Post on 13-Jun-2020
Ministry of Environment and Physical Planning The Government of the Republic of Macedonia
CLIMATE CHANGE MITIGATION ANALYSES
ENERGY SECTOR
THIRD NATIONAL COMMUNICATION TO UNFCCC
Draft Report – Working version
Reasearch Center for Energy, Informatics and Materials, Macedonia Academy of Sciences and Arts
(ICEIM-MANU)
30 August, 2013
II
This document presents the climate change mitigation potential in the energy sector and further proposes
mitigation measures and estimates their feasibility, CO2 reduction and possible co-benefits. This document
provides important guidance for policy-makers in developing adaptation strategies and further strengthens
the dialogue, information exchange and cooperation among all the relevant stakeholders including
governmental, non-governmental, academic, and private sectors.
This paper has been produced with the technical support of the United Nations Development Programme
and financial support by Global Environment Facility.
III
IV
TABLE OF CONTENTS
EXECUTIVE SUMMARY 1
1. INTRODUCTION 2
2. BASELINE SCENARIO 5
2.1. DEMAND PROJECTIONS 5
2.2. FINAL ENERGY CONSUMPTION 6
2.3. POWER SECTOR – INSTALLED CAPACITY AND OUTPUT 8
2.4. PRIMARY ENERGY SUPPLY 11
2.5. CO2 EMISSIONS 12
2.6. SUMMARY 13
3. MITIGATION SCENARIOS 15
3.1. GROUP 1: EU MITIGATION SCENARIOS 15
3.1.1. FINAL ENERGY CONSUMPTION 16
3.1.2. POWER SECTOR – INSTALLED CAPACITY AND OUTPUT 16
3.1.3. PRIMARY ENERGY SUPPLY 17
3.1.4. TOTAL SYSTEM COSTS 17
3.1.5. CO2 EMISSIONS 18
3.1.6. SUMMARY 19
3.2. GROUP 2: QERLC MITIGATION SCEANRIOS 20
3.2.1. FINAL ENERGY CONSUMPTION 21
3.2.2. POWER SECTOR – INSTALLED CAPACITY AND OUTPUT 21
3.2.3. TOTAL SYSTEM COSTS 22
3.2.4. PRIMARY ENERGY SUPPLY 23
V
3.2.5. CO2 EMISSIONS 23
3.2.6. SUMMARY 24
3.3. GROUP 3: BAU DEVIATION MITIGATION SCENARIOS 25
3.3.1. FINAL ENERGY CONSUMPTION 25
3.3.2. POWER SECTOR – INSTALLED CAPACITY AND OUTPUT 26
3.3.3. PRIMARY ENERGY SUPPLY 27
3.3.4. TOTAL SYSTEM COSTS 28
3.3.5. CO2 EMISSIONS 29
3.3.6. SUMMARY 30
3.4. COMPARATIVE ASSESSMENT 30
4. CLIMATE CHANGE MITIGATION ACTION PLAN 31
APPENDIX I: DATA SOURCES AND KEY ASSUMPTIONS 32
APPENDIX II: METHODOLOGY – MARKAL MODEL DESCRIPTION 38
VI
List of Figures
Figure 1. Climate Change Mitigation Workflow ............................................................................................... 3
Figure 2. Electricity Load Profile ........................................................................................................................... 6
Figure 3. Final Energy Consumption by Fuel Type under Baseline Scenario (ktoe) ................................. 7
Figure 4. Final Energy Consumption by Sector under Baseline scenario (ktoe) ....................................... 8
Figure 5. Installed Capacity of Existing and New Build Power Plants under Baseline Scenario (MW) 9
Figure 6. Total Investment Cost of New Power Plants and Gas Pipe line under Baseline Scenario
(MEuros) ................................................................................................................................................................... 10
Figure 7. Electricity Generation and Import under Baseline Scenario (GWh) ........................................ 11
Figure 8. Primary Energy Supply under Baseline Scenario (ktoe) ............................................................... 12
Figure 9. CO2 Emissions under Baseline Scenario (kt) .................................................................................. 13
Figure 10. Definition of EU mitigation scenarios ............................................................................................. 15
Figure 11. Final Energy Consumption by Fuel Type under EU mitigation scenarios (ktoe) ................ 16
Figure 12. Installed Capacity of Existing and New Build Power Plants under EU mitigation scenarios
(MW) ......................................................................................................................................................................... 16
Figure 13. Electricity Generation and Import under EU mitigation scenarios (GWh) ......................... 17
Figure 14. Primary Energy Supply under EU mitigation scenarios (ktoe) ................................................ 17
Figure 15. Total system costs for the Baseline scenario and EU mitigation scenarios (2012Meuros)18
Figure 16. CO2 Emissions by sectors under EU mitigation scenarios (kt) ................................................ 18
Figure 17. Total CO2 Emissions under Baseline scenario and EU mitigation scenarios (kt) ................ 19
Figure 18. Definition of QERLC mitigation scenarios .................................................................................... 20
Figure 19. Final Energy Consumption by Fuel Type under QERLC mitigation scenarios (ktoe) ........ 21
Figure 20. Installed Capacity of Existing and New Build Power Plants under QERLC mitigation
scenarios (MW) ....................................................................................................................................................... 21
Figure 21. Electricity Generation and Import under QERLC mitigation scenarios (GWh) ................. 22
Figure 22. Total system costs for the Baseline scenario and QERLC mitigation scenarios
(2012Meuros) .......................................................................................................................................................... 22
Figure 23. Primary Energy Supply under QERLC mitigation scenarios (ktoe) ......................................... 23
Figure 24. CO2 Emissions by sectors under the QERLC mitigation scenarios (kt) ................................ 23
VII
Figure 25. Total CO2 Emissions under Baseline scenario and QERLC mitigation scenarios (kt) ....... 24
Figure 26. Definition of BAU Deviation Mitigation Scenarios ...................................................................... 25
Figure 27. Final Energy Consumption by Fuel Type under BAU Deviation Mitigation Scenarios (ktoe)
..................................................................................................................................................................................... 26
Figure 28. Installed Capacity of Existing and New Build Power Plants under BAU Deviation Mitigation
Scenarios (MW) ...................................................................................................................................................... 26
Figure 29. Electricity Generation and Import under BAU Deviation Mitigation Scenarios (GWh) ... 27
Figure 30. Primary Energy Supply under BAU Deviation Mitigation Scenarios (ktoe) ........................... 28
Figure 31. Total System Costs under Baseline and BAU Deviation Mitigation Scenarios (2012 M
Euros) ........................................................................................................................................................................ 28
Figure 32. CO2 Emissions under BAU Deviation Mitigation Scenarios (kt) ............................................. 29
Figure 33. Total CO2 Emissions under Baseline and BAU Deviation Mitigation Scenarios (kt) .......... 29
Figure 34. MARKAL Building Blocks .................................................................................................................. 38
VIII
List of Tables
Table 1. Key Demand Drivers in Baseline Scenario ......................................................................................... 5
Table 2. Additional Power Plant Capacity by Fuel Type under Baseline Scenario (MW) ....................... 9
Table 3. CO2 Emissions by Sectors under Baseline Scenario (kt) .............................................................. 13
Table 4. Key Indicators for Baseline Scenario ................................................................................................. 13
Table 5. Definition of EU mitigation scenarios ................................................................................................ 15
Table 6. Key Indicators for the Baseline Scenario and EU mitigation scenarios ..................................... 19
Table 7. Definition of QERLC Mitigation Scenarios ....................................................................................... 20
Table 8. Key Indicators for the QERLC mitigation scenarios ...................................................................... 24
Table 9. Definition of BAU Deviation Mitigation Scenarios ......................................................................... 25
Table 10. Investment Costs under BAU Deviation Mitigation Scenarios (MEuros) ............................... 26
Table 11. Total CO2 Emissions under Baseline and BAU Deviation Mitigation Scenarios (kt) ........... 29
Table 12. Key Indicators for BAU Deviation Mitigation Scenarios ............................................................. 30
Table 13. Key Data Sources ................................................................................................................................. 32
Table 14. Existing Power plants .......................................................................................................................... 33
Table 15. Characterization of Key Power Plant Options ............................................................................. 34
Table 16. Investment costs for revitalization of TPP Bitola.......................................................................... 35
Table 17. Investment costs for revitalization of TPP Oslomej .................................................................... 35
Table 18. Key Constraints in the Baseline Scenario ....................................................................................... 36
Table 19. Energy Price Trajectory Assumptions (Euro/GJ) .......................................................................... 36
ACRONYMS
{The list will be updated accordingly}
ICEIM-MANU Research Center for Energy, Informatics and Materials Macedonian Academy of Sciences and Arts
MARKAL MARKet ALlocation
EE Energy efficiency
TPP Thermal power plant
HPP Hydro power plant
CO2 Carbon dioxide
FiT Feed in tariff
RES Renewable energy source
PV Photovoltaic
CHP Combined heat and power
WEO World Energy Outlook
O&M Operation and maintenance
GHG Greenhouse gases
HH Household
NR Non-residential
UNITS
MW Megawatt
GW Gigawatt
MWh Megawatt hour
GWh Gigawatt hour
GJ Gigajoule
MEuro Million Euros
t tonne
kt kilotonne
Mt Mega (Million) tonne
ktoe thousand tons of oil equivalent
1
EXECUTIVE SUMMARY
2
1. INTRODUCTION
This assignment is a part of the project “Third National Communication (TNC) to the United Nations
Framework Convention on Climate Change (UNFCCC), implemented by UNDP and the Ministry of
Environment and Physical Planning (MoEPP), with the aim to strengthen the information base,
analytical and institutional capacity of the key national institutions to integrate climate change
priorities into country development strategies and relevant sector programs.
Climate Change Mitigation is one of the key thematic areas of the TNC which is built upon the
respective analyses conducted under Second National Communication, but also is accountable for
the developments meanwhile, particularly for the specific position of the Republic of Macedonia
(RM) under UNFCCC and (European Union) EU candidate status. In case that RM enters EU by 2020,
it will also start implementing EU mitigation policies and measures, such as increase of share of
renewables, participation in emissions trading system, obligatory buildings and equipment standards,
labelling and certification of equipment and buildings, phasing out of inefficient technologies as
incandescent light bulbs and retiring or obligatory retrofitting of inefficient plants. The sum of the
measures, together with EU effort sharing scheme, will allow for achieving necessary emission
reduction. In case that RM does not enter EU by 2020, it will still continue to participate in Energy
Community, with similar targets in renewables, energy efficiency and phasing out of inefficient
plants. The country will probably choose to continue transposition of other directives, but with
slower pace. It will then have choice between joining Annex I and offering Quantified Emission
Limitation or Reduction Commitment (QELRC) type of target, or to stay in the position of developing
non-Annex I country and offer target in form of baseline deviation. In all cases similar type of policies
and measures will be implemented, but with different speed and intensity.
Accordingly, the mitigation analysis under TNC addresses the following questions:
What the country can expect in terms of possible greenhouse gases (GHG) emissions
limitation/reduction targets in view of the ongoing UNFCCC negotiations about future
climate regime and of the EU candidate status?
What measures/activities can be undertaken in order to achieve the GHG emissions
limitation/reduction?
How costly would be the different levels of ambition for GHG emissions
limitation/reduction?
3
What is the mitigation potential of non-energy sectors?
How to involve as many as possible relevant stakeholders and set the priorities applying
participatory approach?
How to diffuse the climate change mitigation in the relevant sectoral policies and ensure
joint and cooperative action?
Answering of these questions has required involvement of different performers, with specific roles
and assignments, but acting in partnership with one another. The organization of work with the
main performers and outcomes is schematically presented in Figure 1.
Figure 1. Climate Change Mitigation Workflow
4
Besides an intensive analytical work within and across different sectors, the mitigation analysis has
also included participatory work with a number of relevant stakeholders, particularly when it has
come to evaluation and prioritization of the measures in the mitigation action plans. Moreover, not
less important is the capacity building and knowledge transfer component realized through
engagement of chief technical advisor, international expert and expert support for the modeling
work in non-energy sectors.
This report presents the work of the Research Center for Energy, Informatics and Materials of the
Macedonian Academy of Sciences and Arts (ICEIM-MANU) who has been assigned a task to conduct
a comprehensive assessment of climate change mitigation potential of the national energy sector by
making use of MARKAL energy system model (MARKAL modelling task). Important to note is that
“national energy sector” should be considered in a wider sense, since the MARKAL model covers the
emissions which are associated with fuel combustion, incorporating thus energy supply and demand
sectors - households, industry (fuel combustion emissions), transport, commercial and services and
agriculture (fuel combustion emissions).
Hence, ICEIM-MANU team has developed a baseline scenario and three groups of mitigation
scenarios until 2050, with emissions limitation/reduction targets as defined by the international
expert. The national mitigation scenarios have included measures and activities from the sectoral
portfolios delivered by the international expert, which can be applied and modelled in Macedonian
conditions. The work of ICEIM-MANU has also included a sensitivity analysis and a comparative
assessment of the economic aspects of different types and levels of emissions limitation/reduction
targets corresponding to different level of ambition of the national policies. At last, based on the
analytical results, the nationally appropriate mitigation measures and actions are summarized in a
mitigation action plan for the energy sector.
As a final point, it should be emphasized that the findings of this study should have an indicative
character, to show “where we are and where to go” with regards to climate change mitigation.
Given the dynamics of relevant developments at national and at international level, as well as high
level of uncertainties associated with the UNFCCC process and the EU accession, this should be
rather seen as a building of analytical capacities in the country to generate a solid base for well-
informed and wise policy-making and for devising the national position in the international and
European negotiation processes.
5
2. BASELINE SCENARIO
{The numbers in text will be updated according to the latest results}
To assess the impact of different climate change mitigation policies and programs on the evolution
of the energy system in Macedonia, a Baseline scenario was developed, taking into account specific
characteristics of the national energy system, such as existing technology stock, all possible new
technology options, resource availability and import options, and near-term policy interventions. For
this purpose all available national data sources (State Statistical Office, National energy balances,
etc.) as well as some international databases (e.g., International Energy Agency) were utilized. The
full list of information sources and key assumption for the Baseline scenario is provided in Appendix I.
2.1. DEMAND PROJECTIONS
The energy demand projections for the Baseline scenario over the considered planning horizon
(2011 – 2050) are based on the exogenous economic and demographic projections (drivers) and
assumptions regarding each service demand’s sensitivity to changes in the assumed driver. The
model must satisfy these demands in each time period, by using the existing capacity and/or by
implementing new capacity for end-use technologies. Table 1 provides key demand drivers, GDP and
population growth rates, for the Baseline scenario and how their changes reflect on the future
energy demands in all sectors by end-use services.
Table 1. Key Demand Drivers in Baseline Scenario
Category Assumption
GDP growth rate (annual average) 3.21% (2011-2029), 3.26% (2029-2050)
Sectoral growth rates*
Residential 1.58%
Commercial 2.30%
Industry 1.62%
Agriculture 2.80%
Population growth rate (annual average)
-0.24%
* Overall growth rate for useful energy based on projections for the different energy services in each sector,
during the period 2011 – 2050
6
Another key issue for development of the Baseline scenario is the electricity load profile of the
country, which is necessary to better allocate the seasonal energy demands. The electricity load
profile for 2012, which was used in the model is shown on Figure 2
Figure 2. Electricity Load Profile
2.2. FINAL ENERGY CONSUMPTION
Under the Baseline scenario, energy consumption is projected to grow by 30% in terms of final
energy by 2029, and by 80% till 2050. The most significant share in final energy consumption have
diesel and electricity use, as well as the natural gas, available through import (Figure 3). The diesel
consumption will increase in for almost 190% between 2011 and 2050, mainly due the increased
utilization in transport sector. The electricity consumption will slowly increase during the planning
period with overall growth of 28%. The coal consumption will also increase with overall growth of
128%, mainly in the industry. Gas consumption increases significantly, especially after 2030 mainly in
commercial and industrial sectors. The penetration in residential sector is limited, due to large
investment requirements in distribution infrastructure.
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Figure 3. Final Energy Consumption by Fuel Type under Baseline Scenario (ktoe)
*SOL-Solar; GEO – Geothermal; HFO – Heavy fuel oil; KER – Kerosene; AVF – Aviation fuel;
LPG - Liquefied petroleum gas
There is significant uncertainty around gas prices, which has an important impact on gas
consumption in future years. The current prices, used as the base price in the model, are projected
forward based on IEA WEO assumptions. However, current prices are very high due to the low levels
of import via the pipeline. If import levels were to increase (as predicted under the Baseline
scenario), the relative gas prices under the contract would decrease. The modeling of this issue
needs further consideration, having in mind the new connection of the country to the “South Stream”
gas pipeline.
The highest increase of the final energy consumption over the period 2011 -2050 (around 147%) can
be noticed in the transport and commercial sectors (Figure 4), followed by Industrial sector and
agriculture, while in the residential sector the final energy consumption will change relatively slowly.
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Oil (HFO, KER, AVF)
LPG
Heat
Gasoline
Gas
Electricity
Diesel
Coal
Bunker Fuel
Biomass
Biofuels
8
Figure 4. Final Energy Consumption by Sector under Baseline scenario (ktoe)
2.3. POWER SECTOR – INSTALLED CAPACITY AND OUTPUT
To address the electricity demand which is almost 30% of the total final consumption in 2029 and 25%
in 2050, certain investments in new generation capacities will take place. Total installed capacity
used for electricity generation during the period 2011 - 2050 is shown on Figure 5. By 2017 the
existing coal power plants will be revitalized to satisfy the requirements under the LCP Directive1 and
will be available for operation until 2032, at least the three units of TPP Bitola (with around 600 MW).
Existing gas-fired power plants will also be available until 2032 with total capacity of 290 MW, while
existing hydro power plant will available during the whole planning period with the same capacity of
579 MW.
1 Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants (the LCP Directive) (http://ec.europa.eu/environment/air/pollutants/stationary/lcp/legislation.htm)
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Transportation
Residential
Industrial
Commercial
Agriculture
9
Figure 5. Installed Capacity of Existing and New Build Power Plants under Baseline Scenario (MW)
New power generation capacity additions between 2014 and 2050 are shown in Table 2. Coal power
plants remain one of the main producers of electricity with new installed capacity of 600MW
between 2032 and 2050. The other investments are in hydropower, with cumulative additional
capacity of 363 MW by 2050, or three new large hydro power plants (HPP Sv. Petka, HPP Boskov
Most and HPP Lukovo Pole) and small HPPs. Also, in 2035 two large and one small new gas power
plants will be built, with cumulative installed capacity of 565 MW. Incentivized by a feed-in tariffs,
wind and solar power plants also make an important contribution with 160 MW.
Table 2. Additional Power Plant Capacity by Fuel Type under Baseline Scenario (MW)
Plant Type 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 2047 2050
Coal 0 0 0 0 200 500 500 700 700 700 700 700 700
Gas 0 0 130 130 130 130 130 790 920 920 920 920 920
Hydro 67 221 250 278 306 334 363 363 363 363 363 363 363
Wind 36 65 100 100 150 150 150 150 150 150 150 150 289
Solar 4 4 4 4 4 4 25 25 25 25 25 25 25
Total New Capacity
107 290 484 512 790 1118 1168 2028 2158 2158 2158 2158 2296
% of Installed Capacity
5.6% 15.3% 24.2% 25.2% 34.2% 42.4% 43.5% 77.8% 78.8% 78.8% 78.8% 78.8% 79.9%
Figure 6 shows the capital investment requirements associated with the new capacity added
in each three year period.
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New solar
New wind
New hydro PP
Existing hydro PP
Existing oil-fired PP
New gas-fired PP
Existing gas-fired PP
New coal PP
Existing coal PP
10
Figure 6. Total Investment Cost of New Power Plants and Gas Pipe line under Baseline Scenario (MEuros)
* Investment levels are not annual but cumulative for each three-year period
The investment expenditures for new power plants and devices are incurred as demand rises and
existing power plants and devices reach the end of their operational lifetimes. Under the Baseline
scenario, to add the 1852 MW of new generation capacity by 2050, a total investment of 3045 €
million is required including 8 € millions for new transmission and distribution networks. Significant
level of investment of around 1000 € million can be noticed in 2035 when the old power plant are
retired and new additional capacities (mainly gas-fired and coal PP) are built. Also, additional
investment in new gas pipeline of 156 € millions is needed.
From the generation output of the considered power plants (Figure 7), it can be noticed that the coal
PP dominate. The existing coal PP (only revitalized TPP Bitola) will work almost with the full capacity
until 2032. The existing gas power plant will be also utilized by 2032, but not with the full capacity,
because of the new coal power plants, starting in 2026, which are cheaper to operate than the
existing gas-fired CHPs with full capacity. In 2035, when the existing coal and gas-fired PP are retired,
the new gas-fired PP will take significant part in electricity generation by 2050, together with the new
coal power plant. The other generation capacities (hydro, wind and solar PP), will operate mostly
with full capacity. Also, a small amount of electricity import can be noticed, which remains almost at
the same level over the planning period.
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Distrib. losses red.
Gas Pipeline
T&D Lines
Solar PP
Wind PP
Hydro PP
Gas-fired PP
Coal PP
11
Figure 7. Electricity Generation and Import under Baseline Scenario (GWh)
2.4. PRIMARY ENERGY SUPPLY
Primary energy supply in 2029 is projected to be 2366 ktoe and 3821 ktoe in 2050, increasing from
2006 levels by 40% and 126%, respectively.
In addition to the significant growth in primary energy supply, the supply becomes more diverse. As
shown in Figure 8, the share of imported natural gas increases over the planning period, accounting
for 17% of total supply in 2029 and 30% in 2050. The growth in transport demand is reflected in the
consumption of oil products (imported) and crude oil, increasing their share in the primary energy
supply to 6% in 2029 and 8% in 2050 for oil products and 47% in 2029 and 33% in 2050 for crude oil.
The share of coal as primary energy source remains at the same level of 10% by 2029, but with the
construction of new coal power plants it will increase to 14% by 2050. The contribution of renewable
energy sources (excluding biomass) to total primary energy during this period grows from 8% in
2011 to 10% in 2029, and back to around 8% in 2050, but in absolute values the primary energy
supply from RES grows by 99% over the period 2011-2050. This is primarily due to additional wind
capacity in the power sector. The biomass contribution by 2029 is almost the same at around 10%,
even decreases in 2050 to 6%.
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Existing coal PP
12
Figure 8. Primary Energy Supply under Baseline Scenario (ktoe)
The total discounted system cost for realization of the Baseline Scenario is estimated to be 49418 €
millions.
2.5. CO2 EMISSIONS
CO2 emissions are projected to change from 9.5 Mt in 2011 to 12 Mt in 2029 and 2050, or by 29%,
with predominant share of power generation (Figure 9). The decrease in 2035 is a result of the
retirement of the existing coal and gas power plant units. The emissions will rise again when new
coal power plants enter into the system (in 2035). Also, a significant growth of the CO2 emission
form the other sectors can be noticed, particularly from transport and commercial sectors. As a
result of the growing number of vehicle fleet and increased consumption of petroleum products the
CO2 emissions from transport will increase for more than 100%. The increased emissions from
commercial sector are mainly because of the increased utilization of gas in this sector.
The CO2 emissions from all energy sectors are given in Table 3.
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Oil Products
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Geothermal
Electricity
Crude Oil
Coal
Biomass
13
Figure 9. CO2 Emissions under Baseline Scenario (kt)
Table 3. CO2 Emissions by Sectors under Baseline Scenario (kt)
2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 2047 2050
Agriculture 75 46 49 52 56 60 65 70 75 80 85 89 94 99
Commercial 165 342 228 240 256 271 288 305 327 352 384 425 476 540
Industry 1346 1245 1261 1332 1414 1497 1582 1659 1724 1811 1898 1981 2092 2192
Power Sector 6327 7043 7069 6518 6549 7704 9141 9348 6624 6841 7040 7230 7325 7310
Residential 145 144 146 153 163 179 216 260 307 339 378 410 474 543
Transport 1424 1490 1546 1754 1904 2064 2259 2475 2655 2863 3052 3241 3355 3482
Total 9481 10311 10298 10049 10343 11774 13550 14118 11712 12286 12837 13376 13816 14166
2.6. SUMMARY
Table 4. Key Indicators for Baseline Scenario
Indicator 2011 2032 2050
Annual Growth
Rate 2011 - 2032 (%)
Annual Growth
Rate 2011 - 2050 (%)
Overall Growth 2011 -
2032 (%)
Overall Growth 2011 -
2050 (%)
Final Energy Consumption (ktoe) 1863 2758 3754 1.89% 1.81% 48.07% 101.55%
Power Plant Capacity (MW) 1838 2687 2875 1.82% 1.15% 46.17% 56.43%
Electricity Generation & Import (GWh)
8870 11945 14980 1.43% 1.35% 34.67% 68.88%
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kt
Year
Transport
Residential
Power Sector
Industry
Commercial
Agriculture
14
Primary Energy Supply (ktoe) 1691 2525 4529 1.93% 2.56% 49.33% 167.81%
CO2 Emissions (kt) 9481 14118 14166 1.91% 1.03% 48.90% 49.41%
The highest increase of the final energy consumption is in the transport and commercial sectors.
Diesel and electricity have the largest share in the final energy consumption over the entire planning period. After 2035 the natural gas and coal have increasing share due to increased demand of these fuels in commercial and industry sectors.
The existing coal power plants will be revitalized and will operate until 2032.
The existing gas-fired power plants will be operate until 2032, although not always in full capacity.
After 2030, new capacities based on coal (603 MW) and on gas (565 MW) will be installed in the power system.
Until 2050, total 363 MW of new hydro capacity will enter the power system, (three large hydro power plants - HPP Sv. Petka, HPP Boskov Most and HPP Lukovo Pole and incentivized small HPPs).
Until 2050, total 160 MW of incentivized wind and solar capacities will enter the power system (currently this is the maximal capacity to be supported with feed-in tariffs).
A total investment of 3045 € million is required for the additional 1690 MW of new generation capacities by 2050, including 8 € millions for new transmission and distribution networks.
Additional investment in new gas pipeline of 156 € millions is needed.
Primary energy supply becomes more diverse with increased share of natural gas, crude oil and oil products and renewable energy sources.
{New bullets will be added relevant for transport sector and/or other demand side technologies}
The level of CO2 emissions will grow by 29%, with predominant share of power generation.
15
3. MITIGATION SCENARIOS
3.1. GROUP 1: EU MITIGATION SCENARIOS
Table 5. Definition of EU mitigation scenarios
2020 2030 2040 2050
EU_Low
0%
-20% -30% -40%
EU_Medium -30% -45% -60%
EU_High -40% -60% -80%
Figure 10. Definition of EU mitigation scenarios
16
3.1.1. FINAL ENERGY CONSUMPTION
Figure 11. Final Energy Consumption by Fuel Type under EU mitigation scenarios (ktoe)
*SOL-Solar; GEO – Geothermal; HFO – Heavy fuel oil; KER – Kerosene; AVF – Aviation fuel;
LPG - Liquefied petroleum gas
3.1.2. POWER SECTOR – INSTALLED CAPACITY AND OUTPUT
Figure 12. Installed Capacity of Existing and New Build Power Plants under EU mitigation scenarios (MW)
17
Figure 13. Electricity Generation and Import under EU mitigation scenarios (GWh)
3.1.3. PRIMARY ENERGY SUPPLY
Figure 14. Primary Energy Supply under EU mitigation scenarios (ktoe)
3.1.4. TOTAL SYSTEM COSTS
18
Figure 15. Total system costs for the Baseline scenario and EU mitigation scenarios (2012Meuros)
3.1.5. CO2 EMISSIONS
Figure 16. CO2 Emissions by sectors under EU mitigation scenarios (kt)
19
Figure 17. Total CO2 Emissions under Baseline scenario and EU mitigation scenarios (kt)
3.1.6. SUMMARY
Table 6. Key Indicators for the Baseline Scenario and EU mitigation scenarios
Indicator Baseline EU_Low EU_Medium EU-High
Apsolute difference
Relative difference
Apsolute difference
Relative difference
Apsolute difference
Relative difference
Total Discounted System Costs (20012M€)
51,181 51,725 544 1.1% 52,243 1,063 2.1% 52,487 1,307 2.6%
Final Energy Consumption (ktoe)
113,101 112,043 -1,057 -0.9% 111,088 -2,013 -1.8% 108,857 -4,244 -3.8%
Power Plant Capacity (MW)
33,738 31,019 -2,719 -8.1% 30,852 -2,887 -8.6% 33,330 -408 -1.2%
Electricity Generation & Import (GWh)
489,919 458,764 -31,156 -6.4% 460,187 -29,733 -6.1% 469,332 -20,587 -4.2%
Primary Energy Supply (ktoe)
125,198 134,595 9,397 7.5% 132,140 6,942 5.5% 132,454 7,256 5.8%
CO2 Emissions (kt)
504,354 302,613 -201,741 -40.0% 269,871 -234,483 -46.5% 234,929 -269,425 -53.4%
20
3.2. GROUP 2: QERLC MITIGATION SCEANRIOS
Table 7. Definition of QERLC Mitigation Scenarios
2021-28 2029-36 2037-44 2045-52 QERLC _Low +20% +10% 0% -10% QERLC _MediumLow +10% 0% -10% -20% QERLC _Medium 0% -10% -20% -30% QERLC _MediumHigh -10% -20% -30% -40% QERLC _High -20% -30% -40% -50%
Figure 18. Definition of QERLC mitigation scenarios
21
3.2.1. FINAL ENERGY CONSUMPTION
Figure 19. Final Energy Consumption by Fuel Type under QERLC mitigation scenarios (ktoe)
*SOL-Solar; GEO – Geothermal; HFO – Heavy fuel oil; KER – Kerosene; AVF – Aviation fuel;
LPG - Liquefied petroleum gas
3.2.2. POWER SECTOR – INSTALLED CAPACITY AND OUTPUT
Figure 20. Installed Capacity of Existing and New Build Power Plants under QERLC mitigation scenarios (MW)
22
Figure 21. Electricity Generation and Import under QERLC mitigation scenarios (GWh)
3.2.3. TOTAL SYSTEM COSTS
Figure 22. Total system costs for the Baseline scenario and QERLC mitigation scenarios (2012Meuros)
23
3.2.4. PRIMARY ENERGY SUPPLY
Figure 23. Primary Energy Supply under QERLC mitigation scenarios (ktoe)
3.2.5. CO2 EMISSIONS
Figure 24. CO2 Emissions by sectors under the QERLC mitigation scenarios (kt)
24
Figure 25. Total CO2 Emissions under Baseline scenario and QERLC mitigation scenarios (kt)
3.2.6. SUMMARY
Table 8. Key Indicators for the QERLC mitigation scenarios
Indicator Baseline BAU-Low BAU-Medium BAU-High
Apsolute difference
Relative difference
Apsolute difference
Relative difference
Apsolute difference
Relative difference
Total Discounted System Costs (20012M€)
51,181 51,338 157 0.3% 51,521 341 0.7% 52,092 911 1.8%
Final Energy Consumption (ktoe)
113,101 112,774 -327 -0.3% 112,434 -667 -0.6% 111,677 -1,424 -1.3%
Power Plant Capacity (MW)
33,738 31,415 -2,323 -6.9% 33,330 -408 -1.2% 33,330 -408 -1.2%
Electricity Generation & Import (GWh)
489,919 458,764 -31,156 -6.4% 469,332 -20,587 -4.2% 469,332 -20,587 -4.2%
Primary Energy Supply (ktoe)
125,198 141,572 16,373 13.1% 137,455 12,257 9.8% 132,267 7,069 5.6%
CO2 Emissions (kt)
504,354 345,878 -158,476 -31.4% 320,961 -183,393 -36.4% 285,950 -218,404 -43.3%
25
3.3. GROUP 3: BAU DEVIATION MITIGATION SCENARIOS
Table 9. Definition of BAU Deviation Mitigation Scenarios
Group 3 scenarios 2020 2028 2036 2044 2052
BAUdev_Low -10% -15% -20% -25% -30%
BAUdev_Medium -15% -20% -25% -30% -35%
BAUdev_High -20% -30% -40% -50% -60%
Figure 26. Definition of BAU Deviation Mitigation Scenarios
3.3.1. FINAL ENERGY CONSUMPTION
0
2000
4000
6000
8000
10000
12000
14000
16000
2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 2047 2050
kt
Year
Baseline
BAUdev_Low
BAUdev_Medium
BAUdev_High
26
Figure 27. Final Energy Consumption by Fuel Type under BAU Deviation Mitigation Scenarios (ktoe)
3.3.2. POWER SECTOR – INSTALLED CAPACITY AND OUTPUT
Figure 28. Installed Capacity of Existing and New Build Power Plants under BAU Deviation Mitigation Scenarios (MW)
Table 10. Investment Costs under BAU Deviation Mitigation Scenarios (MEuros)
2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 2047 2050
BAUdev_Low
New PP 112 270 690 187 125 289 579 510 300 329 25 173 940
T&D Lines 56 1 1 0 9 3 2 4 2 4 3 2 1
Gas Pipeline 0 0 126 34 19 17 10 68 21 46 31 25 119
0
500
1000
1500
2000
2500
3000
3500
4000
4500
LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH
2011 2020 2032 2041 2050
kto
e
Year
Renewables (SOL, GEO)
Oil (HFO, KER, AVF)
LPG
Heat
Gasoline
Gas
Electricity
Diesel
Coal
Bunker Fuel
Biomass
Biofuels
0
500
1000
1500
2000
2500
3000
3500
LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH
2011 2020 2032 2041 2050
MW
Year
New solar
New wind
New hydro PP
Existing hydro PP
Existing oil-fired PP
New gas-fired PP
Existing gas-fired PP
New coal PP
Existing coal PP
27
Distrib. losses red.
27 31 36 37 32 32 32 0 0 0 0 0 32
Total Investment
195 301 853 257 185 341 622 582 323 379 59 201 1092
BAUdev_Medium
New PP 112 270 777 45 273 593 411 510 164 329 25 173 935
T&D Lines 56 3 0 4 3 3 2 3 2 4 3 3 1
Gas Pipeline 0 0 135 18 12 10 19 67 25 43 21 0 75
Distrib. losses red.
27 31 36 37 32 32 32 0 0 0 0 0 32
Total Investment
195 304 948 105 320 638 463 580 192 376 49 176 1044
BAUdev_High
New PP 112 270 832 45 125 289 623 736 650 787 131 173 966
T&D Lines 56 10 0 0 1 3 1 2 2 3 3 3 3
Gas Pipeline 0 0 140 19 19 16 4 0 0 0 0 0 0
Distrib. losses red.
27 31 36 37 32 32 32 0 32 0 32 0 0
Total Investment
195 311 1008 101 177 340 661 737 684 791 166 177 968
Figure 29. Electricity Generation and Import under BAU Deviation Mitigation Scenarios (GWh)
3.3.3. PRIMARY ENERGY SUPPLY
0
2000
4000
6000
8000
10000
12000
14000
16000
LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH
2011 2020 2032 2041 2050
GW
h
Year
Import
New solar
New wind
New hydro PP
Existing hydro PP
New gas-fired PP
Existing gas-fired PP
New coal PP
Existing coal PP
28
Figure 30. Primary Energy Supply under BAU Deviation Mitigation Scenarios (ktoe)
3.3.4. TOTAL SYSTEM COSTS
Figure 31. Total System Costs under Baseline and BAU Deviation Mitigation Scenarios (2012 M Euros)
0
1000
2000
3000
4000
5000
6000
LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH
2011 2020 2032 2041 2050
kto
e
Year
Renewables(Sol,Wind,Hydro)
Oil Products
Natural gas
Geothermal
Electricity
Crude Oil
Coal
Biomass
50000
50500
51000
51500
52000
52500
53000
Baseline BAUdev_Low BAUdev_Medium BAUdev_High
20
12
MEu
ros
Scenario
29
3.3.5. CO2 EMISSIONS
Figure 32. CO2 Emissions under BAU Deviation Mitigation Scenarios (kt)
Table 11. Total CO2 Emissions under Baseline and BAU Deviation Mitigation Scenarios (kt)
Scenario 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 2047 2050
Baseline 9481 10311 10298 10049 10343 11774 13550 14118 11712 12286 12837 13376 13816 14166
BAUdev_Low 9453 9564 9280 5693 6193 6521 6910 7266 8033 8453 9032 9494 9929 10020
BAUdev_Medium 9453 9400 8888 5757 6143 6430 6769 7189 7953 8407 8962 9363 9339 9316
BAUdev_High 9453 9267 8576 5794 6188 6506 6869 7197 7383 7029 6858 6688 6326 5964
Figure 33. Total CO2 Emissions under Baseline and BAU Deviation Mitigation Scenarios (kt)
0
2000
4000
6000
8000
10000
12000
LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH LOW MED HIGH
2011 2020 2032 2041 2050
kt
Year
Transport
Residential
Power Sector
Industry
Commercial
Agriculture
0
2000
4000
6000
8000
10000
12000
14000
16000
2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 2047 2050
kt
Year
Baseline
BAUdev_Low
BAUdev_Medium
BAUdev_High
30
3.3.6. SUMMARY
Table 12. Key Indicators for BAU Deviation Mitigation Scenarios
Indicator Baseline BAUdev_Low BAUdev_Medium BAUdev_High
Apsolute difference
Relative difference
Apsolute difference
Relative difference
Apsolute difference
Relative difference
Total Discounted System Costs (2012M€)
51,181 51,550 369 0.7% 51,809 628 1.2% 52,945 1,764 3.4%
Final Energy Consumption (ktoe)
113,101 112,765 -336 -0.3% 112,657 -444 -0.4% 111,977 -1,124 -1.0%
Power Plant Capacity (MW)
33,738 31,415 -2,323 -6.9% 30,852 -2,887 -8.6% 33,330 -408 -1.2%
Electricity Generation & Import (GWh)
489,919 458,764 -31,156 -6.4% 460,187 -29,733 -6.1% 469,332 -20,587 -4.2%
Primary Energy Supply (ktoe)
125,198 141,260 16,062 12.8% 139,805 14,607 11.7% 133,599 8,401 6.7%
CO2 Emissions (kt)
504,354 347,519 -156,835 -31.1% 340,113 -164,240 -32.6% 300,290 -204,064 -40.5%
3.4. COMPARATIVE ASSESSMENT
31
4. CLIMATE CHANGE MITIGATION ACTION PLAN
32
APPENDIX I: DATA SOURCES AND KEY ASSUMPTIONS
The analysis for Macedonia’s energy sector is based on numerous data inputs and assumptions,
therefore requires a set of key national data sources. For Macedonia, the sources of this information
are listed by data requirement in Table 13 below.
Table 13. Key Data Sources
Data Requirement Source
2011 Energy Balance National Energy Balances (from the State Statistical Office2 and the Ministry
of Economy3)
Domestic Energy Prices Energy Regulatory Commission4 (Annual report for 2011)
Resource Potential, including imports/exports
Strategy for Energy Development of the Republic of Macedonia until 20305
Strategy for Utilisation of Renewable Energy Sources in the Republic of
Macedonia by 20206
Program for Realization of the Energy Development Strategy in the Republic of Macedonia for the Period 2013 - 2017
Installed capacity and characterization of existing electricity and CHP plants
Annual Report for 2011 of the JSC Macedonian Power Plants - AD ELEM - for the electricity generation capacities (www.elem.com.mk)
Reports of TE-TO AD Skopje (www.te-to.com.mk)
Load Profile Demand curves for 2012 from the Electricity Transmission System Operator of Macedonia - AD MEPSO (www.mepso.com.mk)
Fuel prices projections World Energy Outlook (WEO) 2011 (provided by World Bank)
In the model there are two types of technologies, existing and new. The basic parameters of the
existing electricity and heat generation plants are given in Table 14. All data in this table are taken
from the relevant institutions mentioned in the Table 13.
2 http://www.stat.gov.mk/pdf/2012/6.1.12.82.pdf
3 http://www.economy.gov.mk/ministerstvo/sektori_vo_ministerstvo/sektor_za_energetika/energetski_bilans_2013-2017.html
4
http://www.erc.org.mk/odluki/Godisen%20izvestaj%20za%20rabota%20na%20Regulatornata%20komisija%20za%20energetika%20za%202011%20godina.pdf
5 http://www.ea.gov.mk/projects/unece/docs/legislation/Macedonian_Energy_Strategy_until_2030_adopted.pdf
6 http://www.uncsd2012.org/content/documents/677Strategy_for_utilization_RES_Macedonia.pdf
33
Table 14. Existing Power plants
Plant Type/Fuel Capacity
(MW) Efficiency Availability
Fixed O&M (M€/GW)
Variable O&M
(€/MWh)
Retirement year
Thermal power plant Lignite 736 31% 73% 25.31 4.60 2017
Power plant Bitola/Lignite 627 31% 73% 2017
Unit 1 209 31% 73% 2017
Unit 2 209 31% 73% 2017
Unit 3 209 31% 73% 2017
Power plant Oslomej/Lignite 109 31% 60% 2017
Power plant/HFO 198 34% 65% 2020
Power plant/Hydro 579 100% 30% 15.9 1.9
Big HPP 551.8 After 2050
Vrben 12.8 100% 40% After 2050
Vrutok 172 100% 26% After 2050
Raven 21.6 100% 28% After 2050
Tikves 116 100% 18% After 2050
Kalimanci 13.8 100% 14% After 2050
Globocica 42 100% 58% After 2050
Spilje 84 100% 41% After 2050
Kozjak 80 100% 21% After 2050
Matka 9.6 100% 48% After 2050
Small HPP 27.2 After 2050
Pena 3.3 100% 33% After 2050
Zrnovci 1.4 100% 34% After 2050
Pesocani 2.7 100% 43% After 2050
Sapuncica 2.9 100% 39% After 2050
Dosnica 4.1 100% 42% After 2050
Turija 2.2 100% 27% After 2050
Modric 0.2 100% 20% After 2050
Babuna 0.7 100% 43% After 2050
Belica 0.3 100% 46% After 2050
Glaznja 2.1 100% After 2050
Popova Sapka 4.8 100% 43% After 2050
Strezevo 1 2.4 100% After 2050
Strezevo 2 0.1 100% After 2050
CHP gas 260 52% 90% 64.6 1.4 2032
TE-TO 230 52% 90% 2032
Kogel 30 44% 85% 2032
34
Plant Type/Fuel Capacity
(MW) Efficiency Availability
Fixed O&M (M€/GW)
Variable O&M
(€/MWh)
Retirement year
Energetika 30 44% 85% 2032
Heating plant (centralized)/Natural gas (PJ/a)
17.345 96% 20% 1.46 0.95 After 2050
The other group is new technologies that are introduced in the model with the following data:
Investment cost, Operation and Maintenance cost (Fixed and Variable), efficiency, installed capacity,
life time and availability factor, so the model can select which technology is the most cost effective,
based on these input data (Table 15). All data, except the investment costs, are taken from the
Strategy for Energy Development of the Republic of Macedonia until 2030 and Strategy for
Utilisation of Renewable Energy Sources in the Republic of Macedonia by 2020.
Table 15. Characterization of Key Power Plant Options
Power Plant Type Start Date (Available)
Life-time Efficiency* Installed Capacity
(MW)
Availability Factor
Investment Cost (M€/GW)
Fixed O&M (M€/GW)
Variable O&M
(€/MWh)
Bitola revitalization 2018 15 0.32 650 0.74 462 25.31 1.28
Oslomej revitalization**
2018 15 0.32 109 0.74 392 25.31 1.28
Lignite Fired 2027 30 0.37 200 0.8 1725 25.31 1.28
Lignite Fired 2030 30 0.37 300 0.8 1725 25.31 1.28
Lignite Fired 2033 30 0.37 300 0.8 1725 25.31 1.28
Gas CHP*** 2016 20 0.52 230 0.85 1090 8.08 1.38
Gas CHP*** 2016 20 0.52 40 0.85 1090 8.08 1.38
Gas CHP*** 2016 20 0.44 30 0.90 1090 8.08 1.38
Gas CHP*** 2016 20 0.44 30 0.90 1090 8.08 1.38
Gas CHP*** 2016 20 0.44 30 0.90 1090 8.08 1.38
Gas Fired 2016 30 0.58 130 0.9 1090 8.08 1.38
Gas Fired 2016 30 0.58 300 0.9 1090 8.08 1.38
Gas Fired 2016 30 0.58 300 0.9 1090 8.08 1.38
Gas Fired 2016 30 0.58 300 0.9 1090 8.08 1.38
Hydro - SvPetka 2012 50 1 36 0.19 1500 4.47 0.20
Hydro - Boskov most 2017 50 1 68 0.22 1818 4.47 0.20
Hydro – Lukovo Pole 2018 50 1 58 0.32 1638 4.47 0.20
Hydro - Gradec 2021 50 1 55 0.51 5577 4.47 0.20
Hydro - Chebren 2022 50 1 333 0.29 1712 4.47 0.20
Small hydro 2012 50 1 120 0.29 2400 4.47 0.20
Hydro - Galiste 2021 50 1 194 0.16 2016 4.47 0.20
Hydro - Veles 2024 50 1 93 0.37 5258 4.47 0.20
Hydro - Babuna 2025 50 1 17 0.38 5176 4.47 0.20
35
Power Plant Type Start Date (Available)
Life-time Efficiency* Installed Capacity
(MW)
Availability Factor
Investment Cost (M€/GW)
Fixed O&M (M€/GW)
Variable O&M
(€/MWh)
Hydro - Zgropolci 2025 50 1 17 0.37 5529 4.47 0.20
Hydro - Gradsko 2025 50 1 17 0.44 6235 4.47 0.20
Hydro - Kukiricani 2025 50 1 17 0.54 6118 4.47 0.20
Hydro – Krivolak 2025 50 1 17 0.54 6118 4.47 0.20
Hydro – Militkovo 2025 50 1 17 0.54 7529 4.47 0.20
Hydro – Demir Kapija 2025 50 1 24 0.55 6167 4.47 0.20
Hydro - Gavato 2025 50 1 17 0.56 8471 4.47 0.20
Hydro - Dubrovo 2025 50 1 17 0.54 7294 4.47 0.20
Hydro - Gevgelija 2025 50 1 17 0.57 6824 4.47 0.20
Wind (central), with FIT
2015 20 1 150 0.14-0.32 1601-1494 25.6 0.00
Wind (central) 2015 20 1 210 0.14-0.32 1617-1509 25.6 0.00
Solar PV (decentralized) with
FIT 2012 30 1 25 0.155-0.310 2134-1067 31.4 0.00
Solar PV (decentralized)
2012 30 1 95 0.155-0.310 2134-1067 31.4 0.00
Nuclear 2029 10 0.36 1000 0.90 4560 80 1.96
*The efficiency of lignite power plants was provided by the World Bank team under Green Growth Project ** The depletion of the lignite mine, requiring the TPP Oslomej to be upgraded to burn imported coal ***Electricity efficiency for CHP plants.
Revitalization of Bitola units includes seven measures (Table 16) with total cost of 300 MEuros.
Table 16. Investment costs for revitalization of TPP Bitola
Measure M€
1 Revitalization of boilers 20
2 NOx 30
3 Sox 65
4 PM 35
5 Turbines
150 6 Generators
7 Automation
Total 300
Investment cost for revitalization of boilers, NOx, SOx and PM are taken from official document from
AD ELEM (internal document for the activities of AD ELEM, 2011). The investment cost for the rest
three measures are obtained from the World Bank team.
The revitalization of TPP Oslomej is projected to be 43 MEuros (Table 17). Investment costs for each
measure, as in the case with revitalization of Bitola, are taken from official document from AD ELEM
(internal document for the activities of AD ELEM, 2011).
Table 17. Investment costs for revitalization of TPP Oslomej
Measure M€
1 Revitalization of boilers 4.3
36
2 NOx 6.4
3 SOx 13.9
4 PM 7.5
5 Turbines 7.5
6 Generators 2.1
7 Automation 1.1
Total 42.7
In order to develop more plausible scenarios and properly reflect the situation in Macedonia a series
of constraints has been introduced (Table 18). The limits for the potential of the wind and solar
technologies are based on the Strategy for Utilisation of Renewable Energy Sources in the Republic
of Macedonia by 2020.
Table 18. Key Constraints in the Baseline Scenario
Sector / Issue Constraint
Resource supply
Domestic resources
RES potential
Small HPP with Feed in Tariff Limited potential for small HPP (up to 120 MW), with FiT 90 €/MWh
Wind with Feed in Tariff Limited potential for wind power plants (up to 150 MW by 2030), with FiT 89 €/MWh
Wind without Feed in Tariff Limited potential for wind power plants (up to 210 MW by 2030)
Solar with Feed in Tariff Limited potential for PV installation (up to 25 MW), with FiT 140 €/MWh
Solar without Feed in Tariff Limited potential for PV installation (up to 95 MW)
Imports No limit
Price for imported electricity, running from 7.3 – 10 €cents/kWh
Exports Not allowed
Electricity generation
Technology availability Revitalized TPP Oslomej using imported coal
The location and the capacities of the large hydro power plants are limited (based on the available National Studies of the hydro potential in the country)
*
In addition to the previous assumptions, the technical losses in transmission and distribution
network are projected to be 2.35% and 13.54%, respectively.
In terms of the energy prices Macedonia model uses its 2011 "border/mine-mouth" price for energy
sources, and any sectoral adjustments to these (for delivery and mark-up (but not taxes)). The
import prices are provided by macro-economic team of the Green Growth Program (Table 19).
Table 19. Energy Price Trajectory Assumptions (Euro/GJ)
Energy Form 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 2047 2050
Biomass (Country price)
3.7 5.5 5.6 5.8 6.0 6.2 6.4 6.5 6.7 7.4 8.2 9.0 9.9 10.9
Coal - Brown 3.0 2.4 2.3 2.4 2.5 2.5 2.5 2.6 2.6 2.6 2.7 2.7 2.7 2.8
Coal - Hard 3.4 2.6 2.6 2.7 2.7 2.8 2.8 2.9 2.9 2.9 3.0 3.0 3.0 3.1
Coal – Lignite (Import)
4.1 5.0 5.5 5.8 6.1 6.4 6.7 7.0 7.3 7.5 7.8 8.1 8.4 8.7
Coal –Lignite (Country price)
1.4 2.1 2.7 3.3 3.8 4.3 4.6 4.8 5.0 5.2 5.4 5.5 5.7 5.9
37
Gas 14.3 6.9 7.4 7.8 8.1 8.4 8.6 8.7 8.8 8.9 9.1 9.2 9.3 9.4
Nuclear 3.0 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6
Oil - Crude 14.7 13.5 14.3 15.0 15.5 16.0 16.3 16.6 16.9 17.2 17.5 17.7 18.0 18.3
Oil - Distillate 19.1 17.5 18.6 19.5 20.1 20.8 21.2 21.6 22.0 22.4 22.7 23.1 23.4 23.8
Oil - HFO 11.9 10.9 11.6 12.1 12.5 12.9 13.2 13.5 13.7 13.9 14.2 14.4 14.6 14.8
Oil - Kerosene 20.6 18.9 20.0 21.0 21.7 22.3 22.9 23.3 23.7 24.1 24.5 24.8 25.2 25.6
Oil - LPG 16.2 14.8 15.7 16.5 17.0 17.6 18.0 18.3 18.6 18.9 19.2 19.5 19.8 20.1
{New Tables will be added with the technologies characteristics on the demand side and in transport sector}
38
APPENDIX II: METHODOLOGY – MARKAL MODEL DESCRIPTION
MARKAL (an acronym for MARKet ALlocation) is a bottom-up, dynamic linear programming model of
the energy system of one or several regions that provides a technology-rich basis for estimating
energy dynamics over a multi-period horizon. The model, first developed in the late 1970s for energy
planning, continues to undergo development and refinement. Energy Technology Systems Analysis
Programme (ETSAP) coordinates these activities, and is sponsored by the International Energy
Agency (IEA)7.
As with most energy system models, energy carriers in MARKAL interconnect the conversion and
consumption of energy. This user-defined network includes all energy carriers involved with primary
supplies (e.g., mining, petroleum extraction, etc.), conversion and processing (e.g., power plants,
refineries, etc.), and end-use demand for energy services (e.g., boilers, automobiles, residential
space conditioning, etc.). The demand for energy services may be disaggregated by sector (i.e.,
residential, manufacturing, transport and commercial) and by specific functions within a sector (e.g.,
residential air conditioning, heating, lighting, hot water, etc.). The building blocks depicted in Figure
34 represent this network, referred to as a Reference Energy System.
Figure 34. MARKAL Building Blocks
The optimization routine used in the model’s solution selects from each of the sources, energy
carriers, and transformation technologies to produce the least-cost solution subject to a variety of
constraints. The user defines technology costs, technical characteristics (e.g., conversion
efficiencies), and energy service demands. As a result of this integrated approach, supply-side
7 http://www.iea-etsap.org/web/reports/markal-irg.pdf
39
technologies are matched to energy service demands. The specification of new technologies, which
are less energy - or carbon-intensive, allows the user to explore the effects of these choices on total
system costs, changes in fuel and technology mix, and the levels of greenhouse gases and other
emissions. Therefore, MARKAL is highly useful for understanding the role of technology in carbon
mitigation efforts and other energy system planning settings.
A variety of different constraints may be applied to the least-cost solution. These constraints include
those related to a consistent representation of the energy system, such as balancing energy inputs
and outputs, utilization of capacity, replacement of expended capacity by new investments and
satisfaction of demand. In addition, environmental or policy issues, such as greenhouse gas
emissions may be examined in several ways, including sectoral or system-wide emissions limits on an
annual basis or cumulatively over time. Alternatively, the imposition of a carbon tax or other fee
structure could be modeled if desired. As a result, various costs for carbon may be generated for
different levels of emission reductions. In this way, future technology configurations are generated
and may be compared. If constraints are also placed on the types of technologies and rates of
penetration, the configuration of the entire energy system will change. In all cases, MARKAL will
produce the least-cost solution which meets the provided set of constraints.