants - Transport
Refrigeration
Refrigerant Recovery - Small Appliances
Domestic HC - Small Appliances
Refrigerant Recovery - MVACs
CO2 for MVAC - MVACs
Inert Gases
Water Mist
Hydrocarbon Aerosol Propellants (Replacing HFC134a)
Not In Kind (NIK) Products (Replacing HFCs with
NIK products)
HFC-152a (Replacing HFC-134a with HFC-152a)
Dry Powder Inhalers (DPIs)
Retrofit (Improved Equipment and Cleaning Processes
with Existing Solvents)
Not-In-Kind (NIK) Technology Processes and Solvent
Replacements (Aqueous Cleaning)
Not-In-Kind (NIK) Technology Processes and Solvent
Replacements (Semi-aqueous Cleaning)
Alternative Solvents (HFEs)
Replacing HFC-245fa or 365mfc in Appliances with
Hydrocarbons (HC)
Replacing HFC-134a in Appliances with
Hydrocarbons (HC)
Replacing HFC-245fa or 365mfc in Sprays with
Hydrocarbons (HC)
2000
0.6
25.2
25.2
25.2
12.6
25.2
8.0
8.0
8.0
4.0
8.0
2010
2.7
30.7
30.7
30.7
15.4
30.7
23.8
23.8
23.8
11.9
23.8
2020
4.1
21.3
21.3
21.3
10.7
21.3
27.0
27.0
27.0
13.5
27.0
2.6
7.9
9.0
1.3
4.0
4.5
2.6
7.9
9.0
0.0
0.4
10.3
0.0
0.4
7.1
0.0
0.5
7.3
0.0
0.0
0.0
3.4
6.7
34.0
68.0
15.2
0.8
3.3
6.5
16.8
33.5
34.2
2.4
2.9
5.9
12.3
24.6
64.6
4.0
40.0
40.0
40.0
100.0
100.0
100.0
48.0
50.0
48.0
50.0
48.0
50.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
5.0
5.0
5.0
0.0
8.0
8.0
0.0
1.0
1.0
0.0
25.0
25.0
Maximum value of Technical Applicability across different regions.
D-3
Sector/Subsector
Foams
Abatement Option
Replacing HFC-245fa or 365mfc in Spray Foams with
Water blown in situ Carbon Dioxide
Foams
Replacing HFC-134a or HFC-152a in Extruded
Polystyrene with Water blown in situ Carbon Dioxide
HCFC-22 Production Thermal Oxidation
Semiconductors
Thermal Destruction/Thermal Processing Units (TPU)
Semiconductors
Catalytic Decomposition System (Hitachi)
Semiconductors
PFC Recapture/Recovery
Semiconductors
Point-of-Use Plasma Abatement (Litmas)
Semiconductors
Chemical Vapor Deposition Cleaning Emission
Reduction - NF3 Remote Clean Technology
Semiconductors
Chemical Vapor Deposition Cleaning Emission
Reduction – C3F8 Replacement
Electric T&D
Leakage Reduction and Recovery
Aluminum
Major Retrofit for Vertical Stud Soderberg
Technologies
Aluminum
Major Retrofit for Horizontal Stud Soderberg
Technologies
Aluminum
Major Retrofit for Side-Worked Prebake Technologies
Aluminum
Major Retrofit for Centre-Worked Prebake
Technologies
Aluminum
Minor Retrofit for Vertical Stud Soderberg
Technologies
Aluminum
Minor Retrofit for Horizontal Stud Soderberg
Technologies
Aluminum
Minor Retrofit for Side-Worked Prebake
Technologies
Aluminum
Minor Retrofit for Centre-Worked Prebake
Technologies
Magnesium
Sulphur Dioxide (SO2) – Alternate Cover Gas
Electric GIS
Improved SF6 Recovery
Manufact.
2000
2010
2020
0.0
25.0
25.0
100.0
37.0
37.0
100.0
100.0
100.0
100.0
30.0
100.0
100.0
100.0
100.0
20.0
100.0
100.0
100.0
100.0
10.0
70.0
80.0
90.0
70.0
80.0
90.0
0.0
30.0
60.0
72.5
69.9
69.9
100.0
100.0
100.0
85.8
85.8
85.8
93.3
93.7
93.3
72.5
69.9
69.9
100.0
100.0
100.0
85.8
85.8
85.8
93.3
93.7
93.3
0.0
70.0
90.0
0.0
30.0
60.0
D-4
Appendix E: Marginal Abatement Cost Curves for 2000 and 2020
Table E-1: Marginal Abatement Cost Curves for the Coal Mining Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central
Europe
0
FSU
0
Japan
0
Latin
America
0
Middle East
0
North
America
0
OECDEurope
0
Rest of Asia
0
South Asia
0
b
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
a
(10)
0
0
0
Value of CO 2 Eq. (US $ (2000)/TCO2 Eq.)
0
10
20
30
40
50
100 150
3
7
7
7
7
7
7
7
4
13
13
13
13
13
13
13
47
128 128
128 128
128
128 128
200
7
13
128
>200
7
13
128
0
0
0.2
7
12
0.72
18
49
0.76
18
49
0.76
18
49
0.76
18
49
0.76
18
49
0.76
18
49
0.76
18
49
0.76
18
49
0.76
18
49
0.76
0
0
2
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
5
0
0
9
37
37
37
37
37
37
37
37
37
0
0
0
0.2
0
0.2
5
8
3
36
62
98
19
21
7
138
168
305
19
21
7
138
168
305
19
21
7
138
168
305
19
21
7
138
168
305
19
21
7
138
168
305
19
21
7
138
168
305
19
21
7
138
168
305
19
21
7
138
168
305
19
21
7
138
168
305
0
20
64
64
64
64
64
64
64
64
64
a
( ) – denotes a negative value
MACCs for Annex I are developed by summing up MACCs for North America, OECD-Europe, Japan, Australia
and FSU.
b
E-1
Table E-2: Marginal Abatement Cost Curves for the Coal Mining Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
7
7
7
7
7
7
20
20
20
20
20
20
206
206
206
206
206
206
150
7
20
206
200
7
20
206
>200
7
20
206
(10)
0
0
0
0
3
5
76
0
0
0.19
0
0
0
0
0
0
0.19
0
0.19
7
9
0.68
4
0
10
4
12
11
36
105
140
18
36
0.72
11
0
44
17
33
24
136
282
418
18
36
0.72
11
0
44
17
33
24
136
282
418
18
36
0.72
11
0
44
17
33
24
136
282
418
18
36
0.72
11
0
44
17
33
24
136
282
418
18
36
0.72
11
0
44
17
33
24
136
282
418
18
36
0.72
11
0
44
17
33
24
136
282
418
18
36
0.72
11
0
44
17
33
24
136
282
418
18
36
0.72
11
0
44
17
33
24
136
282
418
18
36
0.72
11
0
44
17
33
24
136
282
418
0
22
65
65
65
65
65
65
65
65
65
E-2
Table E-3: Marginal Abatement Cost Curves for the Oil Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
16
16
16
16
16
16
2
2
2
2
2
2
5
5
5
5
5
5
150
19
3
7
200
19
3
7
>200
19
3
7
(10)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.02
0
0
0
0
0
0
0.02
0
0.02
0.55
16
0.02
19
15
14
3
6
2
35
63
98
0.55
16
0.02
19
15
14
3
6
2
35
63
98
0.55
16
0.02
19
15
14
3
6
2
35
63
98
0.55
16
0.02
19
15
14
3
6
2
35
63
98
0.55
16
0.02
19
15
14
3
6
2
35
63
98
0.55
16
0.02
19
15
14
3
6
2
35
63
98
0.68
19
0.03
24
18
17
4
7
3
43
78
121
0.68
19
0.03
24
18
17
4
7
3
43
78
121
0.68
19
0.03
24
18
17
4
7
3
43
78
121
0
0
41
41
41
41
41
41
50
50
50
E-3
Table E-4: Marginal Abatement Cost Curves for the Oil Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
22
22
22
22
22
22
2
2
2
2
2
2
6
6
6
6
6
6
150
27
3
7
200
27
3
7
>200
27
3
7
(10)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.02
0
0
0
0
0
0
0.02
0
0.02
1
25
0.02
28
25
15
2
9
3
46
92
139
1
25
0.02
28
25
15
2
9
3
46
92
139
1
25
0.02
28
25
15
2
9
3
46
92
139
1
25
0.02
28
25
15
2
9
3
46
92
139
1
25
0.02
28
25
15
2
9
3
46
92
139
1
25
0.02
28
25
15
2
9
3
46
92
139
1
31
0.03
34
31
19
3
11
4
57
114
171
1
31
0.03
34
31
19
3
11
4
57
114
171
1
31
0.03
34
31
19
3
11
4
57
114
171
0
0
41
41
41
41
41
41
50
50
50
E-4
Table E-5: Marginal Abatement Cost Curves for the Natural Gas Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
(10)
0
0
0
0
4
1
0.02
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
7
9
10
10
10
10
2
2
3
3
3
3
0.61 0.62 0.73 0.74 0.74 0.77
0
0
0.28
0
0
0
0
0
0
0.28
0
0.28
2
15
0.49
16
27
28
6
5
3
53
54
107
6
109
0.49
26
39
40
10
7
11
167
91
258
7
123
0.6
37
51
46
14
10
14
193
123
316
8
143
0.77
41
57
59
14
12
16
227
137
364
8
144
0.77
44
63
64
15
12
17
236
146
382
8
152
0.77
44
63
64
15
12
17
244
146
391
8
154
0.78
44
65
66
16
12
17
248
148
397
8
154
0.78
44
65
66
16
12
17
248
149
397
8
154
0.78
44
65
66
16
12
17
248
149
397
11
199
1
56
82
84
22
15
21
321
189
510
0
11
26
32
37
39
40
40
41
41
52
150
11
3
0.77
200
11
3
0.77
>200
13
4
0.78
E-5
Table E-6: Marginal Abatement Cost Curves for the Natural Gas Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
(10)
0
0
0
0
7
3
0.15
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
13
17
18
19
19
19
5
6
7
7
7
8
4
4
5
5
5
5
0
0
0.27
0
0
0
0
0
0
0.27
0
0.27
4
18
0.46
39
47
34
6
12
11
66
115
182
10
128
0.46
64
68
50
11
19
36
204
205
409
13
144
0.57
91
90
56
16
28
45
236
275
512
14
168
0.73
102
100
72
16
32
51
277
308
585
15
169
0.73
107
110
79
18
33
54
288
328
616
15
179
0.73
107
110
79
18
33
54
298
328
626
15
181
0.74
107
113
81
18
33
54
304
332
635
15
181
0.74
108
113
81
18
34
54
304
332
636
15
181
0.74
108
113
81
18
34
54
304
333
637
20
234
1
137
144
104
25
42
69
392
421
813
0
12
27
33
38
40
41
41
41
41
53
150
19
8
5
200
19
8
5
>200
24
10
5
E-6
Table E-7: Marginal Abatement Cost Curves for the Landfills Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
1
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
1
Non-Annex I
0
World
1
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
32
35
35
37
43
47
11
11
11
11
14
14
56
62
62
62
78
82
(10)
0
0
0
0
17
3
16
0
0
3
0
0
68
0
0
0
71
0
71
11
15
6
16
9
100
30
7
3
165
69
234
19
48
7
51
26
169
94
24
12
348
201
549
21
54
7
57
29
169
116
27
12
379
222
601
21
54
7
57
29
197
116
27
12
408
222
630
22
54
7
57
29
197
116
27
12
409
224
633
27
68
7
64
33
212
131
30
15
459
263
723
8
26
61
67
70
71
81
150
47
14
82
200
47
14
82
>200
47
14
82
29
72
8
72
34
215
139
34
16
476
285
762
29
72
8
72
35
218
142
34
16
483
287
770
29
72
8
72
36
218
142
34
16
483
287
770
29
72
8
72
36
218
142
34
16
483
287
770
85
86
86
86
E-7
Table E-8: Marginal Abatement Cost Curves for the Landfills Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
59
64
64
68
79
86
21
23
23
23
27
28
123
137
137
137
172
182
(20)
0
0
0
(10)
0
0
0
0
32
5
36
0
0
0.51
0
0
0
0
0
0
0.51
0
0.51
0
0
1
0
0
75
0
0
0
76
0
76
12
18
2
22
14
110
31
11
6
179
122
300
21
57
2
70
43
187
97
37
22
386
354
740
24
64
2
78
47
187
119
41
22
420
390
810
24
64
2
78
47
218
119
41
22
451
390
842
25
64
2
78
47
218
119
41
22
452
394
846
30
81
3
89
54
235
134
47
27
510
467
977
0
6
25
61
67
69
70
80
150
86
28
182
200
86
28
182
>200
86
28
182
32
86
3
100
55
238
142
53
29
528
505
1033
32
86
3
100
57
241
146
53
29
535
507
1043
32
86
3
100
58
241
146
53
29
535
508
1043
32
86
3
100
58
241
146
53
29
535
508
1043
85
86
86
86
E-8
Table E-9: Marginal Abatement Cost Curves for the Wastewater Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
24
24
24
24
24
24
0.91 0.91 0.91 0.91 0.91 0.91
71
71
71
71
71
71
(10)
0
0
0
0
24
0.91
71
0
0
0.1
0
0
0
0
0
0
0.1
0
0.1
25
16
0.1
40
10
20
11
48
88
73
280
352
25
16
0.1
40
10
20
11
48
88
73
280
352
25
16
0.1
40
10
20
11
48
88
73
280
352
25
16
0.1
40
10
20
11
48
88
73
280
352
25
16
0.1
40
10
20
11
48
88
73
280
352
25
16
0.1
40
10
20
11
48
88
73
280
352
0
63
63
63
63
63
63
150
24
0.91
71
200
24
0.91
71
>200
24
0.91
71
25
16
0.1
40
10
20
11
48
88
73
280
352
25
16
0.1
40
10
20
11
48
88
73
280
352
25
16
0.1
40
10
20
11
48
88
73
280
352
25
16
0.1
40
10
20
11
48
88
73
280
352
63
63
63
63
E-9
Table E-10: Marginal Abatement Cost Curves for the Wastewater Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
38
38
38
38
38
38
1
1
1
1
1
1
78
78
78
78
78
78
150
38
1
78
200
38
1
78
>200
38
1
78
(10)
0
0
0
0
38
1
78
0
0
0.11
0
0
0
0
0
0
0.11
0
0.11
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
25
16
0.11
51
15
24
10
59
117
76
357
434
0
63
63
63
63
63
63
63
63
63
63
E-10
Table E-11: Marginal Abatement Cost Curves for the Nitric Acid Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
4
4
4
4
4
4
0.58 0.58 0.58 0.58 0.58 0.58
36
36
36
36
36
36
(10)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6
16
1
4
7
18
22
7
23
64
82
146
6
16
1
4
7
18
22
7
23
64
82
146
6
16
1
4
7
18
22
7
23
64
82
146
6
16
1
4
7
18
22
7
23
64
82
146
6
16
1
4
7
18
22
7
23
64
82
146
0
0
89
89
89
89
89
150
4
0.58
36
200
4
0.58
36
>200
4
0.58
36
6
16
1
4
7
18
22
7
23
64
82
146
6
16
1
4
7
18
22
7
23
64
82
146
6
16
1
4
7
18
22
7
23
64
82
146
6
16
1
4
7
18
22
7
23
64
82
146
89
89
89
89
E-11
Table E-12: Marginal Abatement Cost Curves for the Nitric Acid Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
6
6
6
6
6
6
0.53 0.53 0.53 0.53 0.53 0.53
49
49
49
49
49
49
(10)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6
14
1
5
12
22
19
9
37
63
118
181
6
14
1
5
12
22
19
9
37
63
118
181
6
14
1
5
12
22
19
9
37
63
118
181
6
14
1
5
12
22
19
9
37
63
118
181
6
14
1
5
12
22
19
9
37
63
118
181
0
0
89
89
89
89
89
150
6
0.53
49
200
6
0.53
49
>200
6
0.53
49
6
14
1
5
12
22
19
9
37
63
118
181
6
14
1
5
12
22
19
9
37
63
118
181
6
14
1
5
12
22
19
9
37
63
118
181
6
14
1
5
12
22
19
9
37
63
118
181
89
89
89
89
E-12
Table E-13: Marginal Abateme nt Cost Curves for the Adipic Acid Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
0
0
0
0
0
0
0
0
0
0
0
0
6
6
6
6
6
6
(10)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6
0
7
5
0
8
22
8
0
44
19
63
6
0
7
5
0
8
22
8
0
44
19
63
6
0
7
5
0
8
22
8
0
44
19
63
6
0
7
5
0
8
22
8
0
44
19
63
6
0
7
5
0
8
22
8
0
44
19
63
0
0
96
96
96
96
96
150
0
0
6
200
0
0
6
>200
0
0
6
6
0
7
5
0
8
22
8
0
44
19
63
6
0
7
5
0
8
22
8
0
44
19
63
6
0
7
5
0
8
22
8
0
44
19
63
6
0
7
5
0
8
22
8
0
44
19
63
96
96
96
96
E-13
Table E-14: Marginal Abatement Cost Curves for the Adipic Acid Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
0
0
0
0
0
0
0
0
0
0
0
0
9
9
9
9
9
9
(10)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
9
0
10
6
0
13
32
12
0
64
27
91
9
0
10
6
0
13
32
12
0
64
27
91
9
0
10
6
0
13
32
12
0
64
27
91
9
0
10
6
0
13
32
12
0
64
27
91
9
0
10
6
0
13
32
12
0
64
27
91
0
0
96
96
96
96
96
150
0
0
9
200
0
0
9
>200
0
0
9
9
0
10
6
0
13
32
12
0
64
27
91
9
0
10
6
0
13
32
12
0
64
27
91
9
0
10
6
0
13
32
12
0
64
27
91
9
0
10
6
0
13
32
12
0
64
27
91
96
96
96
96
E-14
Table E-15: Aggregated Marginal Abatement Cost Curves for the ODS Substitute Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
2
2
2
2
2
2
2
2
2
2
2
2
3
3
4
4
4
4
(20)
0
0
0
(10)
0
0
0
0
0.5
0.6
0.94
0
0
0
0.01
0
0
0.02
0.01
0
0.02
0.01
0.03
0
0
2
0.01
0
0.02
0.02
0.01
0
2
0.02
2
0.32
0.52
3
2
0.46
2
6
2
0.58
13
6
19
1
2
14
4
1
36
27
5
1
82
18
100
1
2
15
5
1
38
27
5
1
85
18
103
1
2
15
5
1
40
29
6
2
89
19
109
1
2
15
5
1
41
30
6
2
91
19
110
1
2
15
5
1
41
30
6
2
91
19
110
0
1
11
57
59
62
63
63
150
2
2
4
200
2
2
4
>200
2
2
4
1
2
16
5
1
41
30
6
2
91
19
111
1
2
16
5
1
41
30
6
2
92
20
111
1
2
22
6
1
57
40
7
2
124
22
146
1
2
22
6
2
58
43
7
2
129
23
152
64
64
64
64
E-15
Table E-16: Aggregated Marginal Abatement Cost Curves for the ODS Substitute Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
9
11
12
12
12
12
7
8
9
9
9
10
28
30
33
38
38
39
(20)
0
0
0
(10)
0
0
0.24
0
4
4
11
0.05
0
0
0.19
0
0
0.28
0.26
0
0.33
0.45
0.78
0.05
0.08
10
0.19
0.05
0.28
0.28
0.26
0
11
0.74
11
2
4
18
12
3
29
39
16
6
96
51
147
6
10
40
22
6
110
88
31
10
260
106
366
6
10
44
23
6
117
88
32
10
273
112
385
7
12
47
26
6
134
100
36
13
309
126
435
7
12
48
26
6
139
104
36
13
319
131
450
7
12
49
26
7
139
104
36
13
320
132
451
0
2
21
53
56
63
65
65
150
12
10
39
200
13
10
41
>200
13
11
43
8
13
51
30
7
147
109
37
14
338
139
477
8
13
51
30
7
147
109
41
14
339
143
482
9
14
54
32
8
154
117
44
15
358
152
510
9
15
57
33
8
161
130
46
15
384
159
542
69
69
70
70
E-16
Table E-17: Aggregated Marginal Abatement Cost Curves for the HCFC-22 Production Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
(10)
0
0
0
0
0
0
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
0
0
0
0
0
0
0
0
0
0
0
0
4
4
4
4
4
4
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0.35
12
2
0
28
27
2
0
67
9
76
0
0
93
93
93
93
93
93
93
93
93
150
0
0
4
200
0
0
4
>200
0
0
4
E-17
Table E-18: Aggregated Marginal Abatement Cost Curves for the HCFC-22 Production Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
(10)
0
0
0
0
0
0
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
0
0
0
0
0
0
0
0
0
0
0
0
7
7
7
7
7
7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0.56
2
4
0
4
4
4
0
11
14
26
0
0
88
88
88
88
88
88
88
88
88
150
0
0
7
200
0
0
7
>200
0
0
7
E-18
Table E-19: Aggregated Marginal Abatement Cost Curves for the Aluminum Production Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
(20)
0.22
0.48
0
(10)
0.92
0.48
0.06
0
2
0.48
1
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
2
2
2
2
2
2
0.48 0.48 0.48 0.48 0.48 0.48
1
1
1
1
2
2
0
0
0
0.16
0.02
0.17
0
0
0
0.65
0.4
1
0.1
0.06
0
1
0.02
0.17
0
0.15
0.05
0.81
2
3
0.64
0.36
0
1
0.02
2
0
0.15
0.17
3
5
8
0.73
4
0.01
2
0.02
3
2
0.18
0.21
10
5
15
0.73
4
0.01
2
0.02
3
2
0.18
0.21
10
5
15
0.73
4
0.01
2
0.02
3
2
0.18
0.21
10
5
15
0.73
4
0.01
2
0.02
3
2
0.18
0.21
10
5
15
0.75
5
0.01
2
0.02
3
2
0.18
0.24
11
6
17
0.75
5
0.01
2
0.02
3
3
0.18
0.26
12
6
18
0.75
5
0.01
2
0.02
3
3
0.18
0.26
12
6
18
0.75
5
0.01
2
0.02
3
3
0.18
0.26
12
6
18
0.75
5
0.01
2
0.02
3
3
0.18
0.26
12
6
18
2
5
13
25
25
25
26
29
30
30
30
30
150
2
0.48
2
200
2
0.48
2
>200
2
0.48
2
E-19
Table E-20: Aggregated Marginal Abatement Cost Curves for the Aluminum Production Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
(20)
0.41
0.55
0
(10)
2
0.55
0.11
0
3
0.55
2
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
3
3
3
4
4
4
0.55 0.55 0.55 0.55 0.55 0.55
3
3
3
3
3
3
0
0
0
0.28
0.35
0.24
0
0
0
0.79
1
2
0.13
0.08
0
2
0.35
0.24
0
0.22
0.09
1
5
6
0.85
0.5
0
2
0.35
3
0
0.22
0.35
5
9
14
0.97
4
0.02
3
0.35
4
3
0.26
0.41
12
10
22
0.97
4
0.02
3
0.35
4
3
0.26
0.41
12
10
22
0.97
4
0.02
3
0.35
4
3
0.26
0.41
13
10
23
0.97
4
0.02
3
0.35
4
3
0.26
0.41
13
10
23
1
5
0.02
3
0.35
5
3
0.26
0.48
15
11
25
1
6
0.04
3
0.35
5
3
0.26
0.51
15
11
26
1
6
0.04
3
0.35
5
3
0.26
0.51
15
11
26
1
6
0.04
3
0.35
5
3
0.26
0.51
15
11
26
1
6
0.04
3
0.35
5
3
0.26
0.51
15
11
26
2
6
14
24
24
24
25
27
28
28
28
28
150
4
0.55
3
200
4
0.55
3
>200
4
0.55
3
E-20
Table E-21: Aggregated Marginal Abatement Cost Curves for the for the SF6 Sources
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
No options to abate SF 6 emissions were available in 2000
E-21
Table E-22: Aggregated Marginal Abatement Cost Curves for the SF6 Sources
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
(10)
0
0
0
0
0
0
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
0.58 0.58 0.58 0.58 0.58 0.58
6
6
6
6
6
6
19
19
19
19
19
19
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0.56
8
15
3
4
28
18
1
0.69
76
28
104
0
0
82
82
82
82
82
82
82
82
82
150
0.58
6
19
200
0.58
6
19
>200
0.58
6
19
E-22
Table E-23: Aggregated Marginal Abatement Cost Curves for the for the Semiconductors Sector
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
(10)
0
0
0
0
0.04
0.05
0.48
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
0.04 0.06 0.11 0.12 0.12 0.12
0.05 0.06 0.12 0.14 0.14 0.14
0.48 0.63
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0.04
0.04
3
0.04
0.04
2
2
2
0.24
7
3
10
0.04
0.04
3
0.04
0.04
2
2
2
0.24
7
3
10
0.06
0.06
4
0.06
0.06
3
2
2
0.31
10
3
13
0.11
0.11
8
0.11
0.11
6
4
4
0.59
18
6
24
0.12
0.12
9
0.12
0.12
6
5
5
0.67
21
7
28
0.12
0.12
9
0.12
0.12
6
5
5
0.67
21
7
28
0.12
0.12
9
0.12
0.12
6
5
5
0.67
21
7
28
0.12
0.12
9
0.12
0.12
6
5
5
0.67
21
7
28
0.12
0.12
9
0.12
0.12
6
5
5
0.67
21
7
28
0.12
0.12
9
0.12
0.12
6
5
5
0.67
21
7
28
0
36
36
46
88
100
100
100
100
100
100
150
0.12
0.14
1
200
0.12
0.14
1
>200
0.12
0.14
1
E-23
Table E-24: Aggregated Marginal Abatement Cost Curves for the Semiconductors Sector
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America 0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
(10)
0
0
0
0
0.11
0.13
1
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100
0.11 0.12 0.22 0.25 0.25 0.25
0.13 0.14 0.25 0.27 0.27 0.27
1
1
2
3
3
3
0
0
0
0
0
0
0
0
0
0
0
0
0.11
0.11
8
0.11
0.11
6
4
4
0.62
19
7
25
0.11
0.11
8
0.11
0.11
6
4
4
0.62
19
7
25
0.12
0.12
9
0.12
0.12
6
5
5
0.66
20
7
27
0.22
0.22
16
0.22
0.22
11
8
8
1
37
13
49
0.25
0.25
18
0.25
0.25
13
9
9
1
41
14
55
0.25
0.25
18
0.25
0.25
13
9
9
1
41
14
55
0.25
0.25
18
0.25
0.25
13
9
9
1
41
14
55
0.25
0.25
18
0.25
0.25
13
9
9
1
41
14
55
0.25
0.25
18
0.25
0.25
13
9
9
1
41
14
55
0.25
0.25
18
0.25
0.25
13
9
9
1
41
14
55
0
46
46
50
90
100
100
100
100
100
100
150
0.25
0.27
3
200
0.25
0.27
3
>200
0.25
0.27
3
E-24
Table E-25: Combined Methane MACCs by Region. Year: 2000
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
1
Latin America
0
Middle East
0
North America
0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
1
Non-Annex I
0
World
1
World (% of
baseline)
0
(10)
0
0
0
0
48
8
134
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100 150
86
91
91
94
100
104
108
29
30
31
31
33
33
34
260
266
266
266
283
287
288
0
0
4
0
0
68
0
0
0
72
0
72
44
58
8
74
46
156
52
67
97
326
465
791
68
238
8
141
90
280
137
106
120
760
803
1563
72
258
8
158
105
285
164
112
122
818
855
1673
72
278
9
163
111
327
164
113
124
880
869
1749
74
279
9
165
117
332
165
114
125
890
881
1770
79
302
9
172
121
347
179
117
128
948
920
1869
80
308
9
180
123
352
188
121
129
970
945
1914
80
311
9
185
128
357
192
123
129
984
961
1946
80
311
9
185
128
357
192
123
129
984
962
1946
83
356
9
197
146
375
198
126
134
1057
1001
2058
2
25
50
53
55
56
59
61
62
62
65
200
108
34
288
>200
110
35
288
E-25
Table E-26: Combined Methane MACCs by Region. Year: 2020
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
(20)
0
0
0
(10)
0
0
0
0
79
15
189
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100 150
139
148
149
154
165
172
177
50
53
53
54
58
59
60
417
431
432
432
467
477
479
0
0
0.51
0
0
0
0
0
0
0.51
0
0.51
0
0
2
0
0
75
0
0
0
77
0
77
47
60
4
115
77
179
52
94
144
357
699
1056
76
262
4
224
151
320
137
157
203
849
1291
2139
81
286
4
259
177
327
165
170
212
915
1397
2312
81
309
4
270
187
374
165
174
217
987
1430
2417
84
310
4
276
197
381
167
175
220
999
1453
2453
89
337
4
286
203
397
181
181
225
1067
1527
2594
90
344
4
297
208
403
190
187
227
1090
1568
2659
91
350
4
304
216
409
195
189
228
1108
1593
2702
91
350
4
305
216
409
195
189
228
1108
1594
2703
96
403
5
333
247
431
201
197
244
1197
1682
2879
0
2
24
48
52
54
55
58
60
61
61
65
200
177
60
479
>200
181
62
479
E-26
Table E-27. Combined Nitrous Oxide MACCs by Region. Year: 2000
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100 150
4
4
4
4
4
4
4
0.58 0.58 0.58 0.58 0.58 0.58 0.58
43
43
43
43
43
43
43
(20)
0
0
0
(10)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
12
16
9
9
7
27
44
16
23
108
101
209
12
16
9
9
7
27
44
16
23
108
101
209
12
16
9
9
7
27
44
16
23
108
101
209
12
16
9
9
7
27
44
16
23
108
101
209
12
16
9
9
7
27
44
16
23
108
101
209
12
16
9
9
7
27
44
16
23
108
101
209
0
0
0
91
91
91
91
91
91
200
4
0.58
43
>200
4
0.58
43
12
16
9
9
7
27
44
16
23
108
101
209
12
16
9
9
7
27
44
16
23
108
101
209
12
16
9
9
7
27
44
16
23
108
101
209
91
91
91
E-27
Table E-28. Combined Nitrous Oxide MACCs by Region. Year: 2020
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
(20)
Africa
0
Australia
0
China
0
Eastern and
Central Europe
0
FSU
0
Japan
0
Latin America
0
Middle East
0
North America
0
OECD-Europe
0
Rest of Asia
0
South Asia
0
Annex I
0
Non-Annex I
0
World
0
World (% of
baseline)
0
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100 150
6
6
6
6
6
6
6
0.53 0.53 0.53 0.53 0.53 0.53 0.53
58
58
58
58
58
58
58
(10)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
15
14
11
11
12
35
51
21
37
127
145
272
15
14
11
11
12
35
51
21
37
127
145
272
15
14
11
11
12
35
51
21
37
127
145
272
15
14
11
11
12
35
51
21
37
127
145
272
15
14
11
11
12
35
51
21
37
127
145
272
15
14
11
11
12
35
51
21
37
127
145
272
0
0
91
91
91
91
91
91
200
6
0.53
58
>200
6
0.53
58
15
14
11
11
12
35
51
21
37
127
145
272
15
14
11
11
12
35
51
21
37
127
145
272
15
14
11
11
12
35
51
21
37
127
145
272
91
91
91
E-28
Table E-29. Combined Industrial Gases MACCs by Region. Year: 2000
Regional and Global MACCs for Year 2000; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100 150
4
4
4
4
4
4
4
2
2
2
2
2
2
2
9
10
10
11
11
11
11
(20)
0.22
0.48
0
(10)
0.92
0.48
0.06
0
2
1
3
0
0
0
0.16
0.02
0.17
0.02
0.01
0
0.67
0.41
1
0.1
0.06
2
1
0.02
0.18
0.02
0.16
0.05
3
2
6
1
0.92
7
3
0.53
6
8
4
1
23
13
37
2
6
30
9
1
69
58
10
2
167
34
201
2
6
32
9
1
71
58
10
2
171
36
207
2
6
36
9
1
76
63
13
2
185
40
225
2
6
37
9
1
78
64
13
3
189
41
230
2
7
37
9
1
78
64
13
3
191
41
232
2
7
37
9
1
78
64
13
3
191
41
233
0
1
9
49
50
55
56
56
57
200
4
3
11
>200
4
3
12
2
7
37
9
1
78
64
13
3
191
42
233
2
8
43
10
2
94
74
14
3
224
44
268
2
8
44
10
2
95
77
14
3
229
45
274
57
57
57
E-29
Table E-30. Combined Industrial Gases MACCs by Region. Year: 2020
Regional and Global MACCs for Year 2020; Discount Rate – 10% (MTCO2 Equivalent/year)
Region
Africa
Australia
China
Eastern and
Central Europe
FSU
Japan
Latin America
Middle East
North America
OECD-Europe
Rest of Asia
South Asia
Annex I
Non-Annex I
World
World (% of
baseline)
Value of CO 2 Eq. (US $ (2000)/TCO 2 Eq.)
10
20
30
40
50
100 150
13
15
16
16
16
16
16
14
14
16
16
16
17
17
57
59
64
69
69
71
71
(20)
0.41
0.55
0
(10)
2
0.55
0.36
0
7
4
15
0.05
0
0
0.47
0.35
0.24
0.28
0.26
0
1
1
3
0.19
0.16
10
2
0.39
0.53
0.28
0.47
0.09
12
5
17
3
5
27
14
3
38
43
21
6
120
67
186
8
22
66
32
10
152
117
40
12
379
164
543
8
23
70
33
10
159
118
42
12
393
171
564
9
24
81
36
11
182
134
49
15
446
191
636
9
24
83
36
11
188
139
50
16
460
198
657
9
25
84
36
12
189
139
50
16
462
199
661
9
27
87
40
12
197
144
52
16
481
207
688
0
2
19
55
57
64
66
66
69
200
17
17
73
>200
18
18
75
10
27
87
40
12
197
144
56
16
482
211
693
11
28
89
42
12
204
152
58
17
501
220
721
11
29
93
43
13
211
166
60
18
527
226
753
69
70
70
E-30