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October 2011

The Demand for Greenhouse Gas Emissions Reductions: An Investors’ Marginal Abatement Cost Curve for Turkey Prepared for EBRD

Project Team

Daniel Radov (NERA)

Per Klevnas (NERA)

Martina Lindovska (NERA)

Stewart Carter (NERA)

Adil Hanif (NERA)

Guy Turner (BNEF)

Christos Katsileros (BNEF)

Christian Lynch (BNEF)

Jonathan Malsbury (BNEF)

Joel Lindop (BNEF)

Ceren Uzdil (IBS)

Huseyin Celebi (IBS)

NERA Economic Consulting 15 Stratford Place London W1C 1BE United Kingdom Tel: +44 20 7659 8500 Fax: +44 20 7659 8501 www.nera.com

Greenhouse Gas Abatement in Turkey Acknowledgments

NERA Economic Consulting

Contents

Acknowledgments i

Disclaimer ii

Executive Summary iii

1. Introduction 1 1.1. This Report 1 1.2. National Energy and Emissions Profile 2

2. Investor Behaviour 11 2.1. Transaction costs and hurdle rates 11 2.2. Factors affecting transaction costs and hurdle rates 11 2.3. Summary: Investor behaviour 12

3. Overview of Approach to Policy Scenarios and Assumptions 13

3.1. Status Quo Scenario 13 3.2. Currently Planned Policies 14 3.3. Enhanced Policies 15 3.4. Summary Overview of Scenarios 17 3.5. Fuel Price Assumptions 19

4. Policy “Status Quo” Scenario 21 4.1. Policy Setting and Assumptions 21 4.2. Policy Status Quo: Overall MACC 24 4.3. Power 27 4.4. Buildings 34 4.5. Industry 40 4.6. Transport 49 4.7. Waste 51 4.8. Agriculture and Forestry 53

5. Planned Policies Scenario 55 5.1. Policy Settings and Assumptions 55 5.2. Planned Policy: Overall MACC 57 5.3. Power 59 5.4. Buildings 64 5.5. Other Major Emitting Sectors (Industry, Transport, Waste

and Agriculture) 66



6. Enhanced Policy Scenarios 67 6.1. Policy Setting and Assumptions 67 6.2. Enhanced Policy Scenarios: Overall MACCs 72 6.3. Power 75 6.4. Buildings 80 6.5. Industry 83

7. Conclusions 85

Appendix A. Detailed Sector Assumptions and Projections 88

A.1. Power 88 A.2. Household and Building 100 A.3. Industry 109 A.3.4. Detailed technology cost and performance assumptions 114 A.4. Transportation 118 A.5. Waste 123 A.6. Agriculture, Forestry and Land Use 124

Appendix B. Transaction Costs, Discount Rates, and Payback Assumptions 128

B.1. Project Transaction Costs 128 B.2. Summary of Estimates 132

Appendix C. Fuel Price Assumptions 137

Appendix D. Policy Transaction Costs 141

Appendix E. MAC Curve Data 142



List of Tables

Table 1.1 Emissions by Greenhouse Gas and annual growth rate 5 Table 1.2 Emissions by category and annual growth rates 6 Table 1.3 Greenhouse Gas Emission Projections 8 Table 3.1 Feed-In-Tariff Levels 14 Table 3.2 Summary of Modelling Scenarios 17 Table 5.1 Proposed Feed-In Tariff Levels 55 Table A.1 Power Sector Resource Constraints 98 Table A.2 Power Sector Technologies 99 Table A.3 Distribution of Free Lignite to Families (2003-2009) 102 Table A.4 Overview of Buildings Abatement Measures: Space Heating 108 Table A.5 Overview of Buildings Abatement Measures: Water Heating, Lighting and

Appliances 108 Table A.6 Abatement Measures for Cement Sector 111 Table A.7 Crude Steel Production in Turkey 112 Table A.8 Industry Growth Projections 113 Table A.9 Abatement Measures – Cement 114 Table A.10 Abatement Measures – Steel 114 Table A.11 Abatement Measures – Oil Refining and Petrochemicals 115 Table A.12 Abatement Measures – Selected Chemicals 116 Table A.13 Abatement Measures – Minerals, Glass, Bricks, Ceramics 117 Table A.14 Abatement Measures – Selected Other Industry 117 Table A.15 Abatement measures in Transport sector 123 Table A.16 Solid Waste Disposal Facilities in Turkey 124 Table A.17 Enterprises in the Agricultural Sector 127 Table A.18 Forest Area, 2005 127 Table B.1 Examples of Sources on Bottom-Up Estimates of Transaction Costs Faced by

Households and Small/Medium Firms 129 Table B.2 Summary of Barriers Estimates 133 Table C.1 Fuel Price Assumptions, Year and Scenarios 137 Table E.1 Full MACC, Status Quo Policy, 2030 142 Table E.2 Full MACC, Planned Policies Scenario, 2030 147 Table E.3 Full MACC, Enhanced Policies Scenario, 2030 152 Table E.4 Full MACC, Capital Grants Scenario, 2030 157



List of Figures

Figure ES.1 Historical Emissions Trends iv Figure ES.2 Emissions Intensity in Turkey and OECD Europe (1990-2009) v Figure ES.3 Emissions Projections Under Different Scenarios viii Figure ES.4 MACC for Status Quo Policy Scenario (2030) ix Figure ES.5 Summary Macroeconomic Implications xi Figure ES.6 Summary of Profitable Abatement, by Scenario xiv Figure 1.1 MACC Illustration 2 Figure 1.2 Primary energy consumption 3 Figure 1.3 Final energy consumption 4 Figure 1.4 Historical Emissions Trends 5 Figure 1.5 Emissions due to Fuel Combustion by Sub-Sector 7 Figure 1.6 Energy Intensity Measures for Turkey (1990-2008) 9 Figure 1.7 Emissions Intensity in Turkey and OECD Europe (1990-2008) 10 Figure 3.1 Fuel Price Assumptions 20 Figure 4.1 Full MACC, Status Quo, 2020 26 Figure 4.2 Full MACC, Status Quo, 2030 26 Figure 4.3 Power Capacity Projection, Status Quo 28 Figure 4.4 Power Generation, Status Quo 29 Figure 4.5 Power Emissions, Status Quo 30 Figure 4.6 Power Sector MACC, Status Quo, 2020 31 Figure 4.7 Power Sector MACC, Status Quo, 2030 31 Figure 4.8 Number of Dwellings by Level of Insulation 35 Figure 4.9 Total Direct Emissions from Residential Dwellings 36 Figure 4.10 Buildings MACC, Status Quo, 2020 39 Figure 4.11 Buildings MACC, Status Quo, 2030 39 Figure 4.12 2008 Emissions and 2030 “Static” Emissions Projection 41 Figure 4.13 Industry MACC, Status Quo, 2030 43 Figure 4.14 Transport MACC, Status Quo, 2020 50 Figure 4.15 Transport MACC, Status Quo, 2030 50 Figure 4.16 Waste MACC, Status Quo, 2020 52 Figure 4.17 Waste MACC, Status Quo, 2030 52 Figure 5.1 Full MACC, Planned Policy, 2020 58 Figure 5.2 Full MACC, Planned Policy, 2030 58 Figure 5.3 Power Capacity Projection, Planned Policies 60 Figure 5.4 Power Generation, Planned Policies 61 Figure 5.5 Power Emissions, Planned Policies 62 Figure 5.6 Power Sector MACC, Planned Policy Scenario, 2020 63 Figure 5.7 Power Sector MACC, Planned Policy Scenario, 2030 63 Figure 5.8 Buildings MACC, Planned Policy, 2020 66 Figure 5.9 Buildings MACC, Planned Policy, 2030 66



Figure 6.1 Full MACC, Enhanced Policy (Carbon Prices), 2020 73 Figure 6.2 Full MACC, Enhanced Policy (Carbon Prices), 2030 73 Figure 6.3 Full MACC, Enhanced Policy (Capital Grants) Scenario, 2020 74 Figure 6.4 Full MACC, Enhanced Policy (Capital Grants) Scenario, 2030 74 Figure 6.5 Power Capacity Projection, Enhanced Policies (Carbon Prices) 76 Figure 6.6 Power Generation, Enhanced Policies (Carbon Prices) 77 Figure 6.7 Power Emissions, Enhanced Policies (Carbon Prices) 78 Figure 6.8 Power Sector MACC, Enhanced Policy (Carbon Prices) Scenario, 2020 79 Figure 6.9 Power Sector MACC, Enhanced Policy (Carbon Prices) Scenario, 2030 80 Figure 6.10 Buildings MACC, Enhanced Policy, 2020 82 Figure 6.11 Buildings MACC, Enhanced Policy, 2030 82 Figure 6.12 Industry MACC, Enhanced Policy Scenario, 2030 84 Figure 7.1 Emissions Projections Under Different Scenarios 86 Figure 7.2 Summary Abatement, by Scenario 87 Figure A.1 Electricity Consumption in Turkey 88 Figure A.2 Electricity Generation in Turkey 89 Figure A.3 Reserve Margin in Turkey 90 Figure A.4 Renewable Energy in Turkey (ktoe) 91 Figure A.5 Hydro Power Potential of Turkey 92 Figure A.6 Wind Atlas of Turkey, m/s at 30 metres 93 Figure A.7 Installed Capacity By Ownership, end-2009 95 Figure A.8 Electricity consumption per capita (EU and Turkey) 98 Figure A.9 Building Stock in Turkey 100 Figure A.10 Energy Consumption in Buildings and Households 101 Figure A.11 Fuel Mix for Residential Heating (2008) 102 Figure A.12 Energy Consumption by Fuel Type in Buildings 103 Figure A.13 Building Heat Demand Intensity in Turkey and Other European Countries 104 Figure A.14 Number of Dwellings – Houses and Apartments 107 Figure A.15 Cement Plants in Turkey 109 Figure A.16 Cement Production in Turkey (Mt) 110 Figure A.17 Cement Output and GDP per Capita (EU and Turkey) 110 Figure A.18 Iron and Steel Plants in Turkey 112 Figure A.19 Steel Output and GDP per Capita (EU and Turkey) 113 Figure A.20 Industry Energy Intensity - International Benchmarks 118 Figure A.21 Freight and Passenger Transportation 119 Figure A.22 Road Motor Vehicle Stock in Turkey 119 Figure A.23 Energy Consumption of the Transportation Sector 120 Figure A.24 Transport sector - international benchmarks (vehicles) 120 Figure A.25 Transport sector - International Comparison of Fuel Consumption per Capita and

of Fuel prices 121 Figure A.26 Motor Vehicle Penetration in Turkey and Selected Countries 122 Figure A.27 Growth of Agriculture and Forestry 125



Figure A.28 Agricultural Land and Forest Area 126 Figure C.1 Fuel Price Assumptions - Status Quo 138 Figure C.2 Fuel Price Assumptions - Planned Policies 139 Figure C.3 Fuel Price Assumptions - Enhanced Policies 140



i

Acknowledgments

This report was funded by the European Bank for Reconstruction and Development (“EBRD”), and has benefitted greatly from the contributions of its staff. The Project Team would like to thank, in particular, Grzegorz Peszko, the operational leader at EBRD, as well as Adonai Herrera-Martínez, the project liaison at EBRD in Istanbul, for their analytical insights and guidance on relevant policy. Various other members of EBRD staff were also generous with their time and knowledge, including Andi Aranitasi, Alexander Chirmiciu, Aleksandar Hadzhiivanov, Janina Ketterer, Philip Lam, Gianpiero Nacci, Ioannis Papaioannou, and others. This study has been substantially improved by their experience and feedback. In addition to contributions from EBRD, a wide range of industry and government stakeholders also provided input to the study, which would not have been possible without their cooperation. The Project Team is grateful for the contributions of all of these stakeholders. Of course, responsibility for any errors rests with the Project Team.

Greenhouse Gas Abatement in Turkey Disclaimer


ii

Disclaimer

NERA shall not have any liability to any third party in respect of this report or any actions taken or decisions made as a consequence of the results, advice or recommendations set forth therein. This report may not be sold without the written consent of NERA.

This report is intended to be read and used as a whole and not in parts. Separation or alteration of any section or page from the main body of this report is expressly forbidden and invalidates this report.

All opinions, advice and materials provided by NERA are included, reflected or summarized herein as the “NERA Content”. There are no third party beneficiaries with respect to the NERA Content, and NERA disclaims any and all liability to any third party. In particular, NERA shall not have any liability to any third party in respect of the NERA Content or any actions taken or decisions made as a consequence of the results, advice or recommendations set forth herein.

The NERA Content does not represent investment advice or provide an opinion regarding the fairness of any transaction to any and all parties. The opinions expressed in the NERA Content are valid only for the purpose stated herein and as of the date hereof. Information furnished by others, upon which all or portions of the NERA Content are based, is believed to be reliable but has not been verified. No warranty is given as to the accuracy of such information. Public information and industry and statistical data are from sources NERA deems to be reliable; however, NERA makes no representation as to the accuracy or completeness of such information and has accepted the information without further verification. No responsibility is taken for changes in market conditions or laws or regulations and no obligation is assumed to revise NERA Content to reflect changes, events or conditions, which occur subsequent to the date hereof.

Greenhouse Gas Abatement in Turkey Executive Summary


iii

Executive Summary

This report investigates the possibilities for reducing greenhouse gas emissions in Turkey, over the period 2010-2030, and estimates their cost, across a range of sectors of the economy. In contrast to other studies of this kind, the present analysis takes the point of view of a private investor interested in profitable investment opportunities that also reduce emissions. The study includes estimates of the costs and benefits of different investment opportunities, and calculations of the respective costs and benefits of reducing emissions from the perspective of a private investor.

The main output of this work is presented as a “marginal abatement cost curve”, or MACC, for potential investors. A MACC is a graphical representation of the extent of emission reductions that can be achieved by investments in different technologies across the economy, and the corresponding benefits or costs per tonne of emissions reduced. The MACC can be thought of in relation to the pricing of carbon or other GHG emissions, but it need not be interpreted as implying that there is a carbon price – it simply shows the cost of reducing emissions.

Another key output of this study is an analysis of the impact of policies on investors’ costs and profits. The study estimates how demand for emissions-reducing investments, and thus for abatement, can be enhanced by specific economic and climate policies contemplated by Turkey or that might be expected as part of an EU accession package.

Overview of emissions in Turkey

In 1990 Turkey’s emissions were 187 million tonnes of carbon dioxide equivalent (hereafter MtCO2e). By 2008 they had nearly doubled, to 367 MtCO2e. The annual growth rate of emissions during this period was 3.8 percent, although growth has slowed to 2.7 percent since 2000. In 2008, fuel combustion accounted for 76 percent of GHG emissions. Waste treatment ranked second after fuel combustion, with 9 percent. Industrial processes accounted for 8 percent and agriculture 7 percent.1

The power sector accounts for the largest share of emissions, with just over 100 Mt, or around 30 percent of emissions in 2008. Industry as a whole accounted for around 90 MtCO2e, with the cement sector alone responsible for over 40 MtCO2e. Fuel use in buildings and for transportation each also accounted for 50 MtCO2 emissions. The agriculture sector accounted for 40 MtCO2e, and the waste sector nearly 35 MtCO2e (UNFCCC 2010).

1 Turkey Greenhouse Gas Inventory, 1990 to 2008. Annual Report for submission under the Framework Convention on

Climate Change. National Inventory Report, 2010



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Figure ES.1 Historical Emissions Trends

0

50

100

150

200

250

300

350

400

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

MtC

O2e

q

Electricity & Heat Oil and Gas Solid Fuels MetalsMinerals Other Industry Transport BuildingsAgriculture Waste Other

Note: Excluding land use and land use change Source: UNFCCC inventory

Energy and Emissions Intensity

Turkey’s total primary energy supply per capita has risen 45 percent from 1990-2008, but was still only 1.4 tonnes of oil equivalent (toe) per capita by the end of the period. This was less than one-third of the OECD average of 4.6 toe per capita) and just 40 percent of the OECD Europe average of 3.4 toe/cap.

As a proportion of GDP (adjusted for purchasing power parity), Turkey’s energy intensity (0.12 toe / ‘000 $) was 13 percent lower than the OECD Europe average in 2008. Turkey’s energy intensity per PPP-adjusted GDP (in constant year 2000 US$) has remained relatively steady over the last two decades, although there is a slight downward trend over the past decade. For OECD Europe, there is a much stronger downward trend over all of the last 20 years. Turkey’s energy intensity therefore reflects its low GDP per capita relative to OECD Europe, but suggests that the economy is already relatively energy efficient, given the value of its output.

Emissions intensity in Turkey displays a similar pattern, shown in Figure ES.2. Despite increasing 50 percent over the last two decades, Turkey’s emissions intensity per capita, at 5.1 tCO2e in 2008, remains well below the OECD Europe average of 9.3 tCO2e.



v

Figure ES.2 Emissions Intensity in Turkey and OECD Europe (1990-2009)

Emissions per $ GDP Emissions per capita

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

1990 1993 1996 1999 2002 2005 2008

Em

issi

ons

inte

nsity

(tC

O2e

/ 1,

000

US

$ G

DP

)

TurkeyOECD Europe

0

2

4

6

8

10

12

1990 1993 1996 1999 2002 2005 2008

Em

issi

ons

inte

nsity

(tC

O2e

/ ca

pita

)

* At 2000 Prices Source: IEA, UNFCCC



vi

Investor Costs

In modelling investor behaviour we assume that producers or consumers choose the technologies that deliver the goods / services they require at the lowest cost, taking into account technical and standard cost characteristics such as up-front and operating costs, equipment lifetime, etc. We also assume that investors take into account a range of other factors that influence the attractiveness of investments in low-carbon and energy-saving technologies, including the costs of credit and other costs of capital, attitudes toward risk, and potential “transaction costs”. We distinguish project transaction costs, which are likely to be incurred to some extent for most investments, from policy-related transaction costs, such as the cost of participating in an emissions trading scheme or of obtaining government subsidies. And we develop estimates of the “hurdle rates” for different technologies, reflecting a range of different factors, including:

■ Cost of capital and terms of project finance ■ Risk associated with country, sector, technology and policy setting ■ Option value of waiting ■ Various categories of opportunity costs (of time, management attention, or other

investments in the context of scarce capital) ■ Individual preferences (of households) ■ Organisational failures and information asymmetries (split incentives, incomplete capture

of benefits, etc.)

The table below summarises our assumptions related to how the above factors affect decisions about which technologies to choose. The table shows the basic assumptions that we apply to investments involving low, medium, and high transaction costs and hurdle rates, and gives selected examples of abatement measures with these characteristics.

Transaction costs (share of capex)

Low (10-12%)

Large size (> €500k / > 5 MW ) and established supply chains and track record of past projects

Medium (15-20%)

Medium size (< €500k i/ < 5 MW), or larger projects facing weak supply chains or with low priority for organisation

High (20-30%)

Small scale (<€10k ) and / or facing communal / dispersed / split property rights or first-of-a-kind investments

Low

(1

0-12

%) T&D grid updates

New conventional power plant

Energy management systems Process control / automation

Energy efficient lighting

Mod

erat

e (1

5-20

%)

Wind-farms Nuclear Gas leakage Chemical processes New cement capacity District heating rehabilitation

Large heat pumps Biomass boilers Embedded generation Commercial / public building fabric

Reforestation Crop rotation Livestock methane capture

Hur

dle

/ dis

coun

t rat

es

(Cap

ital c

ost,

risk,

opt

ion

valu

es, e

tc.)

Hig

h (2

0-30

%) Carbon capture and

storage Waste handling Coal mine methane

Low-emitting car



vii

Policy Scenarios

The present analysis considers three policy scenarios and compares them to a hypothetical baseline under which Turkey’s economy grows as expected, but where emissions intensity remains “frozen” at current levels. The three scenarios analysed are:

■ Status Quo: Under this scenario current policies and institutions continue as they were in 2010. No new policies are put in place to encourage energy efficiency, renewable energy, or other emissions abatement options. Where policies and measures are already in place, they are not strengthened, and their effectiveness does not improve. It is assumed that nuclear power is not favoured by any Government support (despite the Government’s recently signed contract with Rosatom), and assume that government targets (e.g. for renewables) are not automatically met, unless policies that are currently implemented would deliver them. Continued limited enforcement of energy efficiency rules for buildings is assumed, with no dedicated policies to reduce emissions in industry or the waste sector. Technical progress, however, does occur, so new capacity is typically more energy efficient than existing capacity.

■ Planned Policies: The key assumptions are that the Government supports the development of a nuclear power programme through guaranteed price and off-take agreements, reducing the cost of capital. Feed-in-tariffs for renewables are also increased in line with those approved in December 2010, and interconnector capacity is added to facilitate cross-border trade in hydro-power with Georgia. Energy efficiency requirements, including enforcement of building regulations, are tightened, so that current rules are adhered to and the most inefficient building options are not permitted. Partial liberalisation of the gas sector does not deliver cost reductions to consumers and results in higher long-term gas prices.

■ Enhanced Policies: There are two variants of the “Enhanced Policies” scenario, which incorporates a range of policies designed to promote energy efficiency more forcefully and to further reduce emissions across the economy. The two variants share most features in common. In particular, they increase feed-in tariff support for renewable electricity. They assume completion of the liberalisation of the gas sector which results in increased competition and supply of natural gas. For buildings, they establishes a policy requiring energy suppliers to promote energy efficiency in homes and other buildings, create “soft-loan” programmes for energy efficiency, and phase out government policy to distribute free lignite for home heating. In industry, the scenarios establish targets to encourage benchmarking and sharing of best-practice, and they tighten the waste regime to encourage alternative uses of waste and less carbon intensive disposal.

The variants differ, however, in one of the mechanisms by which low-carbon technologies are supported. In the first (“Carbon Pricing”) variant, a carbon price of €40/tCO2e is applied to sectors that could be covered by the EU Emissions Trading System and a price of €20/tCO2e to sectors potentially eligible for emissions reduction credits. This carbon price could be implemented as a domestic cap and trade scheme linked to European Union Emissions Trading Scheme (EUETS) coupled with project based domestic offsets, or as a carbon tax, or some combination of the two for different sectors. In the second variant, instead of applying a carbon price to relevant sectors, the scenario supports abatement technologies using direct capital grants. These grants are assumed to cover 20 percent of the incremental capital cost of abatement technologies. In



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the power sector, very high efficiency CCGT is the only fossil-fired technology eligible for the grants.

Emissions Pathways

If the Turkish economy grew at a rate of around 4 percent annually over the period 2010-2030, but remained stuck at its current carbon intensity, its emissions would rise from 367 MtCO2e in 2008 to 590MtCO2e in 2020 and 852MtCO2e in 2030. Under the Status Quo scenario, technological improvements for new and replacement equipment reduces these emissions to 533 MtCO2e in 2020 and 741 MtCO2e in 2030. The Planned Policy scenario reduces emissions further – by around 44 MtCO2e by 2030 – primarily as a consequence of investment in nuclear and renewable power, as well as some increased uptake of building insulation and heating controls. The largest policy impact is in moving to the Enhanced Policy scenario, which has the potential to reduce emissions more than 200 MtCO2e by 2030 relative to planned policies. As noted above, these reductions come from a variety of sectors, with the most significant of these a large-scale shift away from solid fuels (both lignite and hard coal) in the power sector. But even the enhanced policies do not stabilise or reduce emissions of greenhouse gases in Turkey below current levels.

Figure ES.3 Emissions Projections Under Different Scenarios

0

100

200

300

400

500

600

700

800

900

1990 1995 2000 2005 2010 2015 2020 2025 2030

Em

issi

ons,

MtC

O2e

q

Static Technology

Policy Status Quo

Pledged policies

Enhanced policy

358%298%

275%

163%

590 MtCO2eq

852 MtCO2eq

MACC Results

The analysis presented here suggests that under the policy Status Quo, there is potential to reduce emissions in 2020 (relative to the “frozen technology” baseline) by around 57 MtCO2e (or nearly 10 percent below the 581 MtCO2e baseline), as presented in Figure ES.4, through profitable investments, even without a carbon price or additional climate policies. The potential emissions reductions rise to 111 MtCO2e in 2030 (around 13 percent below the baseline). Taking into account all measures, including those that have a positive cost (i.e. those that are not profitable without a carbon price or other supporting policy), the abatement potential more than doubles to 159 MtCO2 in 2020, and increases to 344 MtCO2 in 2030.



ix

In 2020, the average cost of profitable abatement measures is -€75/tCO2e. This falls to -€96/tCO2e in 2030. These measures yield a total “surplus” or profit in 2020 of €4 billion and €11 billion in 2030. Note that this profit relative to the alternative technologies in the sector is generally not realised immediately, but is earned over the life of the investment—for example energy is saved as a result of higher initial up-front expenditure. Across the entire MACC up to €150/tCO2 (in real terms), the average cost per tCO2e is €32 in 2020, and just €1 in 2030.

Figure ES.4 shows a high-level summary of the MACC for the Status Quo policy scenario.

Figure ES.4 MACC for Status Quo Policy Scenario (2030)

100

50

0

-50

-100

-150

-200

-250

-300 Abatement (tCO2)

300,000,000250,000,000200,000,000150,000,000100,000,00050,000,0000

Cofiring LigniteBuildings (R)

CCGT (Very-H)CCGT (H)

Landfill gasNuclear

Buildings (nR)

CCGT (Very-H)Nuclear

GeothermalWind (M)

Nuclear

Landfill gasBuildings (R)

150

GeothermalHydro (M)

CCGT (Very-H)

Buildings (nR)Gas pipelines - methane

Gas pipelines - methaneWind (M)

Hydro (H)

Municipal waste water

Buildings (R)Thermostats/heat allocators (R)

Cement

Buildings (nR)Buildings (R)

Road (P)Water heating (R)

Cement

Wind (H)

Pric

e (E

UR

)

WasteIndustryTransportPowerBuildings Notes: Categories of Power generation are labelled L (Low), M (Medium), H (High) and Very-H

(Very-high). Transport is divided between P (Passenger) and F (Freight). Buildings are R (Residential) or nR (non-Residential)

By 2030, the largest improvements in emissions intensity (relative to the intensity of the current economy) that occur under current conditions without any carbon price or other policies are in the power sector, in residential buildings, efficiency improvements expected from new passenger vehicles, and from industry.

■ For power, investments that contribute to lower emissions intensity include the development of renewable power plants (hydro and wind), and investment in more efficient natural gas power stations.

■ For residential buildings, there is significant abatement from the improved construction standards of new buildings, as well as refurbishment of existing dwellings with insulation, improved heating systems such as condensing boilers, and the uptake of solar water heating.



x

■ In industry, there is potential in a range of smaller sectors, as well as in cement, refining, and steel.

■ In the transportation sector, replacement of road vehicles with next-generation diesel and gasoline vehicles results in significant energy intensity reductions.

At positive carbon abatement costs there is very significant potential to reduce emissions further, through investments in additional gas-fired power generation, nuclear power, and renewables, further improvements to buildings, and investments in the waste sector and industry.

Under the Planned Policy scenario, nuclear power becomes a viable power generating technology even without a positive carbon price, because of implicit and explicit support for nuclear power. New feed-in tariffs approved by Parliament stimulate development of some more renewable power capacity. Improvements in the power distribution system also reduce electricity losses and result in emissions reductions. In addition, there is improved energy efficiency in buildings. These policies make viable additional investments delivering a further 54 MtCO2e of emissions reductions by 2030 (a further 9 percent reduction compared to the frozen technology baseline).

Under the Enhanced Policy scenario a large volume of additional measures that reduce emissions become commercially viable investments. These include additional investment in additional hydro, wind, and geothermal capacity, and in gas-fired power stations, which lead to very significant reductions in emissions from the power sector. Energy efficiency of buildings is also improved, and emissions from industry and the waste sector are reduced. These policies make commercially viable additional investments delivering a further 208 MtCO2e of emissions reductions by 2030 relative to the Planned Policy scenario (43 percent reduction compared to the frozen technology baseline). In the package of enhanced policies carbon price creates a strong incentive for abatement investments.

Some of the macroeconomic implications of the policy scenarios are summarised in Figure ES.5. In the Enhanced Policy scenario the incremental investment associated with the low-carbon measures corresponds to 3 percent of total investment, or €5bn per year. The associated operational savings from these investments correspond to around 3 percent of total consumption, or €19bn per year. The carbon revenues (defined as the volume of eligible abatement evaluated at the price of carbon allowances or credits) corresponds to 1 percent of total government revenues (this is for comparison only; the revenues may accrue to other parties, including firms, depending on the policy implemented).2 The capital grants programme would require €6 bn per year, on average, or an average of 5 percent of estimated government expenditure over the period to 2030.

2 This denomination is relevant to an arrangement whereby Turkey could obtain payment for the emissions reductions

relative to Status Quo, through international carbon markets or bilateral agreements. The associated revenue could accrue to government, or could be distributed to firms undertaking investments to reduce emissions. Note that the value of remaining emissions once emissions reductions have taken place is substantially higher. A carbon tax (or auctioning of allowances) at the prices assumed thus would result in substantially higher revenues, accruing in this case to government. With (some degree) of free allocation, some of this value could instead be captured by firms.



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Figure ES.5 Summary Macroeconomic Implications

Planned Policies

Enhanced Policies

2%

5%

1%

Capital grants as share of (estimated)

government expenditure to 2030

5%(€6.0bn)

Carbon revenues as share of (estimated)

government revenues in 2030

1%(€1.6bn)

Net operational savings as share of

(estimated) total consumption to 2030

3%(€19bn)

1%

Investment as share of (estimated)

gross capital formation to 2030

3%(€5bn)

1%

2%

Share to 2030, %(Avg. to 2030, €bn/yr)

Notes: The percentages show the total shares in the period 2010-2030, based on a continuation of current shares of capital formation, consumption, revenues, and expenditure in GDP. Opex savings exclude avoided carbon taxes and subsidies

Policy support: carbon prices versus investment grants

The Enhanced Policy scenarios show different uptake depending on whether carbon prices or capital grants are used. Carbon prices implemented through a cap-and-trade scheme provide an incentive to all sectors covered by the trading system – both a positive incentive (carbon revenues or some other financial return) for reducing emissions, and a negative incentive (opportunity cost) for non-abated emissions. In contrast, the capital grants approach can be thought of as providing positive benefits to investors who reduce emissions without the negative sanction for remaining emissions. Because only a positive incentive is offered, it requires comparatively greater financial incentives to achieve similar abatement.

In any actual implementation of such a policy, the level of support would need to be targeted and specified for the technologies of interest to the government. The analysis presented here assumes that any measure that reduces emissions is eligible for a uniform subsidy of 20 percent of capital expenditure, irrespective of the level of abatement potential. In combination, these factors mean that the amount of financial support required for the capital grants approach is around twice the level of support associated with the carbon price to achieve similar levels of abatement. The Carbon Prices scenario results in “carbon revenues” to the trading entities of €3 billion in 2030. These are the incremental financial transfers accruing to those who reduce emissions relative to the Planned Policies scenario. The Capital Grants scenario implies annual subsidies of €6.6 billion to 2030 paid by the taxpayers. By 2030 these correspond to 2 percent of projected government expenditure. In contrast, if



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carbon prices were to be applied using a carbon tax, this would yield nearly €10 billion in government revenues by 2030.

In practice, governments trying to reduce emissions from their economies have relied on both carbon prices for some sectors and capital grants for others– as well as renewable subsidies, efficiency policies, mandatory requirements, and standards. The policy tools used in Turkey will be developed in the national context and may reflect some combination of these different economic incentive approaches, so it is informative to consider both of them.

Conclusions

The impacts of climate change due to increased concentrations of greenhouse gases (GHGs) in the Earth’s atmosphere are a growing concern internationally. The Fourth Assessment Report of the Intergovernmental Panel on Climate Change, which offered a comprehensive summary of the state of scientific knowledge related to climate change as of 2007, projected very likely increases in extreme weather events, heat waves, heavy precipitation, and cyclones, as well as changes to snow and ice cover, rainfall patterns, and regional temperatures. These could, in turn, have potentially significant implications for the availability of fresh water, for food production and agriculture generally, and for the incidence of infectious diseases. While the economic and social impacts of these potential changes are very difficult to quantify, the possibility of adverse effects has prompted a wide range of countries with very different characteristics to call for increased attempts to reduce greenhouse gas emissions, in an attempt to slow or halt their effects on the climate.

The present report identifies substantial emissions reduction potential in Turkey, relative to the “frozen” and policy Status Quo scenarios. As an economy in transition, Turkey’s GDP per capita is expected to continue to approach typical European levels, and with this growth will come higher emissions. Because consumers in Turkey already face energy prices that largely reflect liberalised markets – and that in some cases are already higher than the EU average – the energy intensity of Turkey’s economy is not markedly higher than that of other major European economies. So while significant improvements in energy efficiency are possible, they are broadly in line with improvements in other European countries.

Choice of fuel in the power sector (and others) is a major determinant of Turkey’s future emissions trajectory. The power sector accounts for a substantial and growing share of emissions (currently 35 percent of combustion emissions), in part because demand for electricity is growing rapidly (at rates of 7-8 percent annually in recent years). In addition, the Government’s energy strategy targets the full exploitation of indigenous lignite reserves, largely for energy security reasons. This results in a significant increase in emissions. Limiting the use of solid fuels would therefore substantially reduce emissions. For such a scenario to be feasible, however, the government would need to significantly increase its efforts to promote the development of renewable and other low-carbon energy sources. In addition, policy-makers in Turkey would need to be convinced that they would have reliable and affordable access to significant natural gas supplies.

An alternative to the increased use of gas would be a future scenario in which carbon capture and storage (CCS) technology matured to the point where it could provide a credible way to reduce emissions at an affordable cost. This would make it possible to increase reliance on emissions-intensive, indigenous solid fuels while keeping final emissions low. Such a



xiii

scenario is highly speculative, however, as it depends on significant advances in CCS technology, including efficiency improvements and cost reductions.

Other sectors with significant abatement potential include the buildings sector, where policies to promote efficient heating systems and building design, insulation, and use of renewable energy could have a significant impact. In industry, particularly Turkey’s large cement sector, there is also scope for significant emissions reduction, but this would require action by the government to promote more efficient use of waste fuels and other waste products. Development of benchmarking programs for industry would also stimulate investment in abatement. There is also significant scope to reduce emissions from the growing road transport sector through improved vehicle standards.

In summary, carbon pricing of some form is likely to provide some of the strongest incentive to invest in abatement technologies, but targeted energy efficiency and other resource efficiency policies can also play an important role. The importance of the power sector means that a government commitment to nuclear power, as well as renewables, also can result in substantial abatement. The policies modelled here suggest that in theory capital grants could deliver abatement similar to carbon prices, but at significantly higher “subsidy” cost (€6 billion annually, rather than €3 billion), and with substantial effort to define all of the eligible technologies. In practice, a combination of measures is likely, but the choice of policies can make a significant difference to both their social cost and the sectors of most interest to investors.



xiv

Figure ES.6 Summary of Profitable Abatement, by Scenario

0

50

100

150

200

250

300

Status Quo Planned Policies Enhanced Policies -Carbon Prices

Enhanced Policies -Capital Grants

Pro

fitab

le A

bate

men

t, M

tCO

2eq

Buildings Power Transport Industry Waste

Note: Includes abatement from profitable measures.

Greenhouse Gas Abatement in Turkey Introduction

NERA Economic Consulting 1

1. Introduction

1.1. This Report

The purpose of this study is to investigate the potential to reduce greenhouse gas emissions in Turkey through investigation of abatement opportunities in individual sectors. The approach evaluates the abatement opportunities from the perspective of a potential investor who is interested reducing emissions, but who is primarily interested in earning a return on these (emissions reducing) investments.

We consider the abatement investment opportunities first in the context of the existing policy and institutional environment, and then under increasingly ambitious policies to reduce emissions. In each scenario, we consider what abatement opportunities investors would find attractive given the policies in place.

The model used was originally developed by Bloomberg New Energy Finance, and has been modified and updated over the course of the project. It represents the major sectors relevant to emissions across the economy. It can therefore be used develop projections of emissions, energy use, technology deployment across specific scenarios, and to compare difference scenarios to each other. It uses this underlying framework to create “Marginal Abatement Cost Curves” (MACCs) showing the emissions reductions that can be achieved at different carbon prices with different “abatement measures”. MACCs can serve an important role in policy analysis by identifying cost-effective opportunities to reduce emissions. They can also be used for a similar purpose by investors, to identify attractive investments in emissions reductions.

Box 1.1 Illustration of a Marginal Abatement Cost Curve

A MACC provides a convenient way of visualising opportunities to reduce emissions ranked in order of financial attractiveness. Each block in the MACC chart represents a particular technology or abatement measure. The width of the block indicates the volume of emissions reductions (i.e. “abatement”) that can be achieved through this measure. The height of the block represents the cost, per tonne of emissions reduced, of the measure. This cost should be understood as the cost relative to another option with higher emissions that the MACC measure is replacing. The cost is also a net cost that reflects differences – whether positive or negative – in both up-front and ongoing costs. For example, the higher incremental capital cost of more efficient equipment is offset, to varying extents, by savings on energy expenditure. The height of each block can be thought of as the “price of carbon” at which the given measure is preferred to the higher-emitting alternative.

The costs reflected in the MACC therefore must be calculated using as the starting point underlying engineering or project feasibility cost estimates, but taking into account the alternative technology, fuel prices, and other factors. Box 4.1 provides further details about how the alternative or “counterfactual” option (to which the abatement option is compared) is determined in our analysis.



The MACCs that we present in this report show the economically feasible abatement potential, in a particular year, at different costs of abatement. This is different from some MACCs, which show the theoretical abatement potential independent of time. For example, while it may theoretically be possible to replace all of the industrial capacity in a particular sector with the latest, most efficient technology, as a practical matter such replacement will occur over time and depending on economic circumstances – and ultimately, on the financial decisions of the investors who will actually finance the uptake of measures to reduce emissions. Our results therefore tend to show greater abatement potential over time, because there is greater opportunity to replace higher emitting technologies.

Figure 1.1 below shows a hypothetical MACC for a single year. The highlighted block shows an illustrative measure that improves energy efficiency. In the relevant year (in this example, 2030), it can deliver carbon savings of 10 million tonnes of CO2-equivalents, at a cost of €25/tCO2e.

Figure 1.1 MACC Illustration

3020100 706050 80 120110100

25 €/t

90

200

40

100

50

0

-50

150

-150

-300

Abatement (MtCO2)

130

-100

10 MtCO2

Price (EUR)Each block in the chart represents a particular technology or abatement measure.

The highlighted block shows an abatement measure.

In 2030, it can deliver carbon savings of 10 million tCO2e, at a cost of €25/tCO2e.

The cost shown is the net cost, relative to other options to produce the same output

The width shows the extent of emissions savings

1.2. National Energy and Emissions Profile

1.2.1. Energy consumption

The primary energy consumption of Turkey was 106 million tonnes of oil equivalent (Mtoe) in 2008, showing a slight decrease compared to 2007. Although in the past oil had been the largest energy source used in the country, from 2007 gas use has exceeded oil use (gas accounts for around 32 percent of primary consumption, and oil around 30 percent). The third important fuel was lignite, with a share of 15 percent.



Figure 1.2 Primary energy consumption

0

20,000

40,000

60,000

80,000

100,000

120,000

2003 2004 2005 2006 2007 2008

Pri

mar

y en

ergy

con

sum

ptio

n (k

toe)

Hard Coal Lignite Oil Natural Gas Hydro Wood Others*

Source: MENR Note: Others include asphaltite, secondary coal, pet-coke, wind, wastes, geothermal and solar energy

Final energy consumption (which accounts for the transformation of fuels into electricity, but excludes losses due to conversion in electricity generation and refineries) was nearly 83 Mtoe in 2007, falling to 80 Mtoe in 2008.



Figure 1.3 Final energy consumption

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

2003 2004 2005 2006 2007 2008

Fina

l Ene

rgy

cons

umpt

ion

(kto

e)

Hard Coal Lignite Oil Natural Gas Electricity Wood Others*

Note: Others include asphaltite, secondary coal, pet-coke, wind, wastes, geothermal and solar Source: MENR

Final energy consumption grew at a rate of 4.4 percent annually between 2003 and 2008 – again, falling slightly in 2008.

1.2.2. Historical Emissions Trends

Turkey prepares its greenhouse gas inventory and National Communication in line with the requirements of the UNFCCC. The inventory is prepared as a joint work by the Turkish Statistical Institute (TSI), Ministry of Agriculture and Rural Affairs, Ministry of Environment and Forestry (MEF), Ministry of Transportation, Ministry of Energy and Natural Resources, Turkish Technology Development Foundation and universities. Turkey submitted its first inventory in April 2006 and the most recent one in June 2010.

The 2010 inventory shows that the total level of GHG emissions has increased from 187 MtCO2eq in 1990 to 367 MtCO2eq in 2008, an increase of 96 percent. The annual growth rate of emissions during this period was 3.8 percent. In 2008, fuel combustion by all sources accounted for 76 percent of GHG emissions. Waste treatment ranked second after fuel combustion, with 9 percent. Industrial processes accounted for 8 percent and agriculture 7 percent. These figures exclude land use and land use change (including forestry) which accounted for net emissions reductions of 81 MtCO2eq. When land-use changes are included, total emissions in 2008 were only 286 MtCO2eq.



Figure 1.4 Historical Emissions Trends

0

50

100

150

200

250

300

350

400

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

MtC

O2e

q

Electricity & Heat Oil and Gas Solid Fuels MetalsMinerals Other Industry Transport BuildingsAgriculture Waste Other

Note: Excluding land use and land use change Source: UNFCCC inventory

CO2 has the highest share of GHG emissions, reaching 81 percent in 2008. CH4 accounted for 15 percent and N2O for 3 percent of emissions in the same year. The share of fluorinated gases (“F gases”) was just 1 percent. The table below shows the emissions by type of gas since 1990.

Table 1.1 Emissions by Greenhouse Gas and annual growth rate

MtCO2e 1990 1995 2000 2005 2008

Average Annual

change (%, 1990-2008)

Average Annual

change (%, 2000-2008)

CO2 141 174 225 260 297 4.2% 3.5%CH4 34 47 53 52 54 2.7% 0.2%N20 12 16 17 14 12 0.0% -4.4%F Gases 0.6 0.5 1.7 3.7 3.5 10.3% 9.8%Total 187 238 297 330 367 3.8% 2.7%

Note: Excluding land use and land use change Source: Turkstat – Greenhouse Gas Inventory of Turkey, 2010



Table 1.2 Emissions by category and annual growth rates

1990 1995 2000 2005 2008

Average Annual

change (%, 1990-2008)

Average Annual

change (%, 2000-2008)

Electricity & Heat 30.4 43.9 72.3 83.9 101.8 6.9% 6.7%Oil and Gas 3.7 3.6 4.7 4.9 4.5 1.1% 1.7%Solid Fuels 1.4 1.4 1.6 1.5 1.9 1.7% 2.3%Metals 10.6 11.5 12.2 12.2 13.1 1.2% 1.0%Minerals 13.7 17.5 18.1 22.5 26.3 3.7% 3.2%Other Industry 28.3 36.9 52.6 58.1 43.2 2.4% 1.2%Transport 26.3 33.3 35.5 41.3 47.8 3.4% 2.8%Buildings 26.7 29.0 29.6 33.1 51.7 3.7% 4.6%Agriculture 35.6 36.1 35.9 35.1 38.8 0.5% 0.6%Waste 9.7 23.8 32.7 33.5 33.9 7.2% 2.8%Total 186 237 295 326 363 3.8% 3.3%

Source: UNFCCC inventory. The figures differ marginally from those reported in the Turkish Inventory table, mostly because F gases are not included in this table and because of rounding errors.

1.2.2.1. Sectoral contributions to emissions

Official Turkish Government statistics group emission sources into four main groups of activities:

■ Energy covers emissions due to fuel combustion. It includes sub-sectors of power and heat production, oil refineries, industry, transportation, residential (including all building sector) and agriculture-forestry-fishery

■ Industrial processes cover non-combustion emissions from industry. It includes sub-sectors of mineral products, chemicals and metal industry.

■ Agriculture covers non-combustion emissions from agriculture.

■ Waste covers emissions from managed and non-managed solid wastes and waste-water.

As mentioned above, energy (fuel combustion) has the highest share in total emissions with 76 percent share. The power generation sector alone produced 37 percent of emissions from fuel combustion and 28 percent of total emissions. Combined heat and power accounted for only 3 percent of total generation in 2009.3 Rapidly increasing electricity demand in the country, i.e.7-8 percent per year with the exception of crisis years has led to increasing power generation mainly from thermal sources. Emissions from the power and heat sector increased from 30 MtCO2e in 1990 to 102 MtCO2e in 2008, with CAGR of 6.9 percent. Industry ranks second after power and heat, with a share of 20 percent, with around one-quarter of emissions from the iron and steel sector. Industry is followed by residential with 19 percent

3 There is no application of district heating in Turkey. Cogeneration facilities mainly serve the heat requirements of

industrial facilities.



and transportation with 17 percent. The chart below shows the sub-sectoral division of emissions resulting from fuel combustion.

Figure 1.5 Emissions due to Fuel Combustion by Sub-Sector

0

50

100

150

200

250

300

1990 2008

Ener

gy c

onsu

mpt

ion

(Mto

e)

Power and Heat Generation Oil refineries I&SOther Industry Transportation ResidentialAgriculture/Forestry/Fishery

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1990 2008

Ener

gy c

onsu

mpt

ion

(sha

res)

Note: Excluding land use and land use change Source: Turkstat – Greenhouse Gas Inventory of Turkey, 2010

The breakdown of emissions from fuel combustion shown in the figure above differs from the breakdown of total emissions shown in Figure 1.4, because some sectors have emissions other than from fuel combustion, for example, from industrial or agricultural processes or.

Emissions from wastes account for 9 percent total emissions. Around 90 percent of waste emissions are from solid wastes.

Industrial processes (as noted above, in addition to emissions from fuel combustion, which are accounted for separately) constituted 8 percent of total emissions. Among the industrial processes, cement production is the most emitting sector, producing 65-70 percent of industrial process emissions.

Non-fuel-related agricultural emissions account for 7 percent of total emissions (total agricultural emissions including fuel combustion account for 11 percent of emissions, as shown in Figure 1.4). The main sources of agricultural emissions are enteric fermentation and manure management.

1.2.3. Emissions Targets

Turkey has not set itself any explicit emissions reduction targets, either in an international or domestic context. (As discussed below, the government has set targets for renewable energy and energy efficiency, which have implications for emissions.)



Emission projections of Turkey are included in the National Communication of 2007. According to the Scenario 1 which assumes that no measures are taken to prevent emissions, greenhouse gas emissions will reach 655 MtCO2eq by 2020. This figure decreases to 619 MtCO2eq in Scenario 2, which assumes certain investments to reduce emissions. The cost of these investments was forecast in 2007 to be 100 Mn TL (around €55 million in €2007).

Scenario 2 is based on energy saving studies of the EIE4 of the MENR. This scenario was developed through a top-down approach, rather than by determining individual measures to achieve emission reductions. It assumes a reduction in power, industrial and residential emissions as a result of energy efficiency investments (including investments in machinery and equipment and infrastructure) between 2008 and 2020, but does not project beyond 2020. The scenario does not include any measures for the transportation sector.

Table 1.3 Greenhouse Gas Emission Projections

MtCO2e EmissionsImplied abatement from

measures2010 2015 2020 2015 2020

Scenario 1 – without measuresElectricity 117.8 159.4 220.1Industry 109.0 149.2 203.1Transportation 64.9 86.9 115.0Residential 61.6 78.2 96.9Agriculture 5.9 10.0 15.1Mining 1.9 3.1 4.4Total 361.1 486.7 654.6

Scenario 2 – with measuresElectricity 116.0 154.4 204.9 3.2 13.4Industry 106.8 141.9 187.9 5.0 12.9Transportation 64.9 86.9 115.0 - -Residential 60.8 75.7 91.8 1.7 4.4Agriculture 5.9 10.0 15.1 - -Mining 1.8 3.0 4.1 0.1 0.3Total 356.2 471.8 618.8 10.0 30.9

Note: Reported 2008 emissions were already higher than 2010 projections Source: National Communication of Turkey, 2007

The above forecasts suggest foresee that, if no measures are taken, power generation would constitute 34 percent of total emissions by 2020, industry 31 percent, transportation 18 percent, buildings 15 percent, agriculture 2 percent and mining 1 percent. If the measures foreseen in Scenario 2 are taken, this would lead 1 percent decrease in emissions in 2010 with respect to Scenario 1, a 3 percent decrease in 2015 and 5 percent decrease in 2020.

4 General Directorate of the Electrical Power Resources Survey and Development Administration



1.2.4. Energy and Emissions intensity

Total primary energy supply (TPES) per capita in Turkey in 2008 was 45 percent higher than 1990 levels, but was still only 1.4 tonnes of oil equivalent (toe) per capita. In contrast energy intensity per unit of GDP is quite high, at 0.26 toe /000 $ (at 2000 prices) in 2008, reflecting the country’s relatively energy intensive economy. TPES per GDP decreased only slightly between 1990 and 2008, by 8 percent, or approximately 0.4 percent per year. There is therefore still considerable potential for energy efficiency improvements.

Figure 1.6 Energy Intensity Measures for Turkey (1990-2008)

Energy use per $ GDP Energy use per capita

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

0.20

1990 1993 1996 1999 2002 2005 2008

Ene

rgy

inte

nsity

(toe

/ 1,

000

US

$ G

DP

)

TurkeyOECD Europe

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

1990 1993 1996 1999 2002 2005 2008

Ene

rgy

inte

nsity

(toe

/ ca

pita

)

* At 2000 Prices Source: IEA; GDP is in 2000 prices, and PPP-adjusted

In per capita terms Turkey’s energy intensity is less than one-third of the OECD average (4.6 toe per capita) and just 40 percent of the OECD Europe average of 3.4 toe/cap. As a proportion of GDP (adjusted for purchasing power parity), Turkey’s energy intensity was 0.12 toe per thousand 2000$ in 2008. This was 13 percent lower than the OECD Europe average that year. Turkey’s energy intensity per PPP-adjusted $ GDP has remained relatively steady over the last two decades, while the European average has been falling. Turkey’s energy intensity therefore reflects its low GDP per capita relative to OECD Europe, but otherwise suggests that the economy is neither dramatically more or dramatically less energy intensive, relative to the value of output, than OECD European countries.

Turkey’s per capita emissions are also lower than OECD and European averages, even though per capita emissions increased 50 percent from 1990 to 2008, from 3.4 tCO2eq/cap to 5.1 tCO2eq/cap. Emissions per GDP (in PPP-adjusted 2000$) have remained relatively stable over the 1990s, but since 2000 appears to show a slight downward trend.



Figure 1.7 Emissions Intensity in Turkey and OECD Europe (1990-2008)

Emissions per $ GDP Emissions per capita

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

1990 1993 1996 1999 2002 2005 2008

Em

issi

ons

inte

nsity

(tC

O2e

/ 1,

000

US

$ G

DP

)

TurkeyOECD Europe

0

2

4

6

8

10

12

1990 1993 1996 1999 2002 2005 2008

Em

issi

ons

inte

nsity

(tC

O2e

/ ca

pita

)

Source: IEA and UNFCCC. GDP is in 2000 prices, and PPP-adjusted

Greenhouse Gas Abatement in Turkey Investor Behaviour


2. Investor Behaviour

2.1. Transaction costs and hurdle rates

In addition to estimates of capex and opex characteristics of investments, we have made estimates of additional costs and other factors that influence the attractiveness of investments in low-carbon and energy-saving technologies. We provide a brief summary below, with a more extensive account of the approach taken in Appendix B

We distinguish two main categories of influences:

■ Transaction costs. These are broadly defined to encompass additional costs incurred in undertaking an investment. We distinguish between the following:

- Project transaction costs. These may include investment appraisal (time costs, consultancy fees, feasibility studies, overheads), procurement and legal costs (contracts, negotiation, search for vendors), compliance costs (e.g., permits, applications) and bribes.

- Policy-induced transaction costs. Costs that arise because of a policy intervention or requirements. These include a range of administrative costs under credit-based emissions trading, as well as costs of adhering to administrative costs arising from subsidy programmes or regulatory requirements.

■ Hurdle / discount rates. A variety of factors influence the (implied) hurdle / discount rates applied by households and firms when evaluating investment options. Important factors include:

- Cost of capital and terms of project finance

- Risk associated with country, sector, technology and policy setting

- Option value of waiting

- Various categories of opportunity costs (of time, management attention, or other investments in the context of scarce capital)

- Individual preferences (of households)

- Organisational failures and information asymmetries (split incentives, incomplete capture of benefits, etc.)

2.2. Factors affecting transaction costs and hurdle rates

Our general principles in estimating transaction costs and discount rates have accounted for the following factors:

■ Project size. Many costs are incurred on a “per-project” basis, so that the costs are proportionately smaller for larger projects.

■ Supply chains and infrastructure: transaction costs are larger for investment in technologies that do not have an established track record in the country / sector.

■ Ownership structure: dispersed, split, or communal ownership can substantially increase the transaction cost of investments. This is relevant to measures in agriculture / forestry, rented buildings, or communal buildings.

Greenhouse Gas Abatement in Turkey Investor Behaviour


■ Regulation: various regulations can increase the cost of projects substantially. An example is the use of any materials classified as wastes, or investments with significant impact on local pollution.

■ Fit with overall organisation activity: costs are likely to be higher for organisations whose commercial focus is not on emissions / energy, than for energy-intensive industry. Likewise, a large literature documents households’ general lack of attention to the potential for savings on energy expenditure.

■ Dependence on policy: Both costs and risk are likely to be higher when the viability of the investment depends on specific government policies that are subject to change. Examples include renewables whose viability depends feed-in tariffs, or investments that have no benefit other than emissions reductions (e.g., carbon capture and storage).

2.3. Summary: Investor behaviour

The below table summarises the assumptions, showing low, medium, and high transaction costs and hurdle rates, and gives selected examples of abatement measures with these characteristics.

Transaction costs (share of capex)

Low (10-12%)

Large size (> €500k / > 5 MW ) and established supply chains and track record of past projects

Medium (15-20%)

Medium size (< €500k i/ < 5 MW), or larger projects facing weak supply chains or with low priority for organisation

High (20-30%)

Small scale (<€10k ) and / or facing communal / dispersed / split property rights or first-of-a-kind investments

Low

(1

0-12

%) T&D grid updates

New conventional power plant

Energy management systems Process control / automation

Energy efficient lighting

Mod

erat

e (1

5-20

%)

Wind-farms Nuclear Gas leakage Chemical processes New cement capacity District heating rehabilitation

Large heat pumps Biomass boilers Embedded generation Commercial / public building fabric

Reforestation Crop rotation Livestock methane capture

Hur

dle

/ dis

coun

t rat

es

(Cap

ital c

ost,

risk,

opt

ion

valu

es, e

tc.)

Hig

h (2

0-30

%) Carbon capture and

storage Waste handling Coal mine methane

Low-emitting car

Greenhouse Gas Abatement in Turkey Overview of Approach to Policy Scenarios and Assumptions


3. Overview of Approach to Policy Scenarios and Assumptions

We consider three scenarios to estimate the potential for emissions reductions in Turkey under different very high level policy settings.

■ “Status Quo” scenario, in which policies and institutions in Turkey continue as they currently are over the next two decades, but technological improvement and natural turnover of equipment is allowed to occur.

■ “Planned Policy” scenario, in which planned but not-yet-implemented policies to reduce emissions are included.

■ “Enhanced Policy” scenario, in which additional policies to spur emissions reductions are reflected.

Some details of the three scenarios are provided below, with a summary of the key differences between them.

3.1. Status Quo Scenario

Our base scenario is the “Status Quo”. It assumes that over the next two decades current policies and institutions continue as they are now. There are no new policies put in place to encourage energy efficiency, renewable energy, or other emissions abatement. Where policies and measures are already in place, they are not strengthened, and their effectiveness does not improve.

For example, in Turkey, the power market is relatively competitive, with liberalisation and privatisation of remaining government assets underway. Demand is expected to continue its recent rapid growth, and this has led the government to be concerned about rising dependence on gas imports. The power market is characterised by the persistence of long-term contracts between generators and state-run wholesale power trading company TETAS, most of which are due to finish by 2020.

The government has announced a target to reduce the share of gas in generation from 50 percent to just 30 percent by 2023 (MENR 2009)5, even as capacity is expected to roughly double. In an effort to diversity its fuel mix, the government has said it intends to expand its use of indigenous lignite reserves (MENR 2009). The government has also signed a contract with Rosatom to build Turkey’s first nuclear power plant, with 4.8 GW capacity6 at Akkuyu. Construction is not due to start until 2013. In the status quo scenario, however, we assume that no specific policies promote the use of lignite or limit the use of gas, and we omit the Akkuyu reactor from projections.

The government has also announced ambitious aspirations for the development of renewables, including wind power and hydro power (MENR 2009). The hope is that by 2023, Turkey

5 Ministry of Energy and Natural Resources, Electricity Energy Market and Supply Security Strategy Paper, May 2009 6 Unless otherwise noted, capacity figures for power generation sites refer to electrical capacity.



will generate 30% of its electricity from renewable sources. This includes the aspiration to add 20 GW new wind capacity by 2023 (compared to 1.1 GW capacity in 20107), and to fully exploit economically feasible hydropower (on the order of 30 GW, or around twice current capacity). Prior to the December 2010 revision to Feed-In-Tariffs, however, the government’s renewable energy law set fixed subsidies below the wholesale price of power. In the status quo scenario we assume that no additional support is provided for renewable power projects. We therefore assume that development of new capacity can proceed at a pace similar to that observed in the past few years – subject to viable sites being available to develop.

Turkey has various policies in place that are intended to encourage energy efficiency in buildings, but in general building regulations are not strictly enforced, and there is still significant construction without all official permits. Under the Status Quo current practice remains the norm.

3.2. Currently Planned Policies

The second scenario takes into account major policies that are in place or announced that are likely to have an effect on emissions. Where policies currently exist but are not well enforced (as in the case of building standards) we assume that they are enforced more strictly.

Differences between this scenario and the status quo include:

■ Government price guarantees, contracts, and borrowing rates are used to underwrite new nuclear power (we assume a 7 percent discount rate and reduction of transaction costs), and the government assumes liability for decommissioning and long-term waste disposal;

■ Completion of interconnector between Turkey and Georgia to allow Turkey to import hydro power (up to 1.7 GW, or 5 TWh) from Georgia;

■ Government feed-in tariff policy is strengthened to provide incentives to develop renewable power;

Table 3.1 Feed-In-Tariff Levels

Technology FIT (€/ MWh) Wind Hydro

55

Geothermal 80 Solar Biomass

100

- The new FIT policy provides additional payments for renewable electricity output generated by facilities containing equipment produced domestically. We have not included this additional payment in our analysis for two reasons – first, because the higher subsidy may be required to allow domestic producers to become competitive, and second, because of the possibility that equipment producers may be able to extract higher prices from customers if customers expect to receive higher subsidy payments.

7 Turkish Wind Energy Association.



■ Energy efficiency regulations are strengthened, including:

- Information and energy performance certification schemes to reduce transaction costs, along with agreed standard assessment procedures and methodologies, such as ISO EN,

- Better enforcement of building regulations, including mandatory inspections, leading to greater uptake of e.g. shared heating systems with higher efficiency, condensing boilers, insulation, and heat meters;

■ Partial liberalisation of gas market through selective sell-off of BOTAS contracts leads to somewhat higher prices (otherwise there is limited new entry) – gas prices gradually increase from 2016-2020 to 10 percent higher than current retail and wholesale levels relative to Status Quo scenario.

3.3. Enhanced Policies

In Enhanced Polices scenario, we consider the implications of a range of policies designed to promote energy efficiency and to reduce emissions from the power and other sectors. In particular:

■ Higher feed-in tariff rates to promote additional renewable resource development. Tariffs are increased relative to the Planned Policies scenario by a further €15/MWh, which serves to promote additional capacity at some locations, but does not incentivise all measures.

Technology FIT (€/MWh)

Wind 70 Hydro 70 Solar 115 Biomass 115 Geothermal 95

Other 70

■ More complete liberalisation of gas market, with entry of major international rivals to BOTAS provide significant competition and long-term benefits to consumers, reducing gas prices and reversing trend to higher gas prices under previous scenario;

■ Additional requirements to consider alternative energy systems in buildings (essentially imposing transaction costs in all cases, and therefore eliminating them as an additional cost for low-carbon measures), along the lines of EU Directive 2010 / 31 on the energy performance of buildings;

■ “Soft loan” programs and expansion of commercial lending opportunities to support household energy efficiency measures, including insulation, solar thermal hot water heating;

■ Obligations on energy suppliers to deliver energy efficiency measures – e.g. via quotas, demand-side management, or white certificate programmes to further support energy efficiency measures in the household and commercial sectors.



■ Industrial benchmarking program designed to share best practice and focus management attention on efficiency improvements (reduces informational transaction costs and reduces hurdle rates by 2%).

■ Tighter regulation of waste to reduce cost of energy-from waste-options, including landfill gas use, use of waste fuels in cement kilns, etc.

■ Phase out of program to provide free lignite to households; replace with more general home heating support policy or general income support.

■ The above policies are combined with one of two further policies, leading to two variants of the Enhanced Policy scenario.

■ The first variant applies a significant carbon price. For sectors that would be covered by the EU ETS this is assumed to be €40/tCO2 in real terms; for sectors that would be eligible to earn CERs, ERUs or equivalent credits, the price (or opportunity cost) is assumed to be €20/tCO2e. The difference between the two prices reflects the risks and transaction costs associated with primary credits.

The second variant, instead of applying the above carbon prices, assumes that a capital grant subsidy is available to every technology that reduces emissions relative to the standard technology in the sector. This subsidy reduces the up-front capital cost of lower-emitting technologies to investors by 20 percent. The source of the capital required to finance the capital grants is not specified.

Both the carbon pricing and the capital grants policies provide support and incentives to develop low carbon technologies. These policies could be implemented in different ways, and the current study models them without too much complexity. With carbon pricing, questions of free allocation and details of specific baseline and crediting approaches are not considered. With capital grants, any technology with lower emissions than the reference is assumed to be eligible for the 20 percent grant. Although there are many international examples of capital grants (often implemented through tax allowances or exemptions), none is nearly as comprehensive or far-reaching as the intervention modelled here, and most have detailed rules specifying how a technology is to be judged to be eligible.

Comparing the results for the two Enhanced Policy variants nevertheless provides a useful insight into the effectiveness of these two approaches.



3.4. Summary Overview of Scenarios

An overview of the scenarios is provided in brief summary below.

Table 3.2 Summary of Modelling Scenarios

Policy Status Quo Planned Policy Enhanced Policy – Carbon Prices

Enhanced Policy – Capital Grants

Fuel market structure and subsidies

Hard coal Continued state support for hard coal mines

Support phased out, but no impact on prices (set by imports)

As in Planned Policy Scenario

As in Enhanced Policy Scenario

Electricity cross-subsidy

Continued cross subsidy of non-industry by industry

Price differential between industry and residential / commercial sectors increased by €0.02/kWh



Distribution Limited loss reduction

Cost-effective investment to go ahead to reduce losses from 14% to 9%



Gas market structure

Continued BOTAS dominance, gas prices rise over time

Partial gas market liberalisation, leading to 10 percent higher gas prices by 2020

More liberalised market with greater competition and entry, prices 10 percent lower than Planned Policies


Lignite subsidy to poor households

Continued subsidy of 2 million households

Continued subsidy of 2 million households

Policy phased out and replaced by other income support without impact on relative fuel prices


Power Sector

Gas share of generation

Broadly matches current mix until 2020, then falls on higher prices

Falls on higher prices sooner, achieving government 30% target

No limitation on gas share.


Lignite share of generation

Use of proven lignite reserves, estimated at 18 GW of electricity generation capacity

As in Status Quo Scenario



Hydropower Continued tendering but no direct financial support




Feed-in tariffs Current feed-in tariff levels (largely

Recently announced proposed FIT revisions

Higher FITs, up to €15/ kWh higher than in PP






Renewables grid connection and transmissions charges

Implicit support by imposing no additional grid connection or transmission charges




Interconnectors Current interconnection capacity

Additional capacity and hydropower imports from Georgia of up to 1.7 GW



Nuclear power No nuclear power programme

State-supported nuclear power programme, up to 5 GW in 2023, 15 GW in 2030



Carbon pricing No carbon price No carbon price Inclusion of sector in EU ETS with exposure to €40 / tCO2 carbon price

No carbon price

Capital grants for abatement technologies

None None None In alternative “Capital Grants” Enhanced Policy scenario, carbon price on emissions is replaced by 20% capital grant for abatement technologies

Household and Buildings sector

Building regulations

Building regulations for new buildings, boilers, and heat meters in place but not effectively enforced

Effective enforcement of buildings regulations



Gas network Trend of increased gas use continues with gradual expansion of gas network




Energy efficiency policies

No additional energy efficiency policy


Extensive energy efficiency policy programme through combination of “soft” loans, obligations, and energy audits.



None None None 20% capital grant for abatement technologies

Industry

Energy efficiency No additional policy No additional Benchmarking and target programme

As in Enhanced





policy policy helps disseminate information about best practice and focus management attention.

Policy Scenario

Carbon pricing No carbon price No carbon price Eligible sectors included in EU ETS with exposure to €40 / tCO2 carbon price

No carbon price


None None None In alternative “Capital Grants” Enhanced Policy scenario, carbon price on emissions is replaced by 20% capital grant for abatement technologies

Transport

Fuel taxes Continued high taxes for transport fuels




None None None 20% capital grant for abatement technologies

Agriculture, Waste, forestry

Carbon pricing No carbon price No carbon price Eligible projects exposed to credit-based emissions trading corresponding to €20 / tCO2 carbon price

No carbon price


None None None Carbon price is replaced by 20% capital grant for abatement technologies

3.5. Fuel Price Assumptions

The figures below show the fuel prices (in real €2010) that we assume for different sectors under the Status Quo scenario. In general, we begin with wholesale price projections and scale these to end-user prices based on current (and where relevant historical) price data. We use IEA forecasts of gas prices (WEO, 2010), which start from relatively low current levels and rise over the period. Coal prices are also based on IEA projections, with an additional transport cost for Turkey. Lignite prices assume costs in Turkey remain broadly at current levels (again, from IEA data) in real terms. Biomass prices start at current low levels, reflecting primarily traditional uses of the fuel and limited use in the power sector, but prices rise to reflect expected increasing international trade in biomass fuel as a low-carbon energy commodity. Wholesale electricity prices are modelled, with end-user power prices scaled up based on historical retail costs.



Figure 3.1 Fuel Price Assumptions

050

100150200250

2010 2015 2020 2025 2030

Coa

l pric

e (€

/tonn

e)

Power Industrial Com/Res

01020304050

2010 2015 2020 2025 2030

Gas

pric

e (€

/MW

h)

Industrial/Power Com/Res

0

500

1,000

1,500

2010 2015 2020 2025 2030

Oil

pric

e (€

/tonn

e)


0

20

40

60

80

2010 2015 2020 2025 2030Biom

ass

pric

e (€

/MW

h)


0

10

20

30

40

2010 2015 2020 2025 2030

Lign

ite p

rice

(€/to

nne)

Power Industrial

0

5

10

15

20

2010 2015 2020 2025 2030

Elec

trici

ty p

rice

(0.0

1€/k

Wh)

Industrial Com/Res

Source: IEA (coal, gas, oil), E4Tech (biomass), IBS (lignite) supplemented by NERA/BNEF estimates and modelling.

As discussed above, under the Planned Policies scenario, the spread between residential and industrial power prices increases. Gas prices to end-users increase under this scenario because of continued limited competition.

Under the Enhanced Policy scenario prices are similar, although gas prices are lower by 10 percent to reflect the benefits to consumers of more complete liberalisation of the market. Coal and oil prices continue to reflect the price of international imports.

Appendix C provides details on fuel price assumptions for each scenario.

Greenhouse Gas Abatement in Turkey Policy “Status Quo” Scenario


4. Policy “Status Quo” Scenario

Our base scenario is the “Status Quo”. It assumes that over the next two decades current policies and institutions continue as they are now. The economy continues to evolve, with emissions abatement potentially available both through the addition of new, more efficient or low-emitting capacity, and through the gradual adoption of technologies and practices to reduce emissions. However, there are no new policies put in place to encourage energy efficiency, renewable energy, or other emissions abatement. Where policies and measures are already in place, they are not strengthened, and their effectiveness does not improve.

This chapter first sets out in some detail the policy assumptions used to construct the Status Quo scenario.8 Section 4.2 presents an overview of the abatement potential across the economy – including an overview (Box 4.1) of the methodology used to produce the MACCs. Subsequent sections provide further details of abatement cost and potential for the main sectors.

4.1. Policy Setting and Assumptions

We provide below a brief summary of the policy assumptions in the Status Quo scenario. More extensive background and assumptions can be found in the Appendices.

4.1.1. Fossil fuel markets and subsidies

Turkish fuel and power markets are relatively liberalised, with little direct intervention in the form of subsidies or cross-subsidies. However, some legacy features of earlier systems persist. The following are the key remaining elements to consider in an evaluation of abatement potential and cost:

■ Free lignite to poor households. The scenario includes continued provision of more than two million tonnes of lignite per year for free to poor households.

■ Support for coal mining. Domestic hard coal mining receives substantial subsidy, in part to cover its legacy employment costs. However, we assume this has limited no impact on coal end-user prices, which are determined instead by the much larger quantity of imported coal.

■ Cross-subsidy of electricity. the current regulatory structure leads to a relatively small difference between the electricity end-user prices faced by industry and the residential and commercial sectors, at around €0.02-0.03/kWh (typical values for other countries are often twice as large). This is likely to constitute an implicit cross-subsidy, with industry paying a proportionally larger share of transmission and distribution costs.

■ Gas market structure. The domestic gas market is dominated by BOTAS. The scenario assumes this situation continues, resulting in gas prices that are somewhat lower than they

8 Note that since 2002 Turkey has enjoyed a period of relative monetary stability, following substantial volatility and

high inflation in the period preceding that. We assume for our analysis that the current stability persists, and with it the relatively low interest rates that the country currently enjoys. If circumstances changed this could have a substantial effect on investor decisions.



otherwise would be (due to BOTAS’s ability to benefit from legacy take-or-pay gas contracts in the power sector)

4.1.2. Power sector

In the power sector, we make the following assumptions about policies.

4.1.2.1. Market structure

Competitive markets. We assume that the process of liberalisation continues, with new capacity incentivised through a combination of private investment and competitive government procurement (e.g. for hydropower and lignite fields for power generation). Existing long-term contracts are maintained but constitute a decreasing share of the total, but new investment decisions determined on a competitive basis and compensated through revenues in the wholesale market.

4.1.2.2. Energy security targets for fossil fuels

The Turkish government has set aspirations to reduce reliance on imported energy and to achieve a more diverse energy mix. The most relevant targets include:

■ Limited gas share in generation. The Turkish government recently sharpened its target to limit the share of gas-fired plant in generation to no more than 30 percent. We assume this target is assumed, through a combination of permitting / regulation and support for other plant.

■ Development of domestic lignite resources. We also assume that the aspiration to bring proven lignite deposits can be realised through. This makes available up to 18 GW of electric generating capacity by 2030.

4.1.2.3. Renewable electricity

The support structure for renewable electricity generation has three main components.

■ Maintained feed-in tariffs. The scenario includes feed-in tariffs (FITs) maintained at current levels and eligibility. Where wholesale prices are higher than FIT levels, renewable generation plant has the option of selling their output in the wholesale market instead.

■ Continued hydropower tendering. The ongoing process of tendering for hydropower development continues, with potential for development of up to 30 GW of available potential. Currently not financial support is provided (on the contrary, hydropower developers bid for their right to develop sites), and we assume that only investments viable under prevailing wholesale market conditions are undertaken.

■ Implicit support for renewables. We assume that “soft” support for renewables continues. This means that no additional cost incurred by renewables requiring remote transmissions grid connections or imposing system balancing costs resulting from intermittent generation.



■ Constrained wind power development. Finally, we assume that licensing delays and transmission constraints continue to limit on the pace of development of new wind power capacity.

4.1.2.4. Nuclear power

Only private nuclear power. The scenario does not include a state-sponsored nuclear power programme. However, we assume a permitting regime is in place to allow privately financed nuclear developments to come forward if sufficiently financially attractive. Transaction costs are assumed to be high, especially given the lack of precedent for nuclear power development in the country.

4.1.2.5. Interconnector capacity

Maintained interconnector capacity. The scenario assumes no expansion of the current interconnector capacity with other electricity markets.

4.1.3. Buildings

Weak enforcement of building regulations. As discussed above, the status quo in the buildings sector assumes little change relative to current trends and practices. Currently buildings in Turkey have limited insulation, and upgrading existing buildings is occurring, but only gradually. Building efficiency standards are not enforced, and uptake of mandatory equipment, such as heat meters in buildings served by shared heating systems, is very slow.

Expansion of gas network. In the Status Quo scenario we assume that gas continues to be available for heating use and that its use can expand to those who have not yet switched to it. We assume that the penetration of air conditioning increases gradually from current levels to approach the current average in Southern Europe (around 30 percent in households).

Fuel prices are as described above.

4.1.4. Other major emitting sectors (Industry, Transport, Waste and Agriculture)

Continued taxes and road transport dominance. In the transportation sector, the scenario includes continuation of prevailing high fuel taxes, as well as vehicle taxes. There is no policy to change the current heavy reliance on road transport for freight and passenger traffic.

Weak waste regulations and institutions. Current waste regulation and infrastructure is assumed to be insufficient to enable many of the potential abatement options that rely on special treatment of various waste streams. This includes insufficient institutions to support landfill gas capture or energy from waste. Similarly, we assume no significant availability of waste streams for combustion in industrial processes, or substitution in cement blending.

No specific industrial energy policy. Industry is assumed not to be subject to any additional incentives or enabling factors to reduce emissions beyond those provided through the price of energy.



4.2. Policy Status Quo: Overall MACC

We present here the overall marginal abatement cost curve results under the Status Quo scenario. Box 4.1 provides an overview of the methodology used to create the MACCs presented below.

Box 4.1 Explanation of MACC Methodology

The MACCs we present below have two distinct areas – the positive cost portion and the negative cost portion. The negative cost portion of the MACC represents investment opportunities that would be taken without a carbon price or further support mechanisms (beyond those already in place). The height of the bars represents the savings per tonne of CO2e reduced. In contrast, the positive cost portion shows abatement measures that would only be profitable if there were a carbon price that was high enough (or some other policy that affected the costs of the abatement measure and/or those of competing technologies).

The methodology for producing the two areas of the MACCs differs. To produce the positive cost portion of the MACC, we run the GE2M model at successively higher carbon prices and compare the types of technology in each sector that are used to create the projected output. As the carbon price increases from model run to model run, less carbon intensive technologies are preferred, and are built (or run more) at the expense of more carbon intensive technologies. When the output from a technology increases from a lower carbon price to a higher carbon price, this indicates that at the new higher carbon price, the low-carbon technology is preferred and therefore represents an abatement measure with a cost per tonne less than or equal to the new carbon price. The volume of abatement (the width of the bar in the MACC) is determined by comparing the emissions intensities of the low-carbon technology to the technology that it displaces. We repeat the process, running the model at successively higher carbon prices, up to €150/tCO2e (in 2010 €), with the modelled economy progressively decarbonising as the carbon prices increase.

The negative cost portion of the MACC is produced using a different approach – one that is more similar to traditional approaches to calculating abatement costs for a MACC. In essence, we compare a single model run (from 2010-2030) with the carbon price set to zero to what the economy would look like if the technologies used – and their carbon intensity – were identical in every future year to what is used now. We call this fixed carbon intensity scenario the “Static Intensity” scenario. It is the reference case for identifying opportunities for emissions reductions that are profitable even now.

To calculate the benefit of investing in profitable emissions reductions relative to the "Static Intensity" scenario, we have first selected the relevant “counterfactual technology” in the Static Intensity scenario and compared this to the technologies in each corresponding sector that reduce emissions. For upgrades to existing equipment, the counterfactual should be the existing equipment: the capital cost is then the cost of the upgrade in the year of the analysis (e.g. in 2030), and the annual operating cost savings is the difference between the operating cost of the new and old equipment. The emissions benefit per unit of output is the difference between the emissions intensity of the old and new equipment.



For new (or replacement) equipment, the methodology is somewhat more complicated. The counterfactual here is defined as an “average characteristics” of the capacity that is in place in 2010. So, for example, in the power sector, approximately half of current electricity production is from natural gas, and a quarter each is from solid fuels and large hydroelectric power plants. In the Static Intensity scenario, we assume that capacity would be built in exactly these same proportions to meet any new demand. In the policy scenarios, we therefore compare any new capacity to this “Static Intensity Average”. The emissions savings per unit of new capacity is therefore the difference between the emissions intensity of the new technology and the weighted average intensity of the existing capacity – which does not change over time. The incremental cost of the new technology is calculated as the weighted average of the capital costs of each technology in each year that the MACC is calculated. So the counterfactual cost in 2030 is based on market shares from 2010 but costs in 2030.

The reason for taking this approach is that the current production mix already includes some low-carbon technologies, and these would be part of the hypothetical “Static Intensity” future. If we did not treat the overall average as the counterfactual, for each new scenario we would have to arbitrarily choose which of the existing “Static” technologies was being replaced. So, for example, if the model predicted construction of new efficient gas-fired power plants, we would have to decide whether this was built instead of a new coal plant, or a new hydroelectric plant, or possibly was simply the gas plant that would have been expected anyway under the Static Intensity scenario.

This approach gives the cost of using abatement technologies to reduce emissions, relative to what would have been built instead (on average) in the Static Intensity scenario. Where there is expected to be technical progress in abatement classes that reduces their cost, but more limited progress in more conventional (counterfactual) classes, the methodology allows for the possibility that abatement classes may actually have lower capital costs than the counterfactual. Moreover, because in some sectors the average counterfactual may be a mix of some capital intensive and some less capital intensive measures, it is not always the case that the abatement class will have a higher capital cost than the counterfactual. In some sectors these considerations may reduce the incremental capital cost that would be calculated if a different counterfactual methodology were used. In addition, the application of the two different methodologies to the positive and negative portion of the MACC means that the counterfactuals in the two areas will not be the same, and therefore the same abatement measure may be shown as having different abatement properties depending on whether it is built at a positive or negative abatement cost.



Figure 4.1 Full MACC, Status Quo, 2020

Landfill gasMunicipal waste water

Road (F)Buildings (R)

Municipal waste waterHydro (H)

Gas pipelines - methane

Geothermal

150

100

50

0

-50

-100

-150

-200

-250



120,000,000100,000,00080,000,00060,000,00040,000,00020,000,0000

Nuclear

CCGT (M)

Geothermal

Buildings (R)

CCGT (M)CCGT (H)

BricksLandfill gas

NuclearBuildings (nR)

Buildings (R)

Acid

Hydro (H)Wind (H)

Buildings (nR)CCGT (Very-H)

CementBuildings (R)

Thermostats/heat allocators (R)Buildings (R)

Road (P)Buildings (nR)

SteelCement

Water heating (R)

Pric

e (E

UR

)

WasteIndustryTransportPowerBuildings Notes: 1. Categories of Power generation are labelled L (Low), M (Medium), H (High) and Very-H (Very-high).

Transport is divided between P (Passenger) and F (Freight) Buildings are R (Residential) or nR (non-Residential)

Figure 4.2 Full MACC, Status Quo, 2030

100

50

0

-50

-100

-150

-200

-250


300,000,000250,000,000200,000,000150,000,000100,000,00050,000,0000

Cofiring LigniteBuildings (R)


Landfill gasNuclear

Buildings (nR)


GeothermalWind (M)

Nuclear

Landfill gasBuildings (R)

150

GeothermalHydro (M)

CCGT (Very-H)

Buildings (nR)Gas pipelines - methane

Gas pipelines - methaneWind (M)

Hydro (H)

Municipal waste water


Cement



Cement

Wind (H)

Pric

e (E

UR

)

WasteIndustryTransportPowerBuildings Notes: 1. Categories of Power generation are labelled L (Low), M (Medium), H (High) and Very-H (Very-high).

Transport is divided between P (Passenger) and F (Freight) Buildings are R (Residential) or nR (non-Residential)



Our analysis suggests that under the policy Status Quo, there is potential to reduce emissions in 2020 (relative to the “frozen technology” baseline) by around 57 MtCO2e through profitable investments, even without a carbon price or additional climate policies. The potential emissions reductions rise to 111 MtCO2e in 2030. Taking into account all measures, including those that have a positive cost (i.e. those that are not profitable without a carbon price or other additional support), the potential abatement more than doubles to 159 MtCO2 in 2020, and increases to 344 MtCO2e in 2030.

In 2020, the average cost of profitable abatement measures is -€75/tCO2. This falls to -€96/tCO2 in 2030. These measures yield a total “surplus” or profit in 2020 of €4 billion and €11 billion in 2030. Across the entire MACC up to €150/tCO2 (in real terms), the average cost per tCO2 is €32 in 2020, and €1 in 2030.

By 2030, the largest improvements in emissions intensity (relative to the intensity of the current economy) that occur under current conditions without any carbon price or other policies are in the power sector, in residential buildings, efficiency improvements expected from new passenger vehicles, and from industry.

■ For power, investments that contribute to lower emissions intensity include the development of renewable power plants (hydro and wind), and investment in more efficient natural gas power stations.

■ For residential buildings, there is significant abatement from the improved construction standards of new buildings, as well as refurbishment of existing dwellings with insulation, improved heating systems such as condensing boilers, and the uptake of solar water heating.

■ In industry, there is potential in a range of smaller sectors, as well as in cement, refining, and steel.

■ In the transportation sector, replacement of road vehicles with next-generation diesel and gasoline vehicles results in significant energy intensity reductions.

At positive carbon abatement costs there is very significant potential to reduce emissions further, through investments in additional gas-fired power generation, nuclear power, and renewables, further improvements to buildings, and investments in the waste sector and industry.

A detailed overview of the abatement measures included in modelling is included in Appendix A.

4.3. Power

4.3.1. High level power sector results

Under the Status Quo scenario, generation increases by 67 percent between 2010 and 2020, and grows an additional 70 percent between 2020-2030.

Gas-fired generation continues to be the least cost option for new power plants during the period 2010-2020, but there are also attractive wind and hydro power sites that are developed. The addition of new hydro and wind does not meet ambitious government targets for



renewables by 2023, however. There are also gradual additions of coal and lignite. The rising gas prices in the IEA projections used and constraint on the available lignite resource combine to make hard coal the favoured source of new generation capacity in the 2020s. By 2030, hard coal and gas provide similar shares of the total generation mix, with coal providing substantial baseload generation. There is limited uptake of biomass or biogas in the Status Quo: the high price of biomass (which increasingly becomes an internationally traded commodity) renders it expensive without quite high levels of support; similarly although there are potential sources of biogas, the relatively low levels of feed-in-tariff support, combined with limited incentives to reduce landfill, are insufficient to stimulate uptake.9

Figure 4.3 Power Capacity Projection, Status Quo

9 Note that here, and in subsequent modelling of the power sector, carbon capture and storage (“CCS”) is not considered

as a realistic abatement option the modelling of which provides any real insight. CCS has not yet been successfully demonstrated on a full commercial scale, and its current costs are significantly higher than most analysts consider to be viable levels.



Figure 4.4 Power Generation, Status Quo



Figure 4.5 Power Emissions, Status Quo

In the absence of incentives for emissions reduction, by 2030 power sector emissions grow to over three times their 2010 levels, as a result of the addition of significant coal and lignite capacity (as well as additional gas). The resulting fuel mix broadly conforms with current government aspirations for fuel diversity, but in the absence of very significant expansion of renewables, this leads to an increase in the overall emissions intensity of the sector.

4.3.2. Marginal Abatement Cost Curves for the Power Sector

The next two pages present the results of the MACC modelling for the Power sector, for 2020 and 2030.



Figure 4.6 Power Sector MACC, Status Quo, 2020

Wind (M)

CCGT (Very-H)

Nuclear

CCGT (H)CCGT (M)

GeothermalCCGT (M) Nuclear

0 10,000,000 20,000,000 30,000,000 50,000,000 60,000,000 70,000,000

Abatement (tCO2)

0

50

40,000,000

100

150

Wind (H)

Hydro (H)

Hydro (H)CCGT (H)

Hydro (M)

Geothermal

Pric

e (E

UR

)

Notes: 1. “H” denotes high and “M” medium quality sites or plant efficiency.

Figure 4.7 Power Sector MACC, Status Quo, 2030

50

0

Abatement (tCO2)


Wind (M)

Nuclear

Geothermal

CCGT (Very-H)

CCGT (Very-H)

Wind (M)

Hydro (H)Wind (H)

150

200,000,000150,000,000

100

100,000,00050,000,0000

Cofiring Lignite

CCGT (Very-H)CCGT (Very-H)

CCGT (H)Nuclear

Hydro (M)

Pric

e (E

UR

)

Geothermal

Notes: 1. “H” denotes high and “M” medium quality sites or plant efficiency.



The modelling suggests that there are several options for emissions reduction in the power sector even without any additional climate policies. Without any carbon price or additional policies, four types of investments come forward in 2010-2020 that have lower emissions intensity than the existing power mix. These are wind power on high quality sites, two types of gas plant (one an upgrade of existing CCGT plant and the other a modern new CCGT), and finally new large hydro power capacity (of which there is around 7 GW). In 2020, investment in cleaner technologies reduces emissions below what they would have been by up to 27 MtCO2e without any carbon price or other climate policies. The reductions from profitable emissions-reducing investment are 47 MtCO2e by 2030.

At positive carbon prices (or if there were other additional supporting policies) there would be significant potential in 2020. Additional hydro power would be profitable at carbon prices of just €6/tCO2 (displacing coal). Turkey also has a significant potential to develop geothermal power at €53/tCO2 by 2020 (displacing gas, primarily.) Nuclear power requires a carbon price of €62/tCO2 to be profitable. Beyond this point, a range of significantly higher-cost options exist. These have in common that they require the “premature” closure of existing coal and lignite capacity, in favour of new or upgraded lower-emitting generation (chiefly gas), as well as nuclear power displacing new gas at carbon prices in excess of €140/tCO2. In total, up to a carbon price of €150/tCO2, the full power sector could deliver emissions abatement of 72 MtCO2 abatement in 2020.

By 2030, the MACC is significantly different from the 2020 MACC, because of the significant increase in coal-fired generation during the 2020s. In the 2020s, the rise of coal-fired generators means that fuel-switching to gas becomes a major abatement option. By 2030, even relatively modest carbon prices of around €10/tCO2 could contribute very significantly to emissions reductions, by increasing the load factors of existing gas plant and by increasing the share of gas in new investment. Such fuel-switching in the power sector could deliver 60 MtCO2e emissions reductions.

The next significant power generation option along the 2030 MACC is again the development of additional hydropower potential – this time at medium quality sites for just €10/tCO2. Geothermal sites again rank next, with the abatement cost falling to an average of just €23/tCO2 (because it is now displacing coal / lignite, rather than gas). Nuclear power also looks better by 2030, becoming profitable at €41/tCO2 to displace primarily new coal, and at higher carbon prices when displacing existing coal or even new CCGTs. The MACC also includes a range of higher cost options beyond this point, including new CCGT and upgrades to replace coal plants of varying ages. Overall, the MACC in 2030 shows abatement potential of nearly 215 MtCO2 by 2030.



Box 4.2 Explanation of "repeated" MACC blocks

In the MACCs above there are instances where the same technology is repeated at different carbon price points. This arises because for abatement costs above zero, the cost and emissions savings are calculated relative to a counterfactual that is not fixed, but modelled dynamically.

For example, the 2020 Status Quo MACC shows Nuclear power at both $100/tCO2 and $225/tCO2. Thus $100/tCO2 is the price required to cause nuclear power to be built instead of the building of new coal and lignite plant. By contrast, the higher price is that required to motivate the construction of new nuclear capacity to displace existing lignite and coal plant.

More generally, technologies may appear in multiple blocks for the following general reasons (analogous issues arise for sectors other than the power sector):

■ Technologies are split into tiers. Several technologies are represented in tiers with different cost characteristics and performance. For example, the modelling includes three categories of wind power sites with different cost and load factor.

■ Different counterfactual technologies. A given technology (e.g., nuclear power) can displace multiple other technologies (e.g., gas- or coal-fired plant). The model analyses the relevant counterfactual by considering what would have been built at a price somewhat lower than the price at which nuclear becomes viable. This means that nuclear can displace (say) some coal-fired plant at one price point, but gas only at a higher price point.

■ Capacity additions at different points in time. The relative cost of generation varies over time, notably because of changes in (relative) fuel prices. Thus even if nuclear power had constant cost, the carbon price required to make nuclear more attractive than gas-fired generation varies over the period. As the 2030 MACC shows cumulative additions over the entire period, this can result in blocks at different price points.

■ Displacement of existing plant. Finally, in the power sector most of the MACC blocks show different options for investment in new capacity to meet growing demand (preserve reserve margins). However, at sufficiently high carbon prices, it becomes cheaper to construct new, low-emitting capacity than to produce electricity from existing, high-emitting plant, despite the additional investment that must be undertaken. Much of the very high-cost potential (in excess of $100/tCO2 is in this category).

In contrast to MACC models that assume a single counterfactual for each technology, the model used here assesses abatement potential through the dynamic simulation of market conditions. The appearance of multiple blocks reflects real-world phenomena that affect abatement potential and cost. They illustrate that investments in low-carbon technologies must take into account not only the technology characteristics of the low-carbon technology itself, but also the overall market setting within which it is deployed. They also provide an illustration of the reasons that deployment of given low-carbon technologies increases as carbon prices increase – rather than enter all at one single trigger price point.



4.4. Buildings

This section presents the abatement that can be achieved under the Status Quo policy scenario, first profitably (i.e. at negative cost of carbon abatement), and then at progressively higher costs per tonne CO2e (consistent with the MACC analysis framework). We discuss expected developments in fuel use and technology for space heating, water heating, and uptake of insulation as building owners and residents make decisions over time about the technologies and measures they choose to invest in.

As set out in Appendix A, section A2, the large majority of residential buildings in Turkey are owner-occupied, with flats making up the majority of new construction. Decisions about existing dwellings are therefore made largely by individual households, where relevant, acting in a coordinated way as part of condominium associations. Where collective decision-making is required, e.g. for shared systems or building-level investments, this incurs significant transaction costs.

For new buildings there are different barriers, but they are equally significant: in particular, as noted above, developers face lax enforcement of building regulations that allow them to avoid investing in more efficient energy saving measures, and on the demand side, purchasers are not sufficiently well-informed about the energy characteristics of buildings to drive a significant shift. The market does respond, however, to demand for the convenience offered by natural gas as a heating fuel, as this option is facilitated by continued expansion of the gas network.

4.4.1. Fuel Use

Significant changes in the number of dwellings by type of fuel used include:

■ Large increases in the number of dwellings using gas. In particular, the share of dwellings using gas condensing boilers rises from 7 percent in 2010 to 16 percent in 2030. The share of dwellings using non-condensing gas boilers remains stable over the period, at around 46 percent.

■ The most significant declines occur in dwellings using electricity and biomass for heating. Although electric heating typically has a low capital cost, the high cost of electricity can make it uneconomic. The decline in the use of traditional biomass follows historical trends as households switch to the convenience of more reliable modern fuels. The total falls in such dwelling between 2010 and 2030 are 45 and 48 percent for electricity and biomass, respectively. The share of dwellings using biomass falls from 13 percent in 2010 to 5 percent in 2030. These shifts are due primarily to increases in the price of electricity and in biomass prices

■ Coal use (including lignite) persists, although its share declines from 27 percent in 2010 to 23 percent in 2030. Coal remains the only viable option in some areas that do not have access to the gas grid, and the persistence of government policy to provide fuel for free to poor households also contributes to its persistence.

■ Insulation



■ Under the Status Quo scenario, uptake of insulation measures continues at a slow rate. Insulation of multi-occupancy buildings requires coordination between residents that impose significant transaction costs. The share of dwellings with “partial insulation” (one or two measures) increases from around 11 percent to 18 percent between 2010 and 2030. The increase in the number of dwellings with three or more measures (“significant insulation”) is greater. Figure 4.8 shows how the number of dwellings by insulation level changes between 2010 and 2030. New buildings are constructed in all three categories, reflecting the heterogeneity of financial attractiveness with different fuel availability, among other factors. Rising prices for electricity and gas over the period also contribute to the increasing attractiveness of insulation measures. In total, the share of dwellings with at least one insulation measure increases from 36 percent in 2010 to 64 percent in 2030. The number of dwellings without any insulation declines between 2010 and 2030 by 16 percent.

Figure 4.8 Number of Dwellings by Level of Insulation

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In the commercial sector, the share of total commercial area with at least one insulation measure increases from around 39 percent to closer to 54 percent between 2010 and 2030.

4.4.2. Water heating

■ There are significant increases in the use of solar water heating and gas condensing boilers: by 2030, over 7 million dwellings (25 percent) use solar heating for hot water, compared to 3 million in 2010. These systems can be very attractive, with paybacks of less than 4-5 years compared to electricity and 3-4 years compared to LPG (Ertekin, et al., 2008). As electricity and gas prices increase, these systems become increasingly attractive.



■ The increase in the use of gas boilers for space heating generally, and condensing boilers in particular, means that their share of the energy used to heat water also increases. Again, rising gas prices over the period makes it increasingly attractive to purchase more efficient equipment, such as condensing boilers. The number of dwellings using condensing boilers to heat water reaches around 6 million by 2030 (21 percent of dwellings).

■ Electric heating systems also remain common, and remain the most commonly used system in 2030, although their share declines from 64 percent in 2010 to 34 percent in 2030. Even though electricity is considerably more expensive than gas, these systems have very low up-front costs, and can be installed very widely, even where gas is not available and solar water heaters or centralised fossil-fired systems are unsuitable. Although they are very efficient, they do not provide significant abatement unless the power sector is decarbonised.

■ Over the period, the number of oil water heaters, which account for less than ten percent of the total, falls by 19 percent, as this relatively expensive option is replaced where possible.

■ In the commercial sector there are similar developments; the most significant increase is in the use of solar water heating, as well as an increase in the use of gas condensing boilers: by 2030, solar water heating accounts for 35 percent of the commercial area.

4.4.3. Emissions implications

Total direct emissions10 from residential buildings were 35 MtCO2e in 2010. Emissions rise to 42 MtCO2e by 2020, and subsequently rise further to 49 MtCO2e. This represents a 40 percent increase in emissions between 2010 and 2030. Figure 4.9 shows how residential emissions develop under the Status Quo scenario.

Figure 4.9 Total Direct Emissions from Residential Dwellings

Residential Emissions ‐ Status Quo

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10 Excluding indirect emissions from electricity consumption.



Despite the increase in total emissions, emissions intensity (measured as emissions per dwelling) falls over the period from 1.6 tCO2e per dwelling in 2010 to 1.5 tCO2e per dwelling in 2030, an average reduction of 5 percent.

In non-residential buildings, total direct emissions were 10 MtCO2e in 2010. Emissions are projected to rise to 14 MtCO2e by 2020, and subsequently to over 16 MtCO2e. This represents a 56 percent increase in emissions between 2010 and 2030.

4.4.3.1. Emissions from space heating

Total emissions from space heating rise from 31 MtCO2e in 2010 to 36 and 41 MtCO2e in 2020 and 2030, respectively (an increase of 15 and 33 percent). However, emissions intensity falls by 6 percent, from 1.4 tCO2e per dwelling 1.3 tCO2e per dwelling in 2020. By 2030, the emissions intensity is under 1.3 tCO2e per dwelling -- 9 percent below its level in 2010.

These emissions include savings from the installation of thermostats. Thermostats reduce emissions by 1.7 MtCO2e in 2010, 2.2 and 2.4 MtCO2e in 2020 and 2030, respectively.

The decline in emissions intensity reflects a variety of trends; these include:

■ Between 2010 and 2030, the share of apartments increases significantly – from 56 percent in 2010 to 71 percent in 2030. Apartments generally have a lower emissions intensity than houses.

■ There is also a significant decline in the share of dwellings using coal, with its share falling to 23 percent in 2030. In particular, there is a significant transition away from non-insulated coal apartments.

■ The increase between 2010 and 2030 of the share of dwellings using at least one insulation measure also contributes to the reduction in emissions intensity during the period. The adoption of insulation measures can lead to reductions in emissions intensity ranging from 12-25 percent for a shift from no insulation to partial insulation, and a 30-45 percent reduction for a shift from no insulation to significant insulation.

■ The increase in the use of heat allocator meters and thermostats. The share of dwellings with these control devices rises from 14 percent in 2010 to 22.0 percent in 2030. These can reduce emissions by between 0.33 to 0.53 tCO2e per dwelling

Space heating emissions from commercial buildings are 10 MtCO2e in 2010, and rise to nearly 15 MtCO2e in 2030.

4.4.3.2. Emissions from water heating

Emissions from residential water heating are 4 MtCO2e in 2010. These increase to over 6 MtCO2 by 2020 (68 percent increase), and rise further to over 7 MtCO2e in 2030 (98 percent increase relative to 2010). This increase is due to the increase in the number of dwellings, many of which use gas condensing boilers.

Emissions from water heating account for a relatively small proportion of total emissions from commercial buildings. In 2010, emissions from water heating are 0.4 MtCO2e, and rise



to 0.7 MtCO2e by 2030. As is the case with residential buildings, the increase in emissions is due to the increase in total commercial area.

4.4.4. Marginal Abatement Cost Curves

A significant reduction in emissions takes place up to 2020 compared to a situation under which the sector grows with the present characteristics. The total reduction in emission due to measures that will be adopted without additional policy under the Status Quo scenario is 12.3 MtCO2e by 2020, and 23.9 MtCO2e by 2030.

There are several sources of reductions in emissions, including:

■ the use of condensing gas boilers in residential buildings

■ the installation of condensing gas boilers and/or insulation measures in residential buildings

■ the adoption of thermostats/heat allocators in commercial buildings

■ the retrofitting of dwellings with greater insulation in residential buildings

Each of these measures leads to a reduction in emissions of more than 1 MtCO2e by 2020. Alongside these, various other measures also contribute to reductions in emissions. These include the use of more efficient air conditioning and the use of solar water heating. Measures in newly constructed buildings generally lead to larger financial savings, ranging from €300/tCO2 to €122/tCO2 by 2020, compared to the retrofitting of measures in existing buildings.

In addition to further emissions reduction from these measures, by 2030, the use of more efficient lighting and refrigerators represent an additional source of emission reduction that would occur under the Status Quo policy scenario and holding carbon prices at zero.

The MACC shows that there is further abatement potential under the Status Quo, but it has an abatement cost greater than zero, so would not be profitable unless other policies or a positive carbon price were put in place. Notable instances of abatement potential greater than 1MtCO2e include:

■ at an abatement cost of €36/tCO2, a combination of installing insulation and gas condensing boilers in residential dwellings, results in abatement of 1.2 MtCO2e. By 2030, this measures results in abatement of 1.9 MtCO2e at a cost of 30 €/tCO2.

■ at an abatement cost of €57/tCO2, greater insulation in residential buildings results in abatement of 1.3 MtCO2e. By 2030, this measure leads to abatement of 1.5 MtCO2e at a cost of €50/tCO2.

■ at an abatement cost of €83/tCO2, a combination of installing insulation and gas condensing boilers in commercial buildings results in abatement of 3.0 MtCO2e. By 2030, this measures results in abatement of 3.2 MtCO2e at a cost of 66 €/tCO2.

By 2030, a further notable abatement opportunity is fuel switching in residential buildings, predominantly to gas from coal. This has a marginal abatement cost of €57/tCO2 and leads to abatement of 1.1 MtCO2e.



Overall abatement potential below €50/tCO2 is 3.4 MtCO2e by 2020, rising to 4.5 MtCO2e by 2030. The main sources of this abatement are greater insulation and/or installing condensing boilers, and to a lesser extent, solar water heating. The total abatement potential at costs less than €150 / tCO2e stands at 13.0 MtCO2e by 2020, and 15.0 MtCO2e by 2030.

Figure 4.10 Buildings MACC, Status Quo, 2020

Solar water heating (R)Refrigeration

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Figure 4.11 Buildings MACC, Status Quo, 2030

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4.5. Industry

4.5.1. Current emissions and projections

Direct emissions from Turkish industry were just over 80 MtCO2eq in 2008. Most of this was accounted for by emissions from fuel combustion, but with substantial contributions also from process emissions from minerals and chemical production. In addition to these emissions, industry gives rise to indirect emissions through the use of electricity.

Emissions are concentrated in a few key sectors. The most prominent is the cement sector, which with total clinker production capacity of 63 Mt per year is very large. Emissions are around 37 MtCO2eq, or as much as 45 percent of total industrial emissions. Turkey also has a substantial steel sector, with capacity to produce around 34 Mt steel per year. Direct emissions from this sector account for 15 percent of total industrial emissions, but as production is dominated by electric arc furnaces the sector also uses substantial quantities of electricity. Lime and bricks production each account for 6-7 percent of total emissions, while petroleum refining gives rise to 5 percent of the total. The remaining 25 percent of emissions accounted for by a range of other industry, with chemicals, ceramics, food, pulp and paper, and textiles important contributors.

With significant forecast economic growth, industrial output is set to increase significantly in the period to 2030. Without reductions in emissions intensity, emissions also would expand substantially, and keeping today’s emissions intensity constant would see an increase to more than 130 MtCO2eq by 2030, a 60 percent increase on current levels.

The figure overleaf shows the current breakdown of direct emissions by broad sectors, as well as a “static” baseline projection of emissions that would result in 2030 if the intensity of production remained at current levels. As we discuss below, there are several ways in which emissions intensity can be reduced.



Figure 4.12 2008 Emissions and 2030 “Static” Emissions Projection

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Notes: The 2030 projection shows the emissions that would result with growing output but constant

(“static”) emissions intensity of production did not improve on current levels. As we discuss below, there are several ways in which the emissions intensity can be reduced. The figure shows direct emissions from fuel combustion and direct process emissions, only, and does not include indirect emissions from electricity use.

4.5.2. Overview of industrial abatement measures and investment drivers

Emissions abatement relative to this “static” case falls broadly into two categories:

1. New capacity to meet additional demand. Both natural attrition of existing capacity and the need for capacity to meet new demand mean that significant new investment in new plant will be required across a range of industry. This offers the opportunity to transition to production capacity with lower emissions intensity than the current average, reflecting a general trend towards more energy-efficient production techniques. New investment thus is a significant source of abatement relative to the static case.

The extent of proportional abatement available through this channel depends on the characteristics of current plant; for example, the Turkish brick industry is characterised by relatively old and energy intensive plants, compared to international benchmarks. By contrast, a large proportion or the Turkish cement industry is of relatively recent construction, with emissions intensity below that of several Western European countries.

2. Retrofitting and changes to existing production techniques. The second major category of abatement is various measures to improve the energy efficiency and the emissions intensity of existing production capacity. This spans a very wide range of



heterogeneous abatement measures which often are highly specific to the particular production processes of different sectors. However, they can be broadly categorised in the following categories:

- Energy efficiency – fuel. These include a wide range of sector-specific measures, with important cross-cutting measures including energy management systems, process optimisation, waste heat recovery, and more efficient furnaces and boilers.

- Energy efficiency – electricity. These include several cross-cutting measures such as more efficient motors and drives, more efficient pumps, and improvements to compressed air, but also sector-specific measures in electric-arc steel production, aluminium production, or some chemical processes.

- Fuel substitution. Abatement also is available by switching to less carbon-intensive fuels. This includes a switch from coal or oil to natural gas; or from fossil fuels to waste fuels (particularly in the minerals sector) or biofuels. Gas has become an important fuel in Turkey; by contrast, current penetration of waste fuels and biofuels is very low.

- Raw material substitution. Emissions from the calcination of limestone (“process emissions”) in the cement and lime sectors are substantial sources of emissions, with some process emissions also in glass production. In the case of cement, these can be reduced by substituting other materials for clinker.

- Non-CO2 gases. Various sectors, and especially chemical industries, offer opportunities for the abatement of non-CO2 greenhouse gases. The most significant in Turkey is the potential to use catatlyic reduction technologies to reduce nitrous oxide emissions arising from the production of adipic and nitric acid.

- Carbon capture and storage. The use of CCS for industrial emissions is significantly more speculative than other measures, but if the technology and associated infrastructure is sufficiently developed could offer the potential for the deep emissions cuts. The measure would likely be limited to sectors with large point-sources of emissions, notably integrated steelworks and large cement plant. However, because the technology is speculative at this stage, we do not include it in the main scenarios investigated here.

These different categories of abatement measures respond to different drivers of investment.

Investment to improve energy efficiency depends in the first instance on the value of the fuel savings that investments can bring. Higher fuel prices thus contribute to higher abatement potential. In addition, firms’ willingness to incur the up-front cost of improving energy efficiency depends on a number of factors, starting with the access to and cost of capital, but in the short term especially also including factors such as awareness and availability of technical expertise and advice.

Fuel substitution, by contrast, depends more on the relative cost of higher-polluting fuels (coal, oil) and lower-polluting options (gas, biofuels, waste). As importantly, widespread adoption of lower-emitting fuels depends on reliable supply. Turkish industry has seen a significant shift away from oil and towards natural gas, as the latter has become more widely available in the past decade and also has had lower cost and other advantages. There is some limited scope for a continuation of this trend but deeper emissions cuts through fuel substitution depend on replacing coal with gas, or with waste or biofuels. This is limited by the often substantial cost advantage of using coal where this is feasible, and by the limited supply chains for alternative fuels, which impact their reliability negatively. Drivers for further fuel substitution thus include higher coal prices relative to gas, and improving the prospects for use of alternative fuels, including biofuels and waste fuel supply chains.



The incentives for raw material substitution are closely linked to the cost of production. In the case of both cement (clinker substitutes) and glass (increased use of cullet) the price of energy is a key factor, with drivers similar to those for energy efficiency. In addition, raw material substitution depends on achieving a reliable supply chain for the relevant waste materials, for which waste regulation is a key factor.

In contrast to the above abatement options, both carbon capture and storage and abatement options relating to non-CO2 gases are motivated not by savings on energy expenditure, but depend on a value associated with avoided GHG emissions. In both cases, investments therefore would be motivated only where reduced GHG emissions brought a direct financial advantage.

4.5.3. Marginal abatement cost curve for industry

The marginal abatement cost curve for industry is shown in Figure 4.13.

Figure 4.13 Industry MACC, Status Quo, 2030

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The MACC identifies 20 MtCO2 of abatement, or a reduction of 18 percent on the 2030 “static” projection. Much of the abatement potential is concentrated in the steel and cement sectors, but bricks, ceramics, and selected chemicals also provide significant potential.

Low-cost options for abatement are dominated by new capacity. As noted in preceding sections, there often is opportunity to achieve higher energy efficiency at relatively small incremental cost, but as with other energy efficiency the cost of energy is a key driver in these investment decisions. There also are significant opportunities to reduce emissions relative to the static case at existing capacity, through maintenance, refurbishment, capacity expansion, as well as discretionary upgrades and adoption of energy efficiency improvements. The sectors that appear to offer particularly important opportunities for such measures include cement, ceramics, bricks, lime, and some chemicals. The measures are concentrated



in sectors and measures that depend strongly on the price of coal, but the results suggest that even at central coal prices many investments could be attractive.

By contrast, switching from coal to gas entails high cost, and would be motivated only if policy were put in place to significantly alter the relative cost of the two fuels (e.g., by making carbon emissions expensive).

As noted above, we do not include carbon capture and storage in this abatement cost curve, as we regard the technology as speculative and costs are highly uncertain. However, there are significant emissions from cement, steel, and refineries which could be amenable to the application of CCS, should the technology prove viable. Unlike energy efficiency or fuel switching, CCS would increase energy costs (as well as entailing high up-front capital investments), and would be motivated only if there were offsetting incentives to reduce GHGs, through regulation or carbon prices.

We provide a more detailed discussion of the abatement options and potential for the more important sub-sectors below.

4.5.4. Results for industry sub-sectors

4.5.4.1. Cement

Turkey has the largest cement production capacity in Western Europe. Without reduction in emissions intensity, cement sector emissions could grow from the already substantial current levels of around 37 MtCO2 / year to around 55 MtCO2 / year by 2030, based on a convergence of Turkish cement consumption to levels in other developed countries and continuation of production for export markets.

The sector already is relatively energy efficient, with emissions and energy intensity below the EU average, but scope for further improvement.

The main abatement measures in the cement industry fall in the following categories:

■ New capacity: modern kilns and dry production technologies can be significantly more energy efficient than older capacity, with improvements of 15 percent not unusual. Significant capacity is likely to be added over the next two decades, and ensuring the application of energy efficient technology could lead to substantial emissions reductions.

■ Energy efficiency measures: key measures to improve the performance of existing plant include preventative maintenance, energy monitoring systems, improvements to kiln combustion, reductions in shell heat loss, replacement of grate coolers, and the use of indirect firing. Depending on the combination of measures and underlying kiln technology, these can reduce energy consumption by 10-20 percent.

■ Fuel use: cement manufacture can make use of a range of fuels, and in particular has the potential to make use of waste fuels from a range of sources. For example, switching from coal to gas can reduce emissions by some 18 percent. A more economically viable option is the use of waste fuels, which can reduce emissions by around 5 percent, depending on the fuel used.



■ Clinker substitution: substituting other materials for clinker can reduce both process and combustion emissions, with key options including blast furnace slag and pulverised fly ash (PFA). Substituting as much as 30 percent of clinker can reduce emissions by 23 percent.

■ Carbon capture and storage: cement has been mooted as one of the sectors that has point source emissions sufficiently large to enable the use of carbon capture and storage. However, the application of this technology in industry remains speculative at this point in time, and we do not include it in our main analysis.

The key driver of energy efficiency measures is the price of coal, which is and is likely to be the key fuel input to cement manufacture. Existing plant vary significantly in energy performance, in part reflecting the age of plant. Given the higher cost and greater inertia in retrofitting existing capacity, energy efficiency improvements through new capacity will be a key route to emissions reductions. In contrast to many potential energy efficiency investments, the use of natural gas would come at significant net present value cost.

The attractiveness of investing in greater clinker substitution and use of waste fuels would vary not only on the cost of coal, but also depend strongly on the institutional and regulatory framework for waste handling. The Turkish cement industry currently makes use of much of the blast furnace slag produced by the country’s integrated steel plant. In addition, some 3 Mt of PFA currently is utilised, out of the around 16 Mt produced by the country’s coal- and lignite-fire power stations.

Expanding clinker substitution would likely require regulatory changes. The current waste regime in Turkey offers favourable terms for more conventional disposal routes, notably nearly costless landfilling of bulk materials. There thus are few incentives to incur the additional cost of using them in cement production, or to develop the infrastructure and commercial arrangements necessary. In the Status Quo scenario we have assumed that the waste regulatory regime permits at most half of production to transition to 20 percent clinker substitution by 2030; however, as we discuss below, significant additional abatement could in principle be made available under stronger policy incentives.

Similar considerations apply for waste fuels, with candidate substances spanning a broad range including tyres, solvents and other chemical waste streams, and some organic waste. Unlike in Western Europe, there currently is nearly no use of such fuels in the industry, reflecting very limited incentives and barriers similar to those noted for clinker substitution. In the Status Quo scenario we have assumed no use of waste firing; again, additional abatement could be made available with more conducive policies. (By contrast, the use of natural gas instead of coal would come at high costs that are unlikely to make them relevant options for this sector.)

In this scenario, the majority of emissions reductions thus are from improved energy intensity of production, motivated by savings on coal costs. We identify emissions reductions of 7 MtCO2, compared to the static case, or a 12 percent reduction. Much of the potential is available through higher energy performance at new capacity, but retrofitting energy efficiency measures also plays a role, and under the assumptions about fuel prices and other factors could offer attractive investment opportunities.



4.5.4.2. Steel

Turkey is a major iron and steel manufacturer. Its 2008 production of just under 27 Mt crude steel put it third in Europe and eleventh in the world (DCUD 2010). There are three integrated iron and steel plants and 19 electric arc furnaces (EAFs) in Turkey, with EAFs accounting for three-quarters of production. The sector accounted for 12 MtCO2e direct emissions in 2008. Because the country relies heavily on the less energy-intensive EAF production route, and relies heavily on the use of steel scrap rather than direct reduction, emissions from the steel sector are lower than those of other major steel producers. However, the high proportion of EAFs also means that Turkey has been an importer of flat steel products, which are produced primarily at integrated steelworks, rather than EAFs. Without reduction in emissions intensity, emissions could grow to 19 MtCO2, based on convergence of Turkish steel production to that of other developed countries.

The abatement measures relevant to the sector vary between the two production routes. Various studies have found that both routes can improve energy performance through better energy management systems, preventative maintenance, and improved process control / automation. Integrated plants can further reduce energy consumption by making use of a range of more specialised measures applied to a variety of processes, including pulverised coal injection, efficient use of BOF gas and heat recovery, and coal moisture control, and sinter plant heat recovery. Correspondingly, specialised measures relevant to the EAF route include improvements to ladle preheating, insulation of furnaces, control of oxygen levels, variable speed drives in fans, and recuperative burners.

Likewise, the drivers for investment vary somewhat between the two routes. In the BOF case, the driver for investment is primarily savings on the cost of coking coal and other direct fuel and raw material inputs. The cost of abatement is strongly linked to the wider coal energy costs. In the EAF case, by contrast, the key cost is electricity, with more complex links to the wider energy markets, including natural gas.

Overall, we identify direct emissions reductions of around 10 percent on the emissions associated with the static scenario, with proportionately higher reductions available from the minority of BOF route production than from EAFs. Because abatement from EAF plants is dominated by reductions in electricity use, the extent of emissions abatement depends on the characteristics of the underlying power plant used for generation. However, as conventional thermal power plant (both gas and coal) continue to be built in all scenarios, all scenarios offer similar scope for emissions reductions.

4.5.4.3. Refining and petrochemicals.

Refining. Turkish refineries processed 24 Mt of crude oil in 2008, with UNFCCC data indicating associated emissions of 4.5 MtCO2. Output is likely to increase significantly in the next two decades. Significant capacity additions of 10 Mt crude throughput per year are due to come online at the Aliağa complex in 2014. At current emissions intensity, emissions would grow to an estimated 8.5 MtCO2 by 2030, reflecting significant underlying demand from a growing transport sector.

A high-level comparison with international benchmarks suggests emissions are similar to the average emissions at EU refineries. However, the energy intensity of oil refining depends



strongly on the nature of precise refining process and the range of associated outputs produced (the “complexity” of the refining undertaken), and comparisons need to account for complexity to be informative. In addition, emissions data are uncertain.

Measures to reduce emissions in refineries centre on optimisation of the overall process to increase the overall product yield per unit of crude oil processed. Key measures include improved process integration, maintenance and cleaning / fouling mitigation, process control, as well as good energy management systems and systems for waste heat recovery. Refining also is a sector where improvements to motors, drives, and compressed air can offer abatement opportunities. Overall we identify scope for emissions reductions of 1.3 MtCO2 by 2030, or a 15 percent reduction in emissions intensity compared to the static case.

The industry has strong inherent incentives to improve efficiency; indeed, the use of (complexity-weighted) energy benchmarking (such as the Solomon system) has become a standard management tool in the refining industry, and is in itself a very important tool in enabling emissions abatement. Incentives to invest in efficiency improvements will depend strongly on the price of crude oil. It also will depend on the extent of market pressure and competition from efficient competitors.

Petrochemicals. The Turkish petrochemicals industry produced 2.4 Mt of output in 2008. Detailed emissions data have not been available to this project, but we estimate emissions in the range 0.9-1.2 MtCO2. Measures to reduce emissions in this industry have much in common with those in selected parts of the oil refining process, including improved drying, distillation, evaporation processes, and waste heat recovery. Overall, we identify a combination of measures that could reduce emissions by 20 percent by 2030, with much of the improvement from efficient new capacity.

4.5.4.4. Lime, bricks, ceramics, and glass production

Lime. Turkey produced 3.4 Mt of lime in 2008, accounting for emissions of approximately 4.5 Mt CO2. A large share of emissions from the lime sector is attributable to irreducible process emissions. However, combustion emissions depend significantly on the production technology used, including the type of kilns as well as the application of various energy efficiency measures. The more important include control of shell heat loss, kiln combustion improvements, and maintenance and process control measures, all of which offer the potential to reduce expenditure on coal, the key fuel used in the industry. The application of these measures in new and existing capacity could reduce emissions by 15-20 percent by 2030, where much of the potential improvement would depend on the adoption of more energy efficient varieties of kiln in new capacity.

Bricks. The Turkish brick industry relies almost entirely on old Hoffmann-type furnaces, with significantly higher energy consumption than tunnel type furnaces. There is scope for significant improvements in energy performance by adoption of tunnel furnaces, with improvements of 30 percent or more. Within each basic kiln design, there also is scope for various measures to reduce energy consumption in the firing and drying processes, and with an inefficient starting point reductions in energy intensity by as much as 50 percent could be feasible, albeit only with significant investment. In addition, the sector relies heavily on lignite and coal. Further emissions reductions thus would be feasible by switching to less polluting fuels, but as with other industry the use of natural gas instead of coal would come at



a high cost. We identify emissions reductions of 3.3 MtCO2 by 2030, compared to the static baseline, or a reduction in emissions intensity of more than 40 percent. The key driver of this very significant investment programme would be savings on coal and lignite costs. In the past, however, the sector has been reluctant to undertake significant investment, reflecting the conditions in an industry with strong competition, small margins, and existing over-capacity. There therefore has been little movement to date towards realising these theoretical energy savings.

Ceramics. In contrast to the brick sector, the Turkish ceramics industry relies primarily on natural gas as a fuel source, and the price of gas correspondingly is the key driver for most abatement measures. The drying and firing processes account for around 90 percent of energy use in typical ceramics production, and these therefore offer the largest scope for emissions reductions. Key considerations for improvement of drying energy efficiency include optimisation of loading, air flow control, waste heat recovery, and efficient monitoring. For firing, the most important considerations include systems for minimising the firing speed, maximising heat recovery, and maintaining kiln control. Although many of these require some degree of investment, much of the emphasis for existing plant is on ongoing process improvements. Finally, motors, drives, and compressed air, although a relatively small share of total energy use, can be among the most cost-effective emissions reduction measures. We identify a combination of these measures that could reduce emissions from ceramics production by 1 MtCO2 by 2030.

4.5.4.5. Other industry

Chemicals. The chemicals sector is highly diverse, and opportunities for emissions abatement often very process-specific. Two sectors with particularly high abatement potential are the production of nitric acid and soda ash. In addition to emissions from energy use, both of these give rise to significant process emissions. Turkey produces around 600 kt per year nitric acid per year, with significant associated emissions of nitrous oxide. We estimate that as much as 3.5 MtCO2e of emissions could be reduced by 2030 through the application of catalytic reduction. However, unlike energy efficiency measures this type of abatement has no additional benefit or cost reduction, and it would be incentivised only under regulation of emissions per se. Soda ash production amounts to 900 kt per year. A range of emissions can reduce energy-related as well as process measures, including membrane process improvements, high-efficiency motors, control systems, high-efficiency trays, waste heat recovery, and control systems. Several of these measures apply more generally to inorganic chemicals production.

Glass. Turkey produces just under 2-2.5 Mt of glass per year, and we estimate that associated emissions are around 1.8 MtCO2, growing to 2.5 MtCO2 by 2030 at static emissions intensities, although detailed data are lacking. Relevant emissions abatement measures for this sector include increased use of cullet, advanced burner systems, oxy-fuel furnaces, the use of ultrasonic refining, waste heat recovery, improved refractories and insulation, as well as improved control systems. Fuel cost would be the chief motivating factor for investment in these technologies.

Pulp and paper. Production and energy intensity in this sector is heterogeneous, depending strongly on the nature of the final paper product. Cross-cutting measures include process control, pinch analysis, and waste heat recovery, which can reduce energy intensity by 5-10



percent. The sector also has scope to make use of wood by-products as substitutes for fossil fuels, offering further reductions in emissions depending on the level achievable.

4.6. Transport

4.6.1. Sectoral growth

In the transport sector we make the following assumptions:

■ Transport fuel prices facing consumers remain high by international standards;

■ There is no major policy drive towards more efficient and/or less carbon intensive vehicles in the road sector, and road continues to dominate the transport sector – with 86 percent of passenger kilometres being travelled by car, and 97 percent of freight being transported by heavy duty vehicles.

■ Road transport sector is expected to grow at a faster rate than GDP: The number of passenger kilometres almost triples between 2009 and 2030. Freight road transport increases by 4.6 percent year on year

Under Status Quo policies, and without any carbon price, most vehicles remain fuelled by traditional fossil fuels, such as diesel and gasoline. A small amount of hybrid vehicles become attractive towards the end of the period, as their upfront and operating costs are sufficiently reduced through technological progress. Fitting standard vehicles with LPG engines remains an attractive option throughout the period.

Only a small amount of hybrid vehicles become profitable towards the end of the modelling period, when their upfront cost is driven down by technological progress; the uptake of electric vehicles is zero, which is less than the government target of 5 percent in 2023.

In the absence of incentives for emissions reduction, by 2030 transport sector emissions roughly double relative to their 2010 levels, mostly driven by increases in road transport, both passenger and freight.

Because it is the source of the majority of emissions, the main abatement options are in the road sector. In the passenger road sector, new and more efficient version of standard vehicles (gas, diesel and LPG) will gradually replace the older ones, which will reduce emissions. At the same time, advanced vehicle technologies, such as hybrids, also result in abatement. By 2030, the sector will replace the entire fleet of current vehicles, and therefore has a potential to significantly reduce current emissions intensities. Appendix A.4.4 provides further details on the assumptions regarding fuel savings and costs of the various types of passenger vehicles modelled.

4.6.2. Marginal abatement cost curves for Transport

The marginal abatement cost curves for Transport are shown in the figures below:



Figure 4.14 Transport MACC, Status Quo, 2020

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Next generation LPG standard

Post 2020 gasoline standardPost 2020 diesel standard

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0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 8,000,000

Abatement (tCO2)

Heavy duty vehicle advanced


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Figure 4.15 Transport MACC, Status Quo, 2030

Next generation diesel standard

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Traditional electric carNext generation NPH standard


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Post 2020 gasoline standard

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Even without any specific policies to reduce carbon emissions in place, several abatement options come forward between 2010 and 2020 to reduce emissions by 5 MtCO2, at an average cost of -€48/tCO2. By 2030, emissions are reduced by 13 MtCO2, at an average cost of -€90/tCO2. If we include the abatement potential that is not profitable (but that could be with a positive carbon price or other policies), the total abatement potential increases to 8.8 MtCO2 in 2020, and 24 MtCO2 by 2030.

The profitable abatement potential is concentrated in Road transport, and specifically in Passenger road transport. Modern diesel vehicles provide 1.7 MtCO2 abatement in 2020 and



up to 3.6 MtCO2 abatement in 2030. Modern LPG vehicles provide 0.7 MtCO2 abatement in 2020 and 1.4 MtCO2 in 2030.

Advanced Freight road transport, shown as “Heavy duty vehicle advanced” in the MACC, includes among others, better and more frequent vehicle maintenance, tyre pressure checks and similar. In 2020, this leads to emissions abatement of around 2.1 MtCO2, increasing to 6.6 MtCO2 in 2030.

For freight road transport, we expect that in reality the cost of abatement will vary depending on the nature of the freight traffic. This is because the benefit of a better-maintained or more efficient vehicle would depend on the average yearly mileage of individual trucks. Long-distance (i.e. international) freight vehicles typically drive substantially more tonne-kilometres over their lifetime than medium distance (inter-city) and short-haul (intra-city) freight vehicles, so the benefits of fuel savings will vary.

4.7. Waste

Emissions from the Waste sector in 2008 were 34 MtCO2e, as reported in the UNFCCC inventories. Most of these were methane emissions from solid waste disposal, but there were also significant N2O emissions from landfills, as well as methane emissions from waste water.

Turkey currently produces around 25 million tonnes of municipal waste every year. Most of the waste is deposited at dump-sites or basic landfills; only small proportions are incinerated and/or composted. In the Status Quo scenario, this trend continues until 2030, as there are few incentives to limit waste or emissions from waste. The amount of waste produced grows at 5.7 percent yearly.

4.7.1. Marginal abatement cost curves for Waste

The marginal abatement cost curves for Waste are shown in the figures below.



Figure 4.16 Waste MACC, Status Quo, 2020

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12,000,00010,000,0008,000,0006,000,0004,000,0002,000,0000

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Improved wastewater treatment and AD (MWW)

Improved wastewater treatment and AD (IWW)

AD (MWW)

Improved wastewater treatment (MWW)

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Figure 4.17 Waste MACC, Status Quo, 2030

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Abatement (tCO2)

10,000,0005,000,0000

Waste: mechanical and biological treatmentWaste: landfill with direct gas use

Improved wastewater treatment and AD (MWW)

15,000,000

AD (MWW)

Improved wastewater treatment (MWW)

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Improved wastewater treatment and AD (IWW)

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AD (MWW)

Notes: Water is categorised as Industrial (IWW) and Municipal (MWW). AD is anaerobic digester.



With the Status Quo policies there are no abatement options that would be commercially viable without additional support (whether this took the form of external carbon price or other policies to reduce waste or encourage energy recovery from waste). This reflects the relatively limited requirements for waste disposal and limited policy directed at reducing waste generation. Without additional policies to reduce the amount of waste going to landfill or open dump sites and to reduce the amount of organic material that is disposed of, most abatement opportunities are not immediately profitable. The current levels of support available for use of biogas recovered from waste disposal (for example, for electricity generation) are generally not sufficient to stimulate widespread adoption. At positive costs of abatement, there is 13 MtCO2 of abatement potential from the Waste sector in 2020, increasing to 19 MtCO2 in 2030.

The cheapest options, below 50 EUR/tCO2, are improved wastewater treatment (both industrial and municipal), and the use of anaerobic digesters. Direct gas use from landfills is an option for landfill waste.

Mechanical and biological treatment of waste is more expensive, at over 95 EUR/tCO2.

4.8. Agriculture and Forestry

The agriculture sector emitted almost 40 MtCO2e in 200811, or 11 percent of the total emissions, excluding land use, land-use change and forestry (LULUCF). On the other hand, LULUCF was a net carbon sink, absorbing around 80 MtCO2e.

Appendix A.6 presents further information on the current state of the two sectors in Turkey.

The key abatement measures in Agriculture and Forestry include:

■ Conservation Agriculture. This measure covers several measures, including reduced tillage, residues management and crop rotation. Lesser mechanical disturbance of soils increases the soils’ retention rate of carbon, mainly by creating a layer of soil with high content of vegetative matter, including dead animals and plants. In addition, fossil fuel (mostly gasoil) consumption is reduced through less tillage, as agricultural machinery (tractors, ploughs) need to be run less.

■ Land conversion. Degraded land can be converted into carbon-retaining soils by suitably modifying the landscape, for example by terracing a hillside that was previously subject to erosion. This allows soil to accumulate on previously bare land, and to retain carbon in the form of soil and plants.

■ Pasture management. The carbon content of soils depends on the frequency of removing excess vegetative matter, typically grazing. The total amount of carbon absorbed can be increased by improving the pasture management – if over-grazed pastures are left to re-grow, while under-grazed pastures are grazed upon, the rate at which plants grow and act as a carbon “sink” can be maximised.

■ Biogas. Conversion of agricultural waste into bio-methane can lead to additional abatement, by displacing conventional natural gas or other fossil fuels. The main

11 UNFCCC inventory



limitation is the economic feasibility of using the produced bio-methane. The options include direct on-site combustion (typically for agricultural processes such as food treatment), on-site use for power generation, or injection of upgraded bio-methane into the gas grid. Power generation seems to be the most accessible of these options.

■ Fertiliser use. Reduction in fertiliser use is a common abatement measure in many countries. However, average fertiliser use in Turkey is not exceptionally high12, and we do not estimate any abatement from reduced fertiliser use.

■ Livestock management. Enteric emissions account for a majority of non-soil emissions. Improving livestock diet could reduce these emissions.

■ Forestry – Degraded forest restoration. Improved forest management can increase the rate of carbon retention of the existing forests.

■ Forestry – afforestation. We have assumed that the government afforestation target (as set out in the National Forestation Campaign) of 2.3 million hectares between 2008-2012 would be met.

12 Although there may be regional differences.

Greenhouse Gas Abatement in Turkey Planned Policies Scenario


5. Planned Policies Scenario

The second scenario takes into account significant policies that are in place or announced that are likely to have an effect on emissions. Where policies currently exist but are not well enforced (as in the case of building standards) we assume that they are enforced more strictly.

5.1. Policy Settings and Assumptions

5.1.1. Fossil fuel markets and subsidies

In this scenario we include the following differences from the Status Quo scenario:

■ Phase-out of support for coal mining. The policy of state support for coal mining is phased out. However, there is no impact on prices, which are dominated by the cost of imported coal.

■ Liberalisation of gas market. Liberalisation of gas market and end of take-or-pay power contracts for BOT and BO generators by 2020 results in higher gas prices for industrial and other customers. We assume a 10 percent increase in retail and wholesale gas prices relative to the Status Quo scenario.

■ Elimination of electricity cross-subsidies. Regulatory changes reduce the cross-subsidy of household / commercial electricity by industry. As a result, residential and commercial prices increase by €0.01/kWh, and industrial prices fall by an equivalent amount.

5.1.2. Power

We maintain the same assumptions for market structure and energy security targets for fossil fuels as in the Status Quo scenario. However, the support structures for renewables and nuclear power differ, as do constraints on interconnection.

5.1.2.1. Renewable electricity

Proposals to revise Turkey’s pre-existing feed-in tariff regime were ratified by the legislature in December 2010. The new proposals are more generous in several cases, and provide for more differentiation by fuel. The levels are summarised in the table below.

Table 5.1 Proposed Feed-In Tariff Levels

Technology FIT (€/ MWh) Wind Hydro

55

Geothermal 80 Solar Biomass

100

Although the FIT levels in several cases are lower than current and expected wholesale prices, they provide additional revenue during periods when wholesale prices are at lower levels. By the same token, they help mitigate the risk that commodities prices fall and lead to lower



power prices. We assume that this leads to a lower risk premium for the financing of renewables.13

5.1.2.2. Nuclear power

Turkey has not made use of nuclear power to date, but in common with many countries has the ambition to add new nuclear capacity. A significant step was taken in 2010 with a contract for 4.8 GW of capacity with ROSATOM.

There is an ongoing debate about the feasibility of either privately developed or state-supported nuclear power in liberalised electricity markets. There is little recent experience, and cost estimates vary widely, while individual projects have encountered significant difficulties. The financial viability of nuclear power is sensitive to several factors, including the risk of cost over-runs and delays, in part from regulatory requirements14; the terms of financing for the initial capex; and the risk that lower future power prices will reduce revenues to the point debt servicing and / or company solvency is under threat15.

In this scenario our intention is to indicate the abatement cost and potential of a nuclear programme where these potential difficulties are overcome, thus making feasible the aspired expansion of nuclear power. We assume that nuclear is developed not through private investment, but through government contracts, with favourable financing terms at the level of government borrowing rates and price guarantees to mitigate future revenue risk. Transaction costs associated with regulatory requirements are assumed to be borne not by the nuclear programme, but by society. These are deliberately optimistic assumptions to indicate the technical abatement potential.

We assume that up to 5 GW of nuclear capacity could be constructed by 2023, and an additional 10 GW by 2030.

5.1.2.3. Interconnectors

There are plans to increase electricity transmission interconnector capacity between Turkey and Georgia to allow for the export of Georgian hydropower to Turkey. In this scenario the interconnector is assumed to be completed, making available up to 1.7 GW of capacity (around 5 TWh / year) of hydropower to the Turkish power market.16

13 Although feed-in tariffs can significantly reduce market risk, they also introduce regulatory risk if there is a perceived

risk that the government may fail to honour the pledged support once investments have been made. This traditional regulatory dilemma is especially acute with technologies like wind and hydro, which have very large up-front costs but virtually no short-run marginal costs. In this scenario, we have not made allowance for this in the modelling. This is because the modelling is intended to show the impact of a successful FIT regime in which investors have confidence.

14 Notable examples include cost over-runs and delays at Olkiluoto in Finland and Flamanville in France 15 For example, British Energy was provided with significant financial support by the UK government in 2002 to offset

the effects of low wholesale prices for electricity. 16 Econ Pöyry AS. “Electricity export opportunities from Georgia and Azerbaijan to Turkey.” (not dated). The report

identifies four hydro-power sites with peak capacity of 1.7 GW, and output potential of 5.3 TWh. Although the interconnector currently has a capacity of 1 GW, the modelling by Econ Pöyry suggests that this will only constrain export two months of the year. The report also suggests that smaller hydro sites could also make use of the interconnector outside the seasonal peak. The interconnector may also be expanded further in future years.



5.1.3. Buildings

The scenario differs from the Status Quo in the effective enforcement of building standards and the implementation of information and certification schemes to reduce transaction costs.

5.1.3.1. Building regulations

Existing building regulations include minimum specifications for insulation, requirements to use communal heating systems with condensing boilers in multi-occupancy buildings, and a requirement to fit heat metering systems.

In this scenario we assume that these provisions are enforced, so that all new construction at least meets the prevailing norms. Achieving this would likely require significant institutional strengthening, not only through the inspection of licensed buildings, but also through a reduction in unlicensed building.

Building standards have the potential to reduce transaction costs, compared to a situation where decisions are made by individual home owners or building developers. On the other hand, like all mandates there is a risk that additional costs are incurred because there is reduced flexibility to account for variation in building requirements and features. We assume that there is no net change to transaction costs as a result of the mandates.

5.1.3.2. Certification and information schemes

Existing regulations include provisions for certification of various aspects of energy performance of buildings. These are strengthened to include certification and energy rating. These are assumed to help reduce transaction cost of energy efficiency measures, by giving building users and occupants better tools to understand the energy use characteristics of buildings, and to reduce the cost of acquiring this understanding. This serves to increase the demand for more energy efficient buildings somewhat, which in turn influences the choices of building developers. It also may help owner-occupiers to make better-informed decisions about improvements to existing buildings.

5.1.4. Other Major Emitting Sectors

We assume no differences from the Status Quo scenario for other sectors.

5.2. Planned Policy: Overall MACC

The economy-wide MACCs for the Planned Policy scenario in 2020 and 2030 are is presented on the following page.



Figure 5.1 Full MACC, Planned Policy, 2020

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GeothermalLandfill gas

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Municipal waste waterBuildings (R)

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Figure 5.2 Full MACC, Planned Policy, 2030

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Our analysis suggests that under Planned Policies, there is potential to reduce emissions in 2020 (relative to the “frozen technology” baseline) by around 80 MtCO2e through profitable investments, even without a carbon price or additional climate policies. The potential emissions reductions rise to 166 MtCO2e in 2030. Taking into account all measures, including those that have a positive cost (i.e. those that are not profitable without a carbon price or further policy changes), the potential abatement more than doubles to 163 MtCO2 in 2020, and increases to 375 MtCO2 in 2030.

In 2020, the average cost of profitable abatement measures is -€95/tCO2. This falls to -€110/tCO2 in 2030. These measures yield a total “surplus” or profit in 2020 of €8 billion and €18 billion in 2030. Across the entire MACC up to €150/tCO2 (in real terms), the average cost per tCO2 is €2 in 2020, and -€20 in 2030.

5.3. Power


The main difference between the Planned Policy scenario and the Status Quo is the addition of nuclear power to the generation mix. 15 GW of nuclear power is added over the next two decades, and by 2030 it provides around one-sixth of generation. The expansion of nuclear comes at the expense of gas-fired generation, due to the factors discussed above in relation to the Status Quo scenario (notably, high projected gas prices in the 2020s, which is the period when any large-scale addition of nuclear is first feasible).

The modelling does not indicate that planned policies lead to a significant expansion of hydropower and wind over the levels in Status Quo. This is because the FIT levels for wind, although increased, still are below the modelled wholesale prices for electricity and insufficient to make lower-quality wind sites attractive.17 As for hydropower, an additional 5 TWh of imported hydropower from Georgia is made available, but there is no difference relative to Status Quo in the expansion of domestic hydropower resource. The increased FIT levels for biomass / biogas do result in profitable opportunities for the use of landfill gas for power generation, although the total capacity remains relatively low at under 1 GW. Overall, fossil-fired sources of generation account for just under 40 percent of generation by 2030.

17 A more detailed power market modelling exercise (notably, with a more granular supply curve for key technologies)

may be able to demonstrate more of a difference from the recent increase in FIT levels.



Figure 5.3 Power Capacity Projection, Planned Policies



Figure 5.4 Power Generation, Planned Policies



Figure 5.5 Power Emissions, Planned Policies


MACCs for the Power Sector under the Planned Policy scenario in 2020 and 2030 are shown on the next page.



Figure 5.6 Power Sector MACC, Planned Policy Scenario, 2020

CCGT (H)

Geothermal

CCGT (Very-H)

CCGT (H)

CCGT (Very-H)Hydro (Georgia)

CCGT (Very-H)

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Figure 5.7 Power Sector MACC, Planned Policy Scenario, 2030

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Under the favourable policy assumptions applied in the Planned Policies scenario, nuclear power is viable without further support and appears in the negative cost portion of the MACC, with emissions reductions of nearly 50 MtCO2 by 2030. There also is the addition of imported Georgian hydropower, with abatement of just under 3 MtCO2. Combined with the wind, gas, and hydro abatement options that were also present in the Status Quo, the total amount of abatement that comes forward profitably is 41 MtCO2 in 2020, increasing to 92 MtCO2 in 2030.

In addition to investments in generating capacity, cost-effective investments in upgraded and new grid infrastructure (not shown in the chart) help reduce distribution losses and provide additional emissions reductions of 8 MtCO2 by 2030

There are relatively limited opportunities to achieve additional abatement at higher carbon costs by 2020. Options below $100 / tCO2 include some additional hydropower (domestic and imports), and limited amounts of new gas-fired generation. Beyond this point, the options include technologies such as co-firing, but are dominated by the opportunity to shift away from coal-fired generation and lignite through increased availability of gas-fired capacity as well as increased generation.

By 2030, additional abatement potential is available beyond the 92 MtCO2 through hydropower ($20/tCO2), geothermal ($30/tCO2), and new gas ($50-80/tCO2). Beyond this point, additional gas dominates, with contributions from expensive windpower, biomass co-firing and other minor technologies. These appear as very high-cost options, as they would require the construction of new plant and premature closure of existing coal and lignite capacity.

5.4. Buildings

Under the “Planned Policies” scenario, there is increased use of gas condensing boilers. Overall, however, there are only small differences between the fuel mix in the Status Quo scenario and the mix in the planned policies scenario. This is because there are limited differences in end-user fuel prices between the two scenarios, and these are not sufficient to affect other factors such as convenience and differences in capex.

Insulation rates for residential buildings do increase in the planned policies scenario. Better enforcement of regulations eliminates the option of building new uninsulated buildings. The number of dwellings without any insulation measures declines between 2010 and 2030 by 43 percent, compared to a decline of 16 percent in the Status Quo. The total share of dwellings without any insulation is just under a quarter by 2030. Dwellings with significant insulation account for nearly two thirds of all dwellings in 2030, compared to less than half in the status quo. Adoption of solar water heating also increases. There is also an increase in the adoption of insulation measures in commercial buildings.

■ In the planned policy scenario, total direct emissions from residential buildings fall from 49 Mt CO2 in the Status Quo to 42 MtCO2e by 2030.

■ In commercial buildings, the fall in emissions is less significant, with total emissions falling to 13 MtCO2e in 2020 in the pledged policies scenario compared to 14 MtCO2e in the status quo scenario. By 2030, emissions stand at 14 Mt, compared to 15 in the status quo scenario.



For residential buildings, the rapid fall in the emissions intensity and total emissions reflects:

■ Significant upgrades of buildings without insulation. Dwellings without any insulation measures account for less than a quarter of the total stock of dwellings, compared to 36 percent in the status quo. This reflects both stronger building regulations and increased awareness (and reduced transaction costs) resulting from building energy performance information. Increases in the price of gas relative to the Status Quo also provide some additional incentive to improve insulation.

■ The higher adoption rate for heat meters and thermostats contributes significantly to a reduction in emissions. These measures are relatively straightforward to install and are reflected in building energy ratings; they are also required in new multi-occupancy buildings. By 2030, 52 percent of all dwellings have a thermostat installed, compared to just 22 percent in the Status Quo. This reduces emissions by 4.5 MtCO2e in 2020 and 5.7 MtCO2 in 2030 (compared to 2.2 and 2.4 MtCO2e in the Status Quo scenario).

The most significant source of the difference in emissions from non-residential buildings between the planned policies and status quo scenario is the higher adoption of metering, controls and thermostats. These lead to emissions reductions by 2020 of 1.5 MtCO2e, and 2 MtCO2e by 2030, compared to 1 and 1.1 MtCO2e in the status quo scenario.


Under the planned policy scenario, the reduction in emissions that would occur without further policy intervention increases substantially relative to the Status Quo. By 2020, the reduction in emissions without is 21.8 MtCO2e, and this rises to 39.3 MtCO2e by 2030 (compared to 12.3 MtCO2e and 23.9 MtCO2e by 2020 and 2030 in the Status Quo, respectively).

Abatement potential at costs below €50t/CO2 is 4.0 MtCO2e by 2020, and 4.5 MtCO2e by 2030. This is similar to the Status Quo scenario. The abatement potential at costs below €150t/CO2 is 12.7 MtCO2e by 2020 and 16.5 MtCO2e by 2030.

Moving along the positive part of the MACC, there are three prominent abatement opportunities that lead to abatement of greater than 1 MtCO2e:

■ At a cost of €26/tCO2, a combination of insulation and condensing gas boilers in residential dwellings can lead to abatement of 1.3 MtCO2e.

■ At a cost of €41/tCO2, there is further potential for 1.3 MtCO2e abatement from additional insulation in residential buildings.

■ Further along the MACC, a combination of insulation and gas condensing boilers in commercial buildings have the potential to reduce emissions by 3.6 MtCO2e at a cost of €66/tCO2.

Other measures that represent significant sources of abatement (greater then 0.5 MtCO2e) by 2030 include the use of solar water heating in residential buildings (0.7 MtCO2e at €127/tCO2) and fuel switching (0.8 MtCO2e at 137 €/tCO2).



Figure 5.8 Buildings MACC, Planned Policy, 2020

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Figure 5.9 Buildings MACC, Planned Policy, 2030

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5.5. Other Major Emitting Sectors (Industry, Transport, Waste and Agriculture)

The Planned Policies reflected in the modelling do not involve significant changes to those modelled for the Status Quo for other major sectors. As a consequence, the emissions and abatement potential from these sectors do not change materially relative to the results reported in sections 4.5- 4.8.

Greenhouse Gas Abatement in Turkey Enhanced Policy Scenarios


6. Enhanced Policy Scenarios

6.1. Policy Setting and Assumptions

In the low carbon policy scenario, we consider a number of extensions to the currently planned policies to make viable a range of additional abatement measures.

6.1.1. Energy Market Structure and Subsidies

6.1.1.1. Free lignite provision

In addition to the policies in the “Planned Policies” scenario, the provision of free lignite to poor households is phased out. The underlying social objectives of supporting these households are pursued instead through other means that do not have an impact on the relative attractiveness of fuels with different carbon intensity (e.g., a general support payment to be applied to space heating energy consumption, or a lump-sum welfare transfer). This allows for the gradual shift away from lignite to other fuels, according to their relative attractiveness depending on the characteristics of the relevant buildings.

6.1.1.2. Gas availability

The scenario also is a “high-gas” scenario. Although improved energy efficiency reduces the overall demand for energy, other drivers in the scenario (notably, carbon pricing and relaxed energy diversity requirements – see below) lead to increased demand for gas. We assume that sufficient gas imports are available. (This could be from the completion of the Nabucco and other pipelines, significant expansion of the LNG market, etc.)

6.1.2. Power

6.1.2.1. Energy security targets for fossil fuels

As noted above, the limitations on gas and support for lignite-fired generation leads to higher emissions in the Status Quo and Planned Policy scenario. In the Enhanced Policy scenario we remove these constraints, so that there is no specified minimum or maximum deployment of these technologies. Instead, the technologies are taken up according to their modelled financial attractiveness.

6.1.2.2. Feed-in tariffs for renewable electricity

As noted above, the currently planned FITs to key technologies are below wholesale electricity prices for much of the peak demand period; depending on the generation profile, power plant operators therefore may be better off by accepting the wholesale price instead.

Although the combination of high wholesale electricity prices and the currently proposed FITs appears able to bring forward a non-negligible expansion in wind and hydro-power, they may not be sufficient to bring forward the full potential for renewables. Additional expansion will require the use of less favourable resources (lower wind-speed, lower load factor hydro, more remote, or more technically difficult) sites, with increasing costs and / or reduced revenues as a result.



In this scenario FITs are increased by a further €15 / MWh on the levels in the Planned Policy Scenario. This matches some of the levels provided internationally, and also are at levels that our modelling indicates is sufficient to make some of the less favourable renewable generation attractive.18

Technology FIT (€/MWh)

Wind 70 Hydro 70 Solar 115 Biomass 115 Geothermal 95

Other 70

6.1.2.3. Carbon pricing

The power sector is exposed to a carbon price through the incorporation in the EU Emissions Trading Scheme. The price of allowances is assumed to be €40 / tCO2.

6.1.2.4. Capital Grants

Investments in the power sector are eligible for capital grants provided they reduce emissions. We assume that new renewable and nuclear power capacity is eligible for the capital grant, as they are zero emitting. We also assume that investments in new gas power plants are eligible for the grant, as they reduce emissions significantly relative to investments in new coal-fired power stations. Given the Government’s announced aspiration to significantly reduce reliance on gas as a fuel source for electricity production, this policy would represent a significant reversal that may not be plausible. Without it, however, there would continue to be significant investment in coal and lignite at the expense of natural gas investments.

6.1.3. Buildings

In the Enhanced Policy scenario we also include significant additional interventions to promote the uptake of energy efficiency in buildings. The options open to Turkey include many of the key policy approaches that have been pursued in more developed countries with long-standing energy efficiency policy, including:

■ “Soft loans” programmes to make available finance for energy saving investments at favourable loan terms. This could have a significant impact in Turkey, where there is only a limited mortgage market and access to personal loans is limited and dominated by short loan terms at relatively high interest rates. Building owners, residents, and investors are assumed to be able to access these financial terms, which significantly reduce the up-front cost that investors face for energy efficiency measures.

18 A full assessment of the support required to bring about the full technical potential assumed here would require the

development of a significantly more detailed supply curve for renewable electricity than has been feasible within this project.



■ An obligation (potentially including a “white certificates” program or similar “demand side management” policy) to mandate the deployment of energy efficiency measures in the building stock. These can accelerate the rate of uptake of energy efficiency measures, through stronger incentives for proactive promotion and awareness campaigns by a range of private organisations. They also can reduce transaction costs through economies of scale and larger supply chains; lower financing costs by involving energy-service companies and / or utilities; and in some cases result in direct subsidies for selected measures.19

■ Various strengthened information measures, including widespread building energy rating certificates, energy audit services, requirements for energy audits, and similar.

These have in common that they use a combination of subsidies to reduce cost and measures intended to accelerate or force uptake, improve supply chains, or increase awareness. For example, white certificates work in two ways: by imposing an obligation on some party to deliver energy savings, and by facilitating a more liquid and competitive market for energy efficiency and energy services, including disseminating information and developing expertise in the relevant product / services markets. In many white certificate schemes the energy consumer or building owner – who are often the investors – do not actually “see” the policy, because they do not have any incentives to acquire certificates. It is more likely that they will simply have greater exposure to vendors offering energy efficient products, or receive better, more qualified advice and information, or be offered services from businesses that are more secure because of the policy framework, and that therefore have lower costs of financing. The main impact of the white certificates scheme, therefore, is to reduce the transaction costs that the investor / consumer faces and to reduce hurdle rates.

A successful combination of these policies can help reduce transaction costs, lower hurdle rates, and overcome some of the inertia in the uptake of energy-saving measures that otherwise characterises households and organisations for which energy costs are a small share of overall expenditure. Concretely, the Enhanced Policies scenarios reduce transaction costs from 20 to 10 percent of capital expenditure and reduce hurdle rates for building investments from 18 percent to 15 percent.

6.1.4. Industry

As noted in the discussion in section 4.5, much of the GHG emissions abatement potential in industry arises through the scope to save on fuel use through more energy efficient technologies – supplemented by opportunities for fuel switching, raw material substitution and waste utilisation, the incineration or reduction of non-CO2 GHGs, and potentially through the capture and sequestration of CO2.

Turkish industry in general faces fuel prices on a par with those in international energy commodity markets, which on their own provide strong incentives for the gradual adoption of more efficient technologies. Provided other aspects of the investment climate are conducive, financial incentives for investments in many cases are present in many sectors.

19 Like all mandates, such programmes also carry the obverse risk of requiring the installation of measures that are in fact

not cost-effective or otherwise desirable.



It is possible to strengthen these incentives through additional policy interventions. Key options Include:

■ Energy efficiency benchmarking and covenants;

■ Carbon prices and related taxes;

■ Capex subsidies

6.1.4.1. Energy efficiency

Several countries have promoted energy efficiency in industry through programmes to establish energy benchmarks, company reporting of performance against these benchmarks, and negotiated targets to achieve energy efficiency improvements according to a specified timetable. These often have been complemented with services to offer subsidised or free energy audits and other support.20

The intention of these programmes is to help disseminate information about best practice and to focus management attention on energy efficiency. This can reduce transaction costs and accelerate uptake of measures that appear financially attractive. In some cases, these have been combined with exemptions from taxes or carbon pricing linked to achievement of standards (e.g., UK Climate Change Agreements).

6.1.4.2. Carbon pricing

We also model a scenario with industry exposed to a carbon price. This takes the form of including Turkish industry in the EU Emissions Trading Scheme (EU ETS), covering those sectors included are those currently included in the EU ETS, including most of heavy industry and the power sector. These are assumed to be exposed to a carbon price of €40 / tCO2.

For sectors not included in the EU ETS we model the potential for credit-based emissions trading. These include the waste and coal mining sectors, gas pipelines, and agriculture, which are assumed to be exposed to a carbon price of €20 / tCO2, reflecting our assumption about primary emissions reduction credit prices under current arrangements under Joint Implementation and the Clean Development Mechanism.

Carbon prices have the advantage that they promote all types of abatement measure – including energy efficiency, fuel substitution, raw material substitution, as well as reduction in non-CO2 emissions and carbon capture and storage, provided these are counted towards obligations or credit opportunities under the relevant emissions trading regime – and moreover , they apply the same (marginal) incentive for each option. They therefore have the potential to achieve a given amount of emissions abatement at least cost. Another advantage is that they are scaleable, so that a large number of industries and sectors can be incorporated. A disadvantage of carbon prices is the potential for adverse impacts on competitiveness in a situation where major competitors do not adopt similar measures.

20 Prominent examples include the UK Climate Change Agreements and Dutch industrial benchmarking programme.



6.1.4.3. Other enabling policies

In addition to intervention directly in industry sectors, we model policies to help overcome the obstacles to using waste materials for various abatement measures, as outlined in section 4.5.2. With sufficient support for the use of clinker substitutes as well as waste fuels, significant additional abatement potential can be unlocked, especially in the cement sector.

6.1.4.4. Capital grants

We also model a capital grants programme on the lines outlined in section 6.1.6.

6.1.5. Other major emitting sectors (Transport, Waste and Agriculture)

6.1.5.1. Waste

There are opportunities to reduce emissions by use of various streams of waste materials. These include energy from municipal waste incineration, capture of methane from landfill sites, biomethane production from biological wastes through anaerobic digestion or other treatments, and the combustion of other specific waste streams such as tyres and solvents. There also are opportunities to use specific waste streams such as power station fly ash and blast furnace slag for clinker substitution in cement production.

These abatement options are unlikely to become available without regulatory support that makes it more difficult to dispose of waste at traditional open dumps or landfills – thus raising the cost of disposal and reducing the cost of waste materials (or waste fuels) for other uses.

In this scenario we assume that the required regulatory and other measures are put in place, enabling the uptake of waste-related abatement. The affected sectors include power generation, the waste sector itself, and selected industrial sectors (notably, cement production). In these sectors, the combination of increased cost of traditional waste-disposal methods and the existence of either a carbon price that rewards abatement (and that imposes a cost on emissions) or a capital grant for more advanced waste treatment technologies renders some abatement from the sector financially attractive.

6.1.6. Capital grants

As noted, the second variant of the Enhanced Policies scenario models the implementation of a capital grants schemes, lowering the effective capex of technologies that reduce emissions if adopted.

The policy is modelled across the board in all sectors, with grants corresponding to 20 percent of the incremental capex of technologies that reduce emissions. This has an impact particularly on energy efficiency measures, but does not capture ongoing process changes or other measures where capex is a less significant aspect of abatement cost.

The scenario modelled here helps illustrate the principle of capital subsidies, but does not reflect the practical implementation difficulties that such programmes often face. Although there are many international examples of capital grants (often implemented through tax allowances or exemptions), none is nearly as comprehensive or far-reaching as the



intervention modelled here. This reflects the fact that large-scale grants programmes often face significant implementation difficulties, including determining the qualifying technologies and the level of grant for different technologies; committing sufficient funding for the very substantial subsidy sums involved; and ensuring that subsidised equipment is efficiently used (notably in the power sector).

6.2. Enhanced Policy Scenarios: Overall MACCs

Summary MACCs for the overall economy under the Enhanced Policy scenarios are shown on the next two pages – the first two figures show the results for the Enhanced Policy scenario with carbon prices; the third and fourth figure show the results with capital grants.



Figure 6.1 Full MACC, Enhanced Policy (Carbon Prices), 2020

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Figure 6.2 Full MACC, Enhanced Policy (Carbon Prices), 2030

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Figure 6.3 Full MACC, Enhanced Policy (Capital Grants) Scenario, 2020

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Figure 6.4 Full MACC, Enhanced Policy (Capital Grants) Scenario, 2030

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The analysis suggests that under Enhanced Policies, there is potential to reduce emissions in 2020 (relative to the “frozen technology” baseline) by around 127 MtCO2e through profitable investments, even without a carbon price or additional climate policies. The potential emissions reductions rise to 256 MtCO2e in 2030. Taking into account all measures, including those that have a positive cost, the potential abatement more than doubles to 202 MtCO2 in 2020, and increases to 338 MtCO2 in 2030.

In 2020, the average cost of profitable abatement measures is -€120/tCO2. This falls to -€128/tCO2 in 2030. These measures yield a total “surplus” or profit in 2020 of €15 billion and €33 billion in 2030. Across the entire MACC up to €150/tCO2 (in real terms), the average cost per tCO2 is -€49 in 2020, and -€84 in 2030.

6.3. Power


The Enhanced Policy scenario contains policies that go a long way towards significant decarbonisation of the Turkish power sector. Apart from the substantial contribution from nuclear that was also in the Planned Policy scenario, there also is a significant expansion of renewables on the back of generous feed-in tariffs and – in the carbon prices variant of the scenario – a significant carbon price. By 2030, hydropower potential doubles to exploit the full estimated potential, while 30 GW of wind is added. Biogas from landfill gas and other sources is exploited to produce power – although the total capacity is small relative to other technologies. In addition, the carbon price means gas is preferred to other fossil fuels, so that there is no new coal plant. Overall, 60 percent of capacity and just over half of generation come from non-fossil sources by 2030.

These developments reduce emissions substantially. Although generation increases by more than 150 percent, emissions increase by no more than 50 percent. Emissions are cut in half compared to Status Quo as a result.



Figure 6.5 Power Capacity Projection, Enhanced Policies (Carbon Prices)



Figure 6.6 Power Generation, Enhanced Policies (Carbon Prices)



Figure 6.7 Power Emissions, Enhanced Policies (Carbon Prices)

As an alternative (or a complement) to imposing a carbon price on the Power sector, the modelling of the Enhanced Policies with capital grants scenario indicates that a similar generation mix can be achieved through providing substantial grants to renewable technologies, and to very-high efficiency CCGT.

As in the Enhanced Policies scenario with carbon prices, capital grants (combined with the various other relevant policies) motivate a transition away from fossil fuels towards renewables and nuclear power. This includes the full hydro potential, 4.5 GW of geothermal and 30GW of wind being exploited by 2030.

The grants also have a significant impact on the uptake of very-high efficiency CCGTs in the second decade of the scenario. In the absence of such grants, much of the fossil fuel generation would remain or become more coal/lignite-based, with correspondingly high carbon emissions. Providing a capital grant to CCGTs offsets the higher price of gas in these years. Even so, towards the end of the 2020s, a small amount of new coal generation capacity is built, as the relative coal and gas prices make some new coal plants profitable.


Because all available hydropower and wind power developments are rendered financially attractive, the cost-effective portion of the MACC is significantly larger in the Enhanced Policy scenario than in either Status Quo or Planned Policy scenarios. By 2020, a combination renewables (primarily wind, hydro and geothermal power plant), nuclear power,



and high-efficiency gas-fired power plant reduce emissions by 65 MtCO2 compared to what the same generation would emit if produced with the current average emissions intensity. By 2030, the cost-effective emissions reductions increase to 140 MtCO2.21

Again, as in the Planned Policies scenario, cost-effective investments in upgraded grid infrastructure (not shown in the chart) reduce distribution losses and cut emissions by 8 MtCO2 by 2030

Because most low-carbon technologies have reached the maximum deployment feasible given growth and resource constraints, much of the remaining potential depends on the substitution of residual coal and lignite generation with gas, and with some co-firing of biomass. This could cut emissions by a further 40 MtCO2 by 2030. As in the previous scenarios, the implied carbon cost is relatively high, as it requires the closure of existing coal and lignite capacity in favour of new gas capacity.

Figure 6.8 Power Sector MACC, Enhanced Policy (Carbon Prices) Scenario, 2020

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21 In fact, because the capacity displaced is not the average current capacity, but primarily coal- and lignite-fired power

production, if measured against a baseline of the “Planned Policies” the Enhanced Policies would show even greater emissions reductions.



Figure 6.9 Power Sector MACC, Enhanced Policy (Carbon Prices) Scenario, 2030

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The Enhanced Policies scenario with Capital Grants offers abatement potential similar to the potential from the Carbon Prices scenario. However, the Carbon Prices policy option creates greater incentives for investors, because of the additional costs faced by counterfactuals as a result of the carbon price. These incentives are illustrated by a comparison of the average net abatement costs for the power sector under the two scenarios. In the Carbon Prices variant, the average “benefit” per tonne of profitable emissions reductions is €114/tCO2 . Under the Capital Grants variant, the average benefit is €49/tCO2. With the capital grants, although abatement technologies are given incentives through the capital subsidy, the disincentive to counterfactual technologies under the carbon prices scenario provides stronger overall incentives for abatement.

6.4. Buildings

Under the “Enhanced Policies” scenario:

■ Total direct emissions from residential buildings are 34 MtCO2e in 2020, compared to 37 MtCO2e in the Planned Policies scenario. By 2030, emissions in the Enhanced Policies scenario are 8 percent lower (at 38 MtCO2e).

■ There is also a reduction in emissions from commercial buildings. Total emissions in 2020 are 12 MtCO2e compared to 13 MtCO2e in the Planned Policies scenario. By 2030, emissions are 7 percent below the level under the Planned Policies scenario (at 13 MtCO2e).

For residential buildings, the reduction in emissions relative to the Planned Policies scenario largely reflects a further increase in the number of dwellings with at least one insulation measure. This uptake is driven by the new financing options available as a result of soft loans, as well as the reduced transaction costs due to the increased activity of energy companies who are obligated to deliver energy efficiency measures, driving economies of



scale and expanding the activities of ESCOs and other companies associated with the delivery of efficiency measures. The share of dwellings with no insulation falls to 18 percent by 2030, compared to 24 percent in the Planned Policies scenario. There is also a further modest increase in the use of gas condensing boilers, the share of which is 2 percentage points higher in 2030, relative to the Planned Policies scenario. The combined share of lignite and coal is also lower in 2030. This is due to the above, and also reflects the elimination of the policy to provide free lignite to poor households, which results in these households choosing their heating source based on actual costs, rather than using lignite by default. In addition, relative to the Planned Policies scenario, the price of gas is lower, and this contributes slightly to the reduction in coal use. Overall, however, there are only small differences between the fuel mix in the Planned Policies scenario and the mix in the Enhanced Policies scenario. Finally, there is an increase in the use of solar water heaters, again reflecting reduced financing and transaction costs.

In commercial buildings, the reduction in emissions reflects a decline in the share of commercial space that is heated by coal, the share in 2030 being 4 percentage points lower than the Planned Policies scenario. Insulation measures also increase their penetration in commercial buildings, as developers and occupants take advantage of the improved financing terms and the advice / expertise offered through the energy supplier obligation. Commercial area without any insulation measures falls by 14 percent between 2010 and 2030, compared to only 3 percent in the planned policy scenario.


Under the Enhanced Policy scenario, the profitable emissions reduction potential increases further relative to the Planned Policy scenario. By 2020, the reduction in emissions without additional policy is 25.3 MtCO2e, and this rises to 42.9 MtCO2e by 2030 (compared to 21.8 MtCO2e and 39.3 MtCO2e by 2020 and 2030 in the Status Quo, respectively).

There are several measures that contribute to the further reduction in emissions. Some of the most significant ones include greater reductions in emissions from:

■ solar water heating new residential buildings;

■ retrofitting of both residential and commercial buildings with insulation measures; and

■ retrofitting of residential buildings with a combination of insulation and/or condensing gas boilers.

Abatement potential at a cost of €50t/CO2e is 5.7 MtCO2e by 2020 and 6.2 MtCO2e by 2030 (compared to 4.0 MtCO2e and 4.5 MtCO2e in the Planned Policy scenario by 2020 and 2030, respectively). Abatement potential at cost of €150t/CO2e is 8.7 MtCO2e by 2020 and 13.8 MtCO2e by 2030.

The largest single source of abatement at a positive cost by 2020 is a combination of greater insulation and condensing gas boilers in commercial buildings. At a cost of €19/tCO2, these lead to abatement of 2.8 MtCO2e. By 2030, there are several other instances of abatement measures being taken up that lead to significant additional reductions in emissions at positive cost. These include:



■ insulation and condensing gas boilers in commercial buildings leading to abatement of 2.9 MtCO2e at a cost of €16/tCO2;

■ insulation and condensing gas boilers in residential buildings also leads to large emissions reductions, including abatement of 1.1 MtCO2e at €91/tCO2, 1.1 MtCO2e at €107/tCO2 and 1.3 MtCO2e at €132/tCO2;

■ greater adoption of solar water heating, leading to abatement of 0.5 MtCO2e at €88/tCO2 and 0.8 MtCO2e at €128/tCO2.

Figure 6.10 Buildings MACC, Enhanced Policy, 2020

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Figure 6.11 Buildings MACC, Enhanced Policy, 2030

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6.5. Industry

The Enhanced Policy MACC for Industry is shown below. The cost-effective abatement potential in 2030 increases significantly, from 13 MtCO2 in the Status Quo scenario, to 28 MtCO2 in the Enhanced Policy case.

The largest single contribution to additional abatement is found in the cement sector. Additional adoption of energy efficiency improvements are attractive with the new policies, but the biggest contribution comes from the use of waste and biofuels as well as the substitution of up to 30 percent of clinker for other materials in up to half of cement production. The importance of the cement industry for overall industrial emissions mean these have a significant impact, making more than 10 MtCO2 of additional abatement attractive. To achieve these theoretical savings, significant modifications to waste handling would be necessary, as discussed in the foregoing sections.22

In addition to these additional abatement measures in the cement sector, a variety of additional abatement measures in other industries become financially attractive. The chief driver is that the carbon price in this scenario reinforces the savings on fuel costs available from increased energy efficiency. The impact is particularly large in the brick industry, with a much more complete transition from current old kiln technology to modern types by 2030 and a near-doubling of abatement potential to 2.4 MtCO2 as a result. Additional energy efficiency opportunities also become attractive across other sectors, including steel, ceramics, and refineries. However, in most cases the increased potential results more from the incremental adoption of a broad range of technologies than from any step-change in technology choice.

Finally, the price on carbon also makes attractive the destruction of non-CO2 GHGs in the chemical industry, notably from the production of nitric acid.

Although the carbon price means that the cost of using coal increases by 50 percent more than that of using natural gas, this is not sufficient to induce switching from coal to natural gas, which remains a very high-cost option for industrial heat / energy provision even in the more favourable policy environment.

We have not included CCS in this scenario. However, our calculations do not suggest that CCS could become an attractive option except with significant additional support.

Replacing emissions trading with across-the-board 20 percent capital grants generally does not provide the same level of incentive for industrial abatement options as does a carbon price of €40/tCO2. The difference is particularly marked where the incumbent fuel used is coal, but the (negative) “height” of the bars in the MACC is lower across most measures. On this criterion, a carbon price provides more assurances to investors that initial capex will be recouped. Because much of the potential is anyway negative-cost (relative to the static baseline), the impact on total volume of abatement is not as marked, with around 3 MtCO2 less abatement. The single most important category not incentivised by capital grants is the 22 Although we have modelled the cement sector as the sector that most readily can make use of waste fuels, it would be

possible to make use of waste incineration in other industrial and non-industrial applications. However, the overall abatement potential is limited by available waste as well as other factors.



destruction of non-CO2 GHG gases, but the same issue would apply to carbon capture and storage, which does not provide any ongoing benefit in the absence of a value placed on emissions.


The MACC for the Enhanced Policy Scenario, and the Industry sector is shown below.

Figure 6.12 Industry MACC, Enhanced Policy Scenario, 2030

0

Bricks Improved kilnNitric Acid Catalysts



Cement Energy Efficiency and Clinker Subst.


-50

Cement Modern Dry, Clinker Subst.Cement Waste firing, Energy Efficiency, Clinker Subst.

Cement Waste firing, Energy Efficiency, Clinker Subst.

Lime Energy Efficiency

Steel BOF Energy Efficiency

RefineriesCeramics Improved kiln

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e (E

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)

Greenhouse Gas Abatement in Turkey Conclusions


7. Conclusions

The present study identifies substantial emissions reduction potential in Turkey, relative to the “frozen” and policy Status Quo scenarios. As an economy in transition, Turkey’s GDP per capita is expected to continue to grow until it approaches typical European levels, and with this growth will come higher emissions. Because consumers in Turkey already face energy prices that largely reflect liberalised markets – and that in some cases are already higher than average – the energy intensity of Turkey’s economy is not markedly higher than that of other major European economies. So while significant improvements in energy efficiency are possible, they are broadly in line with improvements in other European countries.

This study analyses potential investment to reduce emissions from the perspective of the investor. In this respect it differs from many similar studies, and this also means that the study’s findings need to be understood for what they are. Investors seek a return on their capital, and in general are not concerned with whether or not a particular investment achieves certain policy outcomes. Although there are important exceptions, typical investors do not aim to have their investment optimise overall social welfare. But this means that an investment that is good for an investor is not necessarily optimal for society unless appropriate policies are in place to ensure that private incentives are aligned with social costs and benefits.

Typically, the distinction between social and private valuation is presented in the context of the failure of the private actor to appropriately value an external cost or benefit to society. In such cases, policies can be used to correct the “market failure”. But policies themselves can also distort private incentives so that they are not consistent with social costs and benefits. This may be true for certain subsidies for polluting investments – and it may be true for environmentally friendly investments as well. Thus a very high feed-in-tariff may provide an attractive return to investors in a particular renewable electricity technology, even though it may not be clear whether, from a social perspective, those particular green investments were desirable.

In the context of the present study, some policies may encourage more cost-effective abatement investments than others, leading to more abatement at lower cost. This is, for example, the conclusion that we can draw from the comparison of the two variants of the Enhanced Policies scenarios – the carbon prices variant delivers abatement on par with the capital grants variant, but involves financial incentives that amount to less than half what is required for the capital grants variant – €3 billion a year associated with the value of the emissions allowances or permits, compared to €6 billion a year associated with the support from capital grants. The best policy design will seek to provide incentives for investors that deliver the desired objectives without over-compensating or allocating resources inefficiently to sectors or technologies that are not the most cost-effective.

If the Turkish economy grew at a rate of around 4 percent annually over the period 2010-2030, but remained stuck at its current carbon intensity, its emissions would rise from 367 MtCO2eq in 2008 to 590MtCO2eq in 2020 and 852 MtCO2eq in 2030. Under the Status Quo scenario, technological improvements for new and replacement equipment reduces these emissions to 533 MtCO2eq in 2020 and 741 MtCO2eq in 2030. The Planned Policy scenario reduces emissions further – by around 44 MtCO2eq by 2030 – primarily as a consequence of



investment in nuclear and renewable power, as well as some increased uptake of building insulation and heating controls. The largest policy impact is in moving to the Enhanced Policy scenario, which has the potential to reduce emissions more than 200 MtCO2eq by 2030 relative to planned policies. As noted above, these reductions come from a variety of sectors, with the most significant of these a large-scale shift away from solid fuels (both lignite and hard coal) in the power sector.

Figure 7.1 Emissions Projections Under Different Scenarios

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1990 1995 2000 2005 2010 2015 2020 2025 2030

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issi

ons,

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Policy Status Quo

Pledged policiesEnhanced policy

358%298%

275%

163%

590 MtCO2eq

852 MtCO2eq

Choice of fuel in the power sector (and other sectors) is a major determinant of the future emissions trajectory in Turkey The power sector accounts for a substantial and growing share of emissions (currently 35 percent of combustion emissions), in part because demand for electricity is growing rapidly (at rates of 7-8 percent annually in recent years). In addition, the he Government’s energy strategy targets the full exploitation of indigenous lignite reserves, largely for energy security reasons. This results in a significant increase in emissions. Limiting the use of solid fuels would therefore substantially reduce emissions. For such a scenario to be feasible, however, the government would need to significantly increase its efforts to promote the development of renewable and other low-carbon energy sources. In addition, policy-makers in Turkey would need to be convinced that they would have reliable and affordable access to significant natural gas supplies.

An alternative to the increased use of gas would be a future scenario in which carbon capture and storage (CCS) technology matured to the point where it could provide a credible way to reduce emissions at an affordable cost. This would make it possible to increase reliance on emissions-intensive, indigenous solid fuels while keeping final emissions low. Such a scenario is highly speculative, however, as it depends on significant advances in CCS technology, including efficiency improvements and cost reductions.

Other sectors with significant abatement potential include the buildings sector, where policies to promote efficient heating systems and building design, insulation, and use of renewable



energy could have a significant impact. In industry, particularly Turkey’s large cement sector, there is also scope for significant emissions reduction, but this would require action by the government to promote more efficient use of waste fuels and other waste products. Development of energy and emissions intensity benchmarking programs for other industries would also stimulate investment in abatement. There is also significant scope to reduce emissions from the growing road transport sector through improved vehicle standards.

Figure 7.2 Summary Abatement, by Scenario

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Status Quo Planned Policies Enhanced Policies -Carbon Prices

Enhanced Policies -Capital Grants

Pro

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tCO

2eq

Buildings Power Transport Industry Waste

Note: The measures show the negative portion of the MACC, or abatement from measures that provide a net benefit for each tonne of CO2e reduced. (Unprofitable measures are those on the positive portion of the MACC, where abatement imposes a real cost per tCO2e.)

Greenhouse Gas Abatement in Turkey Detailed Sector Assumptions and Projections


Appendix A. Detailed Sector Assumptions and Projections

A.1. Power

A.1.1. Generation Capacity and Capacity and Fuel Mix

A.1.1.1. Capacity and generation mix

As of end-2009, Turkey had an installed capacity of 44,735 MW and generated 195 TWh of electricity. Net consumption is estimated to be around 157 TWh in the same year. Turkey consumes around 80 percent of its generation. The remaining 20 percent is constituted largely by losses and partially by foreign trade balance.

Electricity consumption in Turkey grew at over 6 percent annually between 1998 and 2008, but showed a decline of 3.1 percent in 2009, reflecting the effects of the economic downturn. The relative share of consumer groups did not show a significant change during this period. Around 50 percent of electricity is consumed by industry and about one-quarter of total consumption is for residential use. The net consumption per capita is about 2,162 kWh/year; still far below OECD average of 7-8,000 kWh/year.

Figure A.1 Electricity Consumption in Turkey

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1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Elec

tric

ity c

onsu

mpt

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(TW

h)

,

Industry Residential Commercial Offical Buildings Public lighting Others

Compond annual growth rate 6.3%

-3.1%

Source: TEDAS

Until the recent global recession, electricity generation had been growing at a rate around 8-9 percent per year in the last decade. However, production declined by 3.7 percent in 2008 and by 1.8 percent in 2009, reflecting the effects of the global financial crisis. Turkey generated 195 TWh of electricity with installed capacity reaching 44.7 GW in 2009. 80 percent of total generation was from thermal sources and the remaining 20 percent mainly from large-scale



hydroelectric power. Renewable power generation apart from hydro is very limited, at just 1 percent of the total. Natural gas has the highest share in power generation, accounting for 41-49 percent between 2003-2009. Since 2007, generation from lignite has surpassed hydroelectric power as the second-largest source of energy for electricity. Generation from imported coal showed a substantial increase in 2004, to 6 percent, following the 1,320 MW Isken power plant being put into operation.

Figure A.2 Electricity Generation in Turkey

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2003 2004 2005 2006 2007 2008 2009

Elec

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ity g

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n (T

Wh)

Hard Coal Lignite Imported CoalFO/DO/LPG/Naphta Natural Gas Biogas and OthersHydro Total Geothermal Wind

0%

20%

40%

60%

80%

100%

2003 2004 2005 2006 2007 2008 2009

Elec

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ity g

ener

atio

n (s

hare

s)

Source: TEIAS

A.1.1.2. Investment trends and reserve margins

Because of Turkey’s significant share of hydroelectric power and relatively limited interconnection, it has historically had a high reserve margin, but this has been declining in recent years. The reserve margin has dropped from a comfortable 64 percent in 2003 to a level around 30 percent23, (see Figure A.3). This trend was reversed in 2009, reflecting the demand decrease due to global economic recession. A reason for this narrowing demand-supply balance is the low rate of investments in new generation capacity, which was left to the private sector. The main reason for inadequate private investments was the government’s policy to keep prices constant. Since the electricity prices were fixed for nearly 5 years24 in local currency terms, in spite of rising oil and gas prices, profit margins of the private investors were dissipated. Other reasons behind the lacking investments included uncertainties in the regulatory environment due to the process of moving to a liberalized market and the effects of the recent global downturn.

23 This calculation takes into account that some thermal power plants were taken out of the plant portfolio due to

rehabilitation projects during certain years. 24 Electricity retail prices were fixed between March 2003 and January 2008.



Figure A.3 Reserve Margin in Turkey

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1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

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)

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Res

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(%)

Installed Capacity Instantenous Peak Reserve Margin

Source: TEIAS, IBS calculations

A.1.2. Renewable Electricity Resources and Deployment

As noted above, renewable electricity accounted for around 20 percent of electricity production in 2009, the vast majority of which was supplied by hydroelectric power plants (“HEPPs”). There is very limited use of other renewable sources of electricity, although there is significant use of renewable sources for heat energy (see Figure A.4), which could in some cases also be applied to power generation, as discussed below.



Figure A.4 Renewable Energy in Turkey (ktoe)

Renewable energy (9,400 ktoe)

Wood3,67940%

Animal and vegetable waste1,13412%

Geothermal1,15112%

Other4,87953%

Hydro2,86130%

Wind731%

Solar4204%

Modern biomass661%

Source: MENR – Energy Balance 2008

The Government’s Strategy Paper of May 2009 emphasizes the importance of “national” resources and sets targets for renewable energy. The target is to develop renewable projects to reach 30 percent share in total electricity generation by 2023, with all current technical and economic hydro capacity used, and 20 GW of wind and 600 MW of geothermal plants put in operation. Individual renewable electricity technologies are described briefly below.

A.1.2.1. Hydroelectric power

The total economical hydro potential of Turkey is about 37,10025 MW in terms of installed capacity and 130,000 GWh/year in terms of generation. According to DSI, use of small hydro (1 to 10 MW) could increase the economical potential of Turkey to some 163 TWh/year. Hydro resources are spread all over the country, but concentrated in the east. The map below shows the location of Turkey’s river basins and hydro-potential:

25 Estimated based on 40 percent load factor.



Figure A.5 Hydro Power Potential of Turkey

9,673 MW5,030 MW

3,179 MW3,439 MW

2,059 MW

2,048 MW

1,632 MW

1,632 MW1,346 MW

1,271 MW1,178 MW

Hydro potential by river basin>1,000 MW

Note: Firat/Euphrates figure covers upper, middle and lower river Source: EIE

Turkey uses about one-third of its economical hydro potential. As of end 2009, the total installed capacity of HEPPs was 14.5 GW. These plants generated nearly 36 TWh of electricity during that year. As of end-2009, hydro capacity constituted 32 percent of total capacity and generation from hydro resources accounted 19 percent of total generation.

Investors interested in developing HEPPs have to obtain “water usage rights” from DSI. (State Water Works). In case applications are done for the same source, DSI organises a competition and the investor who pays the highest hydropower resource contribution per kilowatt hour of electricity generated is awarded. Investors were eager to pay the contribution, though it increases the cost of investments. As of December 2009, DSI organized a competition for 449 projects; offers were generally in the range of 0.1 TL/MWh to 100 TL/MWh.26

A.1.2.2. Wind power

According to Turkey’s new wind atlas, REPA, which was presented in January, Turkey’s wind potential is estimated to be around 48-50 GW. This potential is estimated considering areas which have a wind speed of more than 7 m/sec and which have a height of less than 1,500 meter and a slope of less than 20 percent. Besides security bands are allowed near areas like wetlands, highways, railways, etc. This potential is stated to be neither technical nor economic potential but something between these two.27

26 Offers were typically expressed in terms of Kr/kWh, where 100 Kr (Kurus) = 1 TL. 27 According to the old Wind Atlas of Turkey, Turkey’s total technical wind potential was estimated to be 88 GW, while

its “economic” wind potential was around 10 GW



Figure A.6 Wind Atlas of Turkey, m/s at 30 metres

Source: EIE

As of end-2009, Turkey’s installed wind capacity was 803 MW, which generated 1.5 TWh electricity in 2009, less than 1 percent of generation. However, both local and foreign investors’ interest in wind is increasing rapidly, encouraged by government support (see section 3.1.3.3, below). Some of this interest is likely to be speculative.

The Energy Market Regulatory Authority (“EMRA”) accepts wind license applications only at dates that it specifies. The last application date was November 2007, when applications for as much as 78 GW of power were received. Evaluation of these applications has proved difficult because of the very large number of projects, but appears to be nearing completion. Many of these projects are applying for licenses to build in the same areas, and in many cases transformer and transmission system capacity is limited – with provision of grid infrastructure uncertain. (As the figure suggests, much of the potential is in the north-west. Other significant potential exists on the east Mediterranean coast). Several changes have been made in the regulations to date to be able to evaluate the applications. As of September 2010, evaluations have not been completed yet. Many applications were made for the same location and many were not able to meet the technical criteria, so only a small fraction of the applications are likely to be approved and taken forward.

A.1.2.3. Geothermal

Turkey’s geothermal potential is seventh in the world and first in Europe. Total geothermal potential of Turkey is estimated to be 31.5 GWth (billion watts thermal energy) and, with this potential, it would in theory be possible to meet 30 percent of the heat energy demand of Turkey. It also has 600 MWe proven geothermal fields capable of producing electricity, and this number is likely to rise as more exploratory drilling is undertaken. The potential is also expected to increase as geothermal technology improves.28 As of end-2009, installed geothermal capacity was just 77 MW.

28 For example, until recently temperatures above 140º C were necessary to produce energy, but temperatures as low as

90ºC may now be viable under certain conditions.



A.1.2.4. Solar power

Turkey has 61 Mtoe solar energy production potential: 21 Mtoe for power and 40 Mtoe for heating. Today, solar energy is mainly used in water heating systems in Turkey. Turkey is the leading country in Europe – and second in the world – in solar collector installations, with 12 million square meters installed. In 2008, solar energy consumption was 0.4 Mtoe. However, up to now there has been no government encouragement of other uses. There is no grid-connected solar power generator and no application to date to EMRA for a solar power generation license. The installed photovoltaic capacity is just 1 MW, primarily in specialised and off-grid locations such as forest fire watchtowers, highways, communication towers, and meteorological stations.

A.1.2.5. Biomass

Biomass constitutes 5 percent of total primary energy consumption in Turkey. Most of this is for traditional heating uses, rather than for power generation: 3 percent of primary energy consumption is wood and 1 percent animal and vegetable waste. The installed capacity of modern biogas facilities for electricity generation is just 81 MW as of end-2009. Existing biogas capacities in Istanbul and Adana are very small considering the size of the cities. Other than municipal waste, animal waste is considered as an important biomass resource. Government research institute the EIE determined the biogas potential of Turkey based on animal wastes to be 3 billion m3/year, or the equivalent of around 3 Mt hard coal per year.

A.1.3. Regulatory Framework

A.1.3.1. Electricity market structure

Turkey is in the process of changing its electricity market structures from a traditional state-led model to the model pursued with varying degrees of success by European Union Member States today, with disaggregated market structure and competitive principles. As of the end of 2009, 54 percent of the installed capacity in Turkey was still owned by the state – the bulk of this state-owned capacity is lignite and hydro, with some natural gas. Capacity owned by private investors who are subject to free market conditions constituted only 25 percent of the total (of which 17 percent are independent power producers and 8 percent are autoproducers). The remaining capacity – roughly 20 percent – is largely made up of natural gas plants built in the 1990s with take-or-pay agreements, i.e. plants under “BO”, “BOT” and “TOR” models (see Glossary). Figure A.7 illustrates the capacity shares by different fuel / technology and by ownership / contracting regime.



Figure A.7 Installed Capacity By Ownership, end-2009

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State TOR MP BO BOT IPP AP

Coal Lignite NG Hydro Others*

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ty (G

W)

Note: Others includes Fuel Oil, Diesel Oil, Asphaltite, Naphta, Waste, Multifuels, Geothermal, Wind AP=Autoproducer, MP=Mobile Plants.

Source: TEIAS

A.1.3.2. Electricity Market Law

In March 2001, the Grand National Assembly enacted Law 4628 designed to introduce a fully competitive electricity market. The Law aims at the development of a liberalized electricity market on the lines of the markets introduced in Europe and in broad accordance with EU Directives. The processes launched with Law 4628 included:

■ Creation of an independent regulatory body, the Energy Market Regulatory Authority (EMRA).

■ Unbundling of TEAS into generation (EUAS), transmission (TEIAS) and trading (TETAS) bodies with the generation and trading bodies to be privatized.

■ Introduction of private players and of licensing.

■ Constitution of a liberalised wholesale electricity market based on bilateral contracts and exchanges

■ Creation of an electricity balancing mechanism

■ Introduction of the concept of eligible customers who will be free to choose their suppliers29

29 According to Law 4628, EMRA sets the eligible consumer limit each year. As of February 2010,

eligible limit is decreased to 100,000 kWh.



A.1.3.3. Strategy Papers

The changes envisaged by Law 4628 have been difficult to put into practice. These difficulties have led to the issuing of two Strategy Papers – the Strategy Paper of 2004 and that of 2009.

The Strategy Paper of 2004 mainly set out an action plan and timetable for privatisations and introduced a transition period so as to ease the shift to fully liberalised market. The timetable foreseen in the 2004 Strategy Paper has slipped, but the basic approach remains in place.

With implementation lagging, an update became necessary, and in May 2009, the Electricity Energy Market and Supply Security Strategy Paper was released. This aims to improve market structures, targets a considerable privatisation programme, focuses on security of supply and prioritises use of local resources. The government’s 2023 targets for fuel diversity have significant implications for power sector emissions:

■ Renewables are to account for 30 percent of generation (continuation of level in 2005/2006)

■ Hydro: All current technical & economic capacity to be used

■ Wind: 20 GW.

■ Natural gas: <30 percent of generation (down from 49 percent in 2009)

■ Nuclear: at least 5 percent of generation.

■ Proven lignite deposits and hard coal resources will be brought into use.

A.1.3.4. Environmental regulations

Turkey’s power sector is subject to environmental restrictions for new and existing power plants that are likely to affect their costs, particularly if the country continues to align itself with European institutions and regulations. Requirements to fit flue-gas desulphurisation equipment or controls to reduce nitrogen oxide emissions and particulates will increase costs for the sector.

A.1.3.5. Renewable Energy Law

Turkey’s current Renewable Energy Law (Law 5346) was introduced on May 18, 2005 and amended by Law 5627 on May 2, 2007. The Law covers renewable30 power generation projects, but excludes heating. Major points of the Law include:

■ Generators using renewable energy resources are required to obtain a “Renewable Energy Resource Certificate” (RES Certificate). This certificate is not equivalent to a Green Certificate but is a guarantee of origin.

■ For projects put in operation by end-2011:

30 Defined as hydro (excluding dams with reservoirs over 15 sq km), wind, solar, geothermal, biomass, biogas, wave,

current and tidal energy resources



■ Holders of retail sale licenses are obliged to buy electricity from RES Certificate holders who have not completed ten years of operation. Each retail company should purchase the same share of RES certified electricity as the ratio of the electricity they sold in the previous year to total electricity sold in the country.

■ The Law introduces a single feed-in tariff for all types of renewable energy. The levels of this feed-in tariff have since been revised.

■ Generators are allowed to sell their electricity at a higher price without obtaining a RES certificate if they could find any opportunity in the free market. i.e. Currently they prefer to sell their electricity in the B&SM.

■ Investors are allowed to use state owned land provided that they pay for the cost. 85 percent reduction applied on the sale price, rent, rights of access and usage permissions for the first 10 years of operation.

A.1.4. Demand Projections

■ Turkey’s electricity consumption has been growing at 6-7% over the last decade, and this growth is expected to continue, as Turkey is still well below the current EU average per capita consumption.

■ Turkey’s total consumption per capita will increase from current 2.2 MWh/capita to 3.8 MWh in 2020 and 5.6 MWh in 2030. This level of growth would bring Turkey in line with the current EU average of 5.7 MWh / capita by 2030.

■ Demand for electricity over the period increases from 180 TWh in 2010 to 310 TWh in 2020 and 490 in 2030.



Figure A.8 Electricity consumption per capita (EU and Turkey)

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Source: EEA, citing Eurostat and IEA

A.1.5. Resource Constraints

We make the following assumptions about the availability of key resources in the power sector.

Table A.1 Power Sector Resource Constraints

Quantity Value Notes Hydro resource 30 GW Accounts for environmental

constraints Split into two tiers of different attractiveness

Imported Georgian hydropower 1.7 GW Corresponds to plans currently being considered for increased generation and interconnector capacity

Wind resource 50 GW Split into three tiers with different attractiveness

Lignite resource 18 GW Based on assessment of locally available resource

Source: various sources as discussed in preceding sections



A.1.6. Power Sector Technologies

Table A.2 Power Sector Technologies

tCO2/MWh % % New build Upgrade Comments

Existing coal plant 0.99 36% 2,600 Not built anymore.

New supercritical coal plant 0.80 44% 2,800 Cost of new plant.

Existing coal plant, running on 10% biomass 0.80 40% 260

New supercritical coal plant running on 10% biomass 0.72 43% 260

Existing CCGT plant 0.41 44% 1,000 Not built anymore.

New CCGT plant 0.35 59% 1,100 Cost of new plant.

Existing lignite plant 1.07 33% 2,800 Not built anymore.

New supercritical lignite plant 0.83 42% 3,100 Cost of new plant.

Existing lignite plant, running on 10% biomass 0.86 37% 260

New lignite plant running on 10% biomass 0.75 42% 260

Oil-fired power station 0.58 30% 1,600 Cost of new plant.

Biomass-fired power plant - 38% 40% 2,500 Cost of new plant.

Biofuel-fired power plant - 29% 40% 2,500 Cost of new plant.

Nuclear (Fission) - N/A 75% 3,900 Cost of new plant.

Solar Photovoltaic - N/A 19% 3,600 Cost of new plant.

Solar thermal - N/A 30% 3,900 Cost of new plant.

Geothermal - N/A 67% 3,700 Cost of new plant.

Wind Onshore - N/A 24-32% 1,400 Cost of new plant.

Wind Offshore - N/A 36% 2,900 Cost of new plant.

Hydro - N/A 30-34% 1,900 Cost of new plant.

Energy From Waste - N/A 42% 3,800 Cost of new plant.

Cost of retrofitting the plant to allow for cofiring.

CAPEX (in 2010)€/kW

Cost of retrofitting the plant to allow for cofiring.

Description

Carbon intensity Efficiency

Availability factor



A.2. Household and Building

A.2.1. Building Stock

There are difficulties in measuring the building stock of Turkey and uncertainties on the number of buildings. The major source of information on the building stock is TUIK’s Building Census of 2000, which is now quite dated.31 Information on subsequent building construction permits and occupation permits is published quarterly by TUIK. We estimate that Turkey had 8.4 million residential, commercial and public buildings as of end 2009. 32 (This number counts large apartment blocks as a single “building”, so the number of individual dwellings is much higher.) The chart below shows the development of the number of buildings (excluding industrial buildings), together with their area.

Figure A.9 Building Stock in Turkey

7

7.2

7.4

7.6

7.8

8

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Num

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f bui

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gs (m

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n)

02004006008001,0001,2001,4001,6001,800

Are

a (m

illio

n m

2)

Number of buildings Floor area Note : Excluding industrial buildings; data are based on construction permits, not occupancy permits. Source: TUIK

According to data from TUIK, around 15-20 percent of dwellings are in large multi-unit residences heated via shared heating systems. Another 30 percent of dwellings are heated via individually-sized heating systems. Stoves for individual rooms are used around 40 percent of dwellings (typically much smaller single homes).

A.2.2. Energy Consumption

Energy consumption in buildings (including households and the commercial and public sectors) constituted 36 percent of total final energy consumption of the country in 2008. This figure increased during the economic crisis, i.e. 2001 and 2008, reflecting the demand decline in the industrial sector. 31 This was not a periodic study and the Institute does not have any plans to conduct a new census. 32 We arrive at this total by adding the number of construction permits from 2000-2009 to the 2000 Building Census

figures. We use construction permits rather than occupation permits, as this data covers a larger base of buildings. It is not uncommon for building occupants to avoid applying for an occupation permit in order not to be subject to certain taxes.



Figure A.10 Energy Consumption in Buildings and Households

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1994 1995 19961997 19981999 2000 20012002 20032004 2005 20062007 2008

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Energy Consumption Share in Total Final Consumption Source: MENR – Energy Balances

Energy consumption of buildings increased from 16 Mtoe (186 TWh) in 1994 to 28 Mtoe (326 TWh) in 2008, growing at an average rate of 4 percent. The share of electricity in this total rose from around 14 percent to 24 percent in 2008 (7 Mtoe, or around 80 TWh).

Of building energy use, approximately three-quarters is for residential use, and the rest for non-residential. Taking only fuels used for heating, in the residential sector, natural gas accounts for around 30 percent of the total energy use, with coal and lignite combined accounting for another 30 percent, biomass and wood fuels accounting for just under 25 percent, and oil and other renewables (including geothermal and solar thermal) accounting for most of the remainder.



Figure A.11 Fuel Mix for Residential Heating (2008)

Natural gasWood and biomassCoalLigniteOilOther renewablesElectricity for heatingOther solid fuel

Source: NERA estimates based on data from Ministry of Energy and Natural Resources

Use of low quality lignite for fuel in the residential sector is supported by Government policy to provide the fuel free of charge to poor households. In 2009 the government distributed 2 million tonnes of the fuel to 2.2 million poor households (i.e. 10 percent of all households), in both urban and rural areas. The table below shows the number of households and amount of lignite distributed from 2003-2009.

Table A.3 Distribution of Free Lignite to Families (2003-2009)

Year Volume of Brown Coal

(Tonnes)

Number of Families

2003 649,818 1,096,4882004 1,052,379 1,610,1702005 1,329,676 1,831,2342006 1,363,288 1,797,0832007 1,494,163 1,894,5552008 1,827,131 2,246,2802009* 1,977,907 2,234,720

* 2009 December figure

Source: Social Assistance and Solidarity Fund



In recent years, the share of natural gas33, as more cities have been connected to the natural gas network and receive natural gas. Natural gas consumption in the cities has been encouraged by the government and local authorities to reduce air pollution.

Figure A.12 Energy Consumption by Fuel Type in Buildings

0

5

10

15

20

25

30

1994 2008

Ener

gy c

onsu

mpt

ion

(Mto

e)

Hard Coal Lignite Oil Products Natural Gas Electricity Wood Others

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1994 2008

Ener

gy c

onsu

mpt

ion

(sha

res)

Source: MENR – Energy Balances

Electricity is used primarily for non-heating purposes, i.e. electrical equipment and lighting. Coal and lignite are preferred as heating fuels because they are inexpensive Wood is used mainly in rural areas. The share of oil-fired heating has declined as more cities have been connected to the gas grid.

■ Use of solar thermal technology for hot water heating is relatively common, although estimates of market penetration for hot water heating are around 15%.34

■ Use of air conditioning – estimated by a major foreign manufacturer at just 10 percent of residential properties – is likely to increase with GDP. (Japan Times, 2010)

■ District heating is almost non-existent, but in around 15-20 percent of dwellings35, heat is provided through shared heating facilities. This number is likely to increase as flats become a larger share of the total housing stock.

■ Most households (around 70 percent) own their own homes.

33 The data may not accurately distinguish between lignite and hard coal, particularly in earlier years – that is, use of hard

coal may have been higher in the past than is suggested by the data in the chart. 34 Based on discussion with manufacturers and other experts; see also http://www.alternaturk.org/turkiye-gunes-

enerji.php; 35 Based on data from TUIK.



A.2.3. International comparisons

■ Turkey’s relatively warm climate requires less energy for heating than the European average

- Turkey’s average heating degree days are similar to Italy and Croatia, but there is wide regional variation

■ Average consumption of energy for heating based on total floor area and total energy consumption is around 100 kWh/m2

Figure A.13 Building Heat Demand Intensity in Turkey and Other European Countries

Turkey

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0 1000 2000 3000 4000 5000 6000

Climate (in heating degree days)

Ener

gy C

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mpt

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for

Hea

ting

(kW

h/m

2)

ItalyCroatia

Source: Heating-degree days from WRI (2005) energy consumption Eurostat and MENR.

The table above shows the specific heat consumption in Turkey compared to others – the dotted line shows the European average, controlling for climate. Although the data appear to suggest that Turkey’s buildings are insulated to a standard similar to the rest of Europe, this may not be the case. Various sources36 suggest that buildings in Turkey are built to a relatively low energy efficiency standard – in some cases suggesting consumption as high as 250 kWh/m2 annually. The data shown above therefore may reflect a number of other factors:

■ first, some fuel use may not be reported, particularly where traditional wood fuel is being used;

■ second only a fraction of total residential floor area may be heated, so the estimates above, based on total residential floor area, may not be directly comparable if the countries are heating their homes differently;

36 Cakmanus (2007): 150 kWh/m2; others to be added.



■ third, the average internal temperatures in different countries may not be the same – that is, using the same amount of fuel in a less well-insulated house may lead to colder internal temperatures, which would increase with income or with higher levels of insulation.

All of the above suggest that as Turkey’s per capita income rises, fuel use and associated emissions per m2 for heating could increase significantly relative to current levels. This provides further motivation for improving building insulation levels.

A.2.4. Regulatory Framework

Turkey has enacted a wide range of laws and regulations related to energy efficiency of buildings and building energy use, in part to align its regulatory framework with that of the European Union. Nevertheless, many existing laws are not well-enforced – this applies not only to energy-efficiency regulations, but to building regulations more generally. A large number of buildings in Turkey are developed without necessary licensing and permitting.

■ Several laws and supporting regulations have been published under energy efficiency programmes. The laws and regulations which target to decrease energy consumption in the buildings include:

■ The main law on energy efficiency - Energy Efficiency Law (No: 5627) published by the MENR in August 2007.

■ Regulations regarding efficient use of heating energy in buildings. These are published by the Ministry of Public Works and Settlement

■ Regulation on Energy Performance of Buildings published in December 2008

■ Regulation on Heat Insulation in Buildings published in October 2008

■ Regulation on Distribution of Heating and Hot Water Costs in Centrally Heated Buildings published in April 2008

■ Regulations on efficiency of household appliances. These are published by the Ministry of Industry and Commerce.

■ Law Related to the Preparation and Implementation of Technical Legislation of Products (Law No. 4703) published in June 2001

■ Regulation on Efficiency requirements of New Hot Water Boilers published in June 2008

■ Regulation Amending the Regulation on Labelling of Domestic Air Conditioners published in June-08

■ Regulation on Labelling of Domestic Air Conditioners published in December 2006

■ Regulation on Energy Efficiency of Electrical Refrigerators, Freezers and Their Combinations published in December 2006

■ Regulation on Energy Efficiency of Fluorescent Lamps published in December 2006



Some significant provisions in the above laws include:

■ Requirements that a Heat Insulation Report is prepared for each building to be submitted together with the construction permit application. The report must include heat losses, heat gains and heat requirements. The heat requirement of a building should not be more than the standard to be calculated according to the formula in TSE 825.

■ The above standards distinguish between four climatic zones in Turkey; they suggest heating requirements for buildings that are already quite low:

Specific Heat Consumption (kWh/m2)

Climatic Zone 1 33.2 Climatic Zone 2 60.6 Climatic Zone 3 75.8 Climatic Zone 4 93.5

- Source: Onan and Erdem, Yildiz Technical University

■ Shared, centrally heated systems are obligatory for new buildings with useful area greater than 2,000 m2. Dwellings with area greater than 250 m2 that use gas heating systems must use condensing boilers or equipments with integrated economizers.

■ Non-residential buildings with more than 250 kW cooling requirement shall have central cooling systems.

■ Buildings with more than 2,000 m2 area which have central heating, cooling, lighting systems shall have automated control systems.

■ Metering of heat (e.g. using heat “allocators”) for each dwelling in centrally heated buildings became compulsory in new buildings from May 2007. Buildings which do not have the system may not receive a construction permit. However, discussions with experts suggest that currently only around 50,000 residential units have heat measurement and control systems – far fewer than the number of homes built since 2007. Existing buildings are required to install these systems by March 2012.

Although implementation of the above regulations and a host of others has begun, it is likely to take time (and commitment) for them to be fully implemented.

A.2.5. Projections

■ Population growth from currently level of 73 million to 87 million in 2030 (TUIK forecast; implies growth rate of 1.1 percent in 2010, falling to 0.7% in 2030)

■ As per capita income increases the number of dwellings per capita is also expected to increase.

■ The total number of dwellings increases by just under 50 percent between 2010 and 2030, from 22.0 million to 32.5 million (and by 22 percent between 2010 and 2020).

■ The majority of the increase in dwellings occurs in apartments (in 2009, TUIK data suggest that apartments accounted for two-thirds of new construction). Figure A.14 shows how the number of dwellings changes over time.



■ In the commercial sector, the total commercial floor area increases by 58 percent between 2010 and 2030, from 546 million m2 to 861 million m2.

Figure A.14 Number of Dwellings – Houses and Apartments

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25

30

35

2010 2015 2020 2025 2030

Num

ber o

f dwellings, m

illions House

Apartment

A.2.6. Abatement Measures in the Buildings Sector

As discussed elsewhere, our approach is to represent buildings as combinations of different technologies and characteristics that have particular energy and emissions attributes. Households and other building users choose from a range of different building types, and upgrade buildings when this is financially attractive (or required by law, etc.). The table below summarises the technologies and “measures” that affect building emissions intensity, and provide some additional information about the nature of these measures.



Table A.4 Overview of Buildings Abatement Measures: Space Heating

Energy / carbon savings Cost (€)

(relative to no insulation) (per dwelling)Roof Insulation 5 - 15 percent 280Wall insulation 15 - 25 percent 1,700Floor boards 5 - 15 percent 340Double Glazing 10 - 20 percent 1,300Triple Glazing 15 - 25 percent 1,500

(relative to coal) (per system)Coal N/A 220Gas 60 percent 720Oil 40 percent 410Electricity varies 200

(per system)Condensing boilers 25 percent 830

(per dwelling)Heat meters / controls 25- 30 percent 54

Category

Insulation

Fuel switching

Control Equipment

More efficient boiler

Table A.5 Overview of Buildings Abatement Measures:

Water Heating, Lighting and Appliances

Energy savings Cost (€)

Water heating (relative to oil boilers)Incremental cost (per dwelling)

Gas boiler 25 percent 0Condensing gas boiler 45 percent 150LPG boiler 20 percent 230Electric system 65 percent -39Oil boiler N/A N/ASolar heater 90 percent 440

(relative to incandescent) (per unit) Fluorescent energy saver light bulbs 91 percent 5

Fluorescent light bulbs 89 percent 4 Halogen light bulbs 70 percent 4

Incandescent light bulbs N/A 1 LED light bulbs 93 percent 7

(relative to standard model)Relative to cost of standard

model Standard model N/AEnergy efficient model 20 percent 110

(relative to standard model)System cost

(per m2)Standard N/A 8.2Energy efficient 10-30 percent 8.9 - 9.8

Lighting

Refrigerators

Air conditioning

Category



A.3. Industry

A.3.1. Cement

Turkey has the largest cement capacity in Western Europe. As of end-2009, total clinker capacity in the country was 62.5 Mtons/year and cement grinding capacity 103.5 Mtons/year.

There are 64 cement plants in the country. Three quarters of these are integrated plants producing both clinker and cement and the remainder are stand-alone cement grinding plants. The map below shows the geographic distribution of the industry.

Figure A.15 Cement Plants in Turkey

Source: Turkish Cement Manufacturers Association (TCMA)

In 2009, Turkey produced 46.2 Mtons of clinker and 53.9 Mtons of cement. Cement production increased from 33 Mtons in 2002 to 54 M tons in 2009 (a 7.3 percent annual growth rate). The largest increase was in South East Anatolia, mainly due to exports to the Middle East, particularly Iraq. The Turkish Cement Manufacturers Association (TCMA) forecasts a 60 percent increase in cement production, reaching around 90 Mtons in 2020.



Figure A.16 Cement Production in Turkey (Mt)

0

10

20

30

40

50

60

2002 2003 2004 2005 2006 2007 2008 2009

Cem

ent p

rodu

ctio

n (M

tons

)

Aegean Black Sea Central Anatolia East AnatoliaMarmara Mediterranean South East Anatolia

CAGR 2002-9

12.5%

3.6%

7.6%

6.5%

8.9%

7.2%

7.3%

Source: Turkish Cement Manufacturers Association (TCMA)

A.3.1.1. Projection

■ Current cement output of around 50 Mt is ~700 kg / capita; consumption is 550 kg/capita

■ Consumption is consistent with other less developed EU member states, but below China

■ Sector is already relatively efficient, with energy intensity below EU average

■ Assume growth continues faster than population growth (at 2%) to 2020, then levels off

Figure A.17 Cement Output and GDP per Capita (EU and Turkey)

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

0 10,000 20,000 30,000 40,000 50,000GDP pe r Ca pi t a ( Eur os/ c a pi t a )

Turkey

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0 10,000 20,000 30,000 40,000 50,000GDP pe r Ca pi t a ( Eur os/ c a pi t a )

Turkey



A.3.1.2. Abatement measures

Table A.6 Abatement Measures for Cement Sector

Measure Description Energy / Emissions Impact

Efficient new capacity Modern kilns using dry production processes

15 percent reduction in energy intensity (compared to average existing capacity). Emissions reduction of 6 percent compared to current average.

EE package 1 Preventative maintenance Improved kiln combustion Shell heat loss reduction

10 percent reduction in energy intensity. Emissions impact depends on fuel use and clinker ratio, but is 4.5 percent for a typical, unimproved coal-fired plant.

EE package 2 EE package 1 + Improved process control and automation New grate cooler Indirect firing

18 percent reduction in energy intensity. Impact on emissions depends on fuel characteristics. Emissions impact depends on fuel use and clinker ratio, but is 8 percent for a typical, unimproved coal-fired plant.

Fossil fuel substitution Switch from default fuel (coal) to other fuels with lower emissions intensity (subject to technical suitability)

Emissions reduction depends on relative carbon intensity of fuels used. E.g., switch coal to gas leads to 18 percent reduction.

Waste firing Substitute fossil fuel input with waste

Up to 40 percent reduction in emissions intensity

Clinker substitution Substitute up to 20 percent of clinker with alternative materials in cement blending.

Reduction in energy use as well as process emissions, with up to 23 percent reduction in overall emissions intensity

Carbon capture and storage Capture up to 90 percent of CO2 emissions.

90 percent reduction in total CO2 emissions.

A.3.2. Iron and Steel

Turkey is a major iron and steel manufacturer. It ranks 3rd in Europe and 11th in the world in crude steel production. As of end-2008, Turkey had a crude steel capacity of 34.1 million tons and produced 26.8 million tons of crude steel during this year. In 2009, production decreased to 25.3 million tons.



There are three integrated iron and steel plants (ISPs) - Eregli Iron and Steel Works Co. (Erdemir), Iskenderun Iron and Steel Works Co. (Isdemir) and Karabük Iron and Steel Works Co. (Kardemir), and 19 electric arc furnaces (EAFs) in Turkey. EAFs constitute 77 percent of capacity and 74 percent of production.

The map below shows the geographical distribution of the industry. The Erdemir and Kardemir integrated plants are located in the north-west due to their proximity to hard coal mines. Isdemir (the second largest integrated plant) is located in the mid-south and generally supplies demand in the south and east of the country. Most EAF production is located in the Marmara and Izmir province, where economic activity is developed, particularly in coastal areas to ease slab and export logistics.

Figure A.18 Iron and Steel Plants in Turkey

Source: Turkish Iron and Steel Producers (TISPA)

Crude steel production in Turkey grew at an average annual rate of around 8 percent from 2000-2008, from 14.3 million tons to 26.8 million tons. Table 3.3 below shows crude steel production by year. EAF production has expanded dramatically over the last decade, and as noted above, now accounts for nearly three quarters of production.

Table A.7 Crude Steel Production in Turkey

Mtons 2000 2005 2006 2007 2008 2009Electric Arc Furnace 9.1 14.8 17.3 19.4 19.8 17.7Integrated Steel Plant 5.2 6.1 6.2 6.4 7.0 7.6Erdemir 2.4 3.1 3.1 3.1 3.1 3.7Isdemir 2.0 2.1 2.0 2.2 2.9 2.8Kardemir 0.9 1.0 1.0 1.0 1.1 1.1Total 14.3 21.0 23.4 25.8 26.8 25.3

Source: TISPA



A.3.2.1. Projection

Steel industry continues to expand at a rate (1-2%) faster than population growth, although dominance of electric arc furnaces may be sensitive to electricity prices

Sector is relatively efficient due to prevalence of electric arc furnaces

No specific policies to encourage efficiency improvements

Figure A.19 Steel Output and GDP per Capita (EU and Turkey)

Turkey

0

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500

- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000GDP per Capita (Euros/capita)

Tota

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TurkeyTurkey

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- 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000GDP per Capita (Euros/capita)

Tota

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per C

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(kg

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ita)

Turkey

A.3.3. Industry Growth Assumptions

The industry growth assumptions are presented below in Table A.8. In general, industry is expected to grow at a lower rate than GDP, as the country reduces its reliance on Industrial production, and increases the share of contribution to GDP from services.

Table A.8

Industry Growth Projections

Sector Growth rates, y/y

2010-2020 2020-2030

Cement 2.0% 1.0%

Steel 1.8% 1.0%

Refining 4.4% 3.5%

Other Industry 2.6% 2.7%

Source:IBS and NERA analysis



A.3.4. Detailed technology cost and performance assumptions

The tables below provide a summary of the efficiency or carbon improvement and associated capital cost (per unit of annual production capacity) for the major industrial abatement technologies included in our analysis, organised by sector.

Table A.9 Abatement Measures – Cement

Sector Measure Carbon savings Cost (€/t cement)

Cement Preventative Maintenance 1-5% 4.6

Cement Shell heat loss reduction 5-10% 0.17

Cement Improved kiln combustion 5-10% 0.52

Cement Process control and automation 1-5% 0.12

Cement New grate cooler 5-10% 4.0

Cement Indirect firing 5-10% 5.6

CementWaste firing Fuel is 40% less carbon

intensive with 80% regular waste and 20% biowaste

3.8

Cement Medium clinker substitution 10% relative to portland cement

3.2

Cement High clinker substitution 20% relative to portland cement

4.9

Table A.10 Abatement Measures – Steel

Sector Measure Carbon savings Cost (€/t steel)

Steel Energy monitoring & management system 1-5% 0.05

Steel Preventative maintenance 1-5% 0.00

Steel Sinter plant heat recovery 1-5% 0.34

Steel Coal moisture control 1-5% 7.5

Steel Blast furnace pulverised coal injection 1-5% 3.2

Steel Hot blast stove automation 1-5% 0.14

Steel Heat recovery - basic oxygen furnace 1-5% 11.2



Table A.11 Abatement Measures – Oil Refining and Petrochemicals

Sector Measure Carbon savings Cost (€/t output)

Oil refineries Energy management 1-5% 0.23

Oil refineries Fouling Mitigation 1-5% 0.35

Oil refineries Pumps, motors and compressed air 5-10% 0.08

Oil refineries Improved process controls 1-5% 0.43

Oil refineries Waste heat recovery 1-5% 0.57

Oil refineries Process Integration and change 1-5% 0.15

Petrochemicals Energy management 1-5% 0.12

Petrochemicals Improved distillation 1-5% 0.11

Petrochemicals Improved drying 1-5% 0.29

Petrochemicals Improved evaporation 1-5% 0.33

Petrochemicals MVR 1-5% 35.3

Petrochemicals Process control 1-5% 0.29

Petrochemicals Process integration 1-5% 0.13

Petrochemicals Waste heat recovery 1-5% 2.9



Table A.12 Abatement Measures – Selected Chemicals


Ammonia Energy management 5-10% 2.6

Ammonia Reforming large improvements 1-5% 28

Ammonia Reforming moderate improvements 1-5% 5.7

Ammonia Improvement in CO2 removal 1-5% 17

Ammonia Low pressure synthesis 1-5% 6.9

Ammonia Hydrogen recovery 1-5% 2.3

Ammonia Process integration 1-5% 3.4

NitricAcid Alternative oxidation catalyst more than 20% 32

NitricAcid Extension of the reactor chamber more than 20% 429

NitricAcid Secondary catalyst - N2O decomposition in the oxidation reactor 10-20% 1.3

NitricAcid Tertiary catalyst - Variant 2 1-5% 91

NitricAcid Non-selective catalytic reduction of NOX and N2O (NSCR) 1-5% 64

SodaAsh Control systems 1-5% 1.8

SodaAsh Energy management 1-5% 1.9

SodaAsh HEMs 1-5% 1.8

SodaAsh High efficiency trays 1-5% 15

SodaAsh Improved control 1-5% 2.8

SodaAsh Waste heat recovery 1-5% 27

SodaAsh Membrane process improvement 1-5% 3.9

SodaAsh Electricity efficiency - other inorganics 1-5% 3.9

SodaAsh Adjustable speed drives 1-5% 2.8



Table A.13 Abatement Measures – Minerals, Glass, Bricks, Ceramics


Lime Preventative Maintenance 1-5% 0.14

Lime Process Control 1-5% 0.64

Lime Improved kiln combustion 5-10% 0.45

Lime Shell heat loss reduction 1-5% 0.14

Glass Advanced burner systems 1-5% 3.2

Glass Control 1-5% 2.2

Glass Expert system 1-5% 2.2

Glass External cullet 1-5% 2.7

Glass Waste heat recovery 1-5% 7.0

Glass Oxy trim 1-5% 1.7

Glass Refractories and insulation 1-5% 3.2

Glass U/S Refining 1-5% 4.2

Bricks Improved firing and drying 55% 32

General ceramics Improved firing and drying 25% to 40% 210

Table A.14 Abatement Measures – Selected Other Industry


Aluminium Enhanced furnace 5-10% 8.5

Copper Monitoring and targeting 5-10% 3.1

Copper Modern furnaces more than 20% 7.7

Paper (excl. pulp) Waste heat recovery in the pulp industry 1% 81.3

Paper (excl. pulp) Process control and pinch analysis in the pulp industry 5% 38.8

Pulp Process control and pinch analysis in the pulp industry 5% 26.1

Pulp Waste heat recovery in the pulp industry 1% 2.2

A.3.5. International Benchmarking of Industry

As shown in the main body of the report, there is considerable scope for energy efficiency improvements in Turkish industry. In this section we present the average fossil fuel energy consumption of individual industries relative to international benchmarks, with an aim to



indicate whether Turkey is closer to the most inefficient plants (“Laggards”), to the most efficient ones (“Leaders”), or somewhere in between (“Standard”).

In general, industrial plants in Turkey have fossil fuel energy consumption close to “standard” plants that currently operating in Europe and other developed countries, although this varies from sector to sector based on the available information.

Progressing towards state-of-art plants (“leaders”), either by upgrading current capacity or by building new, more efficient capacity, would allow Turkey to reduce industrial energy consumption and emissions further.

Figure A.20 Industry Energy Intensity - International Benchmarks

0

2

4

6

8

10

12

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16

Alu

min

ium

Am

mon

ia

Bric

ks

Cem

ent

Cop

per

Cer

amic

s

Gla

ss

Lim

e

Nitr

ic A

cid

Pet

roch

emic

als

Pap

er

Pul

p

Ref

iner

ies

Sod

a A

sh

Ste

el

MW

h fu

el/t

capa

city

Leader Standard Laggard Turkey

Source: BNEF database, Turkey Ministry of energy and Natural Resources Energy Balances, UNFCCC, FAOStat, SPO, Tukder, YEM, Ceramic federation, SPO & Eti Aluminyum, SPO & Eti Copper, Turkish Chemical Manufacturers Association (TCMA), and NERA analysis.

A.4. Transportation

A.4.1. Overview

In 2008, total freight transportation was about 200 Gtkm (billion tonne-kilometres) and passenger transportation more than 200 Gpkm (billion passenger-kilometres). Road transportation dominates transportation in Turkey, accounting for 86 percent of freight and 97 percent of passenger transportation.



Figure A.21 Freight and Passenger Transportation

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25020

01

2002

2003

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2006

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2008Frei

ght t

rans

port

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nnes

km

)

Road Railway Maritime* Air Transport*

0

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Pass

enge

r tra

nspo

rtat

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(bn

pass

enge

r km

)

Road Railway Maritime* Air Transport*

Note: Maritime and air transport do not include international transportation. Air transportation data are not available for the last three years.

Source: TUIK

The number of road motor vehicles in the country increased by 76 percent between 2001 and 2009. During this period, the number of cars grew from 4.5 million to 7.1 million, trucks and small trucks from 1.2 million to 4.5 million and motorcycles from 1.0 million to 2.3 million.

Figure A.22 Road Motor Vehicle Stock in Turkey

0

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14,000

2001 2002 2003 2004 2005 2006 2007 2008 2009

Roa

d m

otor

veh

icle

s (th

ousa

nds)

Car Motorcycle Small truck Truck Minibus Bus Other

Source: TUIK

Energy consumption by the transportation sector constituted 20 percent total final energy consumption in 2008, or 16 Mtoe. Nearly all (98 percent) of the energy came from oil products.



Figure A.23 Energy Consumption of the Transportation Sector

02468

101214161820

2001 2002 2003 2004 2005 2006 2007 2008

Ene

rgy

cons

umpt

ion

(Mto

e)

0%

5%

10%

15%

20%

25%

Sha

re in

Tot

al F

inal

C

onsu

mpt

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%

Energy consumption Share in Total Final Consumption Source: MENR – Energy Balance

A.4.2. International Comparisons

Figure A.24 Transport sector - international benchmarks (vehicles)

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600

Turk

ey

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Rus

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Turk

ey

Kaz

akhs

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Ukr

aine

Rus

sia

Pol

and

UK

Veh

icle

s / k

m ro

ad

Source: World Bank

Vehicle penetration levels in Turkey are low by international standards, as illustrated in Figure A.24 above. At just above 100 vehicles per 1,000 people, the penetration rate is at the same level as Ukraine, but just 20-25 percent of that in Poland or the UK.



Figure A.25 Transport sector - International Comparison of Fuel Consumption per Capita

and of Fuel prices

0.00.20.40.60.81.01.21.41.61.82.0

Turk

ey

Kaza

khst

an

Ukr

aine

Rus

sia

Pola

nd UKPu

mp

pric

e ($

/litre

)

Diesel Gasoline

0.00.10.20.30.40.50.60.7

Turk

ey

Kaza

khst

an

Ukr

aine

Rus

sia

Pola

nd UK

Tran

spor

t fue

l con

sum

ptio

n (l/

capi

ta)

Diesel Gasoline

Source: World Bank. Data are for 2007 (fuel consumption) and 2006 (fuel prices).

Motor fuel prices in Turkey are high by international standards – significantly higher than fuel prices in other Eastern European countries such as Poland or Ukraine. While the diesel price in Turkey is comparable to that in the UK, the gasoline price is the highest among the benchmarked countries. Fuel consumption per capita is low by international standards – reflecting both the high price of fuel and lower GDP/capita.

A.4.3. Relevant policies

In June 2008, the Ministry of Transportation published the Regulations on Principles and Procedures to Increase Energy Efficiency in Transportation. The document includes strategies for reducing unit energy consumption of vehicles and improving energy efficiency standards, public transportation and traffic flow.

The motor vehicle tax in Turkey depends on the motor cylindrical volume, and on the age of the vehicle. For new cars the tax, in 2010, ranges from 405TL (less than 1300cc) to 14,689 (over 4,000cc). In this sense, the tax incentivises new buyers to purchase lower-volume, less fuel-consuming vehicles. On the other hand, the amount of tax payable for each vehicle decreases with age (for example, the tax for a vehicle with an engine of 1800-2000cc would cost 1,793 when new, but would decrease to 194TL when over 16 years old). This encourages people to hold on to their old (inefficient) cars rather than to buy new ones.37

A.4.3.1. Projections

Current motor vehicle penetration is very low by EU standards, due in part to per capita GDP, but also to relatively high fuel prices.

37 http://www.turkisheconomy.org.uk/buyingproperty/motor_vehicle_tax.htm



Figure A.26 Motor Vehicle Penetration in Turkey and Selected Countries

0 50100150200250300350400450500

Turkey

Kazakhstan

Ukraine

Russia

Poland

UK

Passenger cars /1,000 people

■ Growth in passenger vehicle km faster than GDP to 2020, at GDP by 2020

■ Motor fuel prices at international market levels with taxes making them higher than average.

■ Aviation demand to grow quickly



A.4.4. Detailed cost and performance assumptions

Table A.15 Abatement measures in Transport sector

Indicative energy or carbon savings

Fuel cost savings relative to a standard gasoline car in 2010

Costs per vehicle relative to a standard gasoline car in 2010

Costs per vehicle relative to a standard gasoline car in 2020

Gasoline car N/A N/A N/ADiesel car 19 percent -800 -800Electric car 78 percent 6,700 3,800LPG car 45 percent 1,000 1,000CNG car 25 percent 2,300 1,900Non-plug-in Hybrid 44 percent 6,200 5,500Plug-in Hybrid 67 percent 9,900 7,200

Modern vehicles

Costs per vehicle relative to a modern gasoline car in 2010

Costs per vehicle relative to a modern gasoline car in 2020

Next generation gasoline car 15 percent N/A N/ANext generation diesel car 31 percent -400 -400Next generation electric car 82 percent 9,800 6,700Next generation LPG car 53 percent 5,300 4,400Next generation CNG car 36 percent 2,300 1,900Next generation hybrid car (non-plug-in) 53 percent 10,400 7,200Next generation hybrid car (plug-in) 72 percent 15,500 11,400

Ultra-modern vehicles

Costs per vehicle relative to an ultra-modern gasoline car in 2010

Costs per vehicle relative to an ultra-modern gasoline car in 2020

Post-2020 gasoline car 28 percent N/A N/APost-2020 diesel car 41 percent - - Post-2020 electric car 86 percent 12,800 9,100Post-2020 hybrid car (non-plug-in) 60 percent 14,500 10,500Post-2020 hybrid car (plug-in) 76 percent 20,900 15,800

Indicative costs (2010 €)

Standard vehicles

Category

A.5. Waste

As noted above, in the 2008 GHG Emissions Inventory of Turkey, waste treatment ranks second after CO2 emissions from fuel combustion across all sectors. Waste accounts for 9 percent of the total GHG emissions of Turkey. This section explains the waste treatment activities in Turkey.

Solid waste: According to the most recent solid waste statistics, 3,129 municipalities out of 3,225 collect solid waste and they collected 24.4 million tons of waste in 2008. 45 percent of the waste was treated in landfills, 1 percent composted and the rest was mainly collected in municipality garbage dumps. Solid waste per capita in the same year was 1.15 kg.

There are 37 landfills, 4 compost facilities and 2 incineration facilities in Turkey.



Table A.16 Solid Waste Disposal Facilities in Turkey

Landfill Compost facility Incineration facility Number 37 4 2 Capacity, 000 tons/yr 390,048 551 44 Received waste, 000 tons 10,947 276 36 Treated waste, tons 10,037 143 29

Source: TUIK

Waste disposal is the responsibility of the municipal authority, and municipalities often face capital constraints that limit their ability to invest in equipment that will reduce costs in the longer term. Although Turkey aims to harmonise its waste regulations with the EU, there are limited requirements on waste disposal, and most municipal waste is disposed of at open dumps or in basic landfills that do not capture landfill gas. There is only limited experience in Turkey with landfill gas recovery, although there are some examples, including a large landfill in Ankara (the Mamak landfill) and recent projects in Istanbul (at Odayeri and Komurcuoda).

Waste water: According to TUIK statistics38., 8.7 billion m3 of waste-water was discharged in 2008. 51 percent of the discharge was from thermal power plants, 38 percent from municipalities and villages (via waste-water network), 10 percent from manufacturing industries and 1.5 percent from OIZs.

According to 2008 statistics, 2,421 municipalities out of 3,225 have waste-water network systems. Municipalities collected 3.26 billion m3 of waste-water and treated 69 percent of it. There are 236 waste-water treatment facilities owned by the municipalities, 32 of which are advanced-technology facilities, 29 physical treatment, 158 biological treatment and 17 natural treatment facilities.

A.5.1.1. Projections

■ No specific provisions to reduce waste or landfill, nor to increase recycling

■ Growth continues at rate of population plus 1 percentage point

■ Waste fuels unavailable to industry due to lack of infrastructure / regulatory framework

A.6. Agriculture, Forestry and Land Use

Although the contribution of the agriculture sector to Turkey’s total economic output is decreasing, it is still important in terms of meeting local food requirement, supplying input to industry and providing employment. Agriculture and forestry together constituted 10 percent of total GDP in 2008, accounting for 9.4 billion TL at 1998 prices. Growth of the sector has a lumpy trend, reflecting its sensitivity to economic and social conditions.

38 TUIK collects waste-water data from municipalities and villages which have waste-water network, OIZs, thermal

power plants with capacities above 100 MW, manufacturing industry facilities employing more than 50 people.



Figure A.27 Growth of Agriculture and Forestry

0123456789

10

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Val

ue o

f Agr

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and

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TL)

0%

2%

4%

6%

8%

10%

12%

14%

Sha

re in

tota

l GD

P, %

Value of Agriculture and Forestry Share in total GDP

Source: TUIK

High and humid regions of the country are suitable for forestry activities, high and dry regions for livestock production and all regions for crop production. Turkey has a total agricultural land of 40 million hectares (50 percent of the total land area of 770 thousand km2) and forest area of 21 million hectares.39 The chart below shows the use of agricultural land and forest area:

39 [Cite.] The CIA Factobook suggests that only 30 percent land is arable, although this is likely to be a question of the

definition of arable / agricultural lang.



Figure A.28 Agricultural Land and Forest Area

Agricultural land and forest area (61 million Ha)

Forest35%

Meadows and pastures24%

Fruits, vineyards and olives

5%

Fallow land7%

Vegetable1%

Cereals and crops28%

Source: TUIK – 2007 statistics

Agricultural activities are mainly conducted by small-scale family owned enterprises. According to 2006 statistics of TUIK, 99 percent of the enterprises have a land less than 0.5 hectare (5,000 m2). These account for 89 percent of the total land owned by agricultural enterprises and 97-98 percent of the animal stock.



Table A.17 Enterprises in the Agricultural Sector

Size of enterprise, decare

No.of enterprises Land, decare No. of sheep and goats

No. of cattle and buffaloes

Without any Land 54,523 - 1,824,342 299,662

< 5 178,006 481,987 588,265 265,354

5-9 290,461 1,952,471 1,154,216 480,001

10-19 539,816 7,378,022 3,697,403 1,250,855

20-49 950,840 29,531,622 6,468,575 3,129,549

50- 99 560,049 38,127,035 5,427,504 2,746,636

100-199 327,363 43,884,397 4,397,393 1,852,716

200-499 153,685 42,075,498 3,250,858 948,991

500-999 17,429 11,218,554 422,883 111,534

1,000-2,499 4,199 5,476,930 195,722 44,150

2,500-4,999 222 695,541 24,186 2,434

>5,000 57 3,526,175 99,656 15,556

Total 3,076,650 184,348,232 27,551,003 11,147,438

Source: TUIK

According to recent official statistics, half of the 21 million hectares of forest area is productive and the remaining half is degraded.40 The productive forest area has a growing stock of 1 billion m3.

Table A.18 Forest Area, 2005

High Forest Coppice Forest Forest Area, Mn Hectare

Productive 8.9 1.7 Degraded 6.5 4.1

Growing stock, Mn m3 Productive 1,128 70 Degraded 65 24

Source: MEF - Forestry Statistics

40 Ministry of Environment and Forestry

Greenhouse Gas Abatement in Turkey Transaction Costs, Discount Rates, and Payback Assumptions


Appendix B. Transaction Costs, Discount Rates, and Payback Assumptions

B.1. Project Transaction Costs

B.1.1. Households and small/medium firms: background and sources

The “energy efficiency gap”

■ A very large literature has documented how households and firms leave low carbon (particularly, energy efficiency) investments untapped that appear to have with rates of return in excess of 30 percent, as calculated by comparing initial capex against assumed future savings on energy expenditure

■ It also is documented (albeit more anecdotally) that many firms apply very stringent payback criteria to energy efficiency investments (e.g., 3-4 year payback). Comparing results from models (e.g., UK ENUSIM model of industry energy use), it is clear that uptake is limited to measures with very high rates of return (when evaluated at capex + energy savings).

■ Quantitative estimates of these findings, often referred to as the “energy efficiency gap” (although applicable also to small-scale renewables, see below) are often expressed as a discount rate or rate of return – which emerges as a “residual” in modelled or estimated relationships between capex, opex, and other engineering-economic factors. By far the largest body of data on transaction costs are in this format. 41

There is little agreement about the relative importance of the factors that may explain the energy efficiency gap.

■ A large number of explanations have been advanced, with little agreement on what accounts for the observed situation. The main categories of explanation are the following:

- Transaction costs (e.g., “hassle”, cost of time spent, additional staff, costs of contracting, etc.)

- Poor performance of equipment, or high variability in performance (e.g., [CRA])

- High discount time preference rates of individuals. (e.g., Frederick et al. 2002)

- Misaligned incentives, within organisations (E.g., Sorrel et al., 2005)

- Opportunity costs, either of credit in the presence of credit market imperfections, or management / leisure time (e.g., […] )

- Option value associated with and irreversible investments under uncertainty, which in some models have suggested hurdle rates four times higher than the cost of capital. (E.g., […])

- Consumer / manager irrationality.

41 See NERA’s previous note on discount rates for sample references of estimates of the magnitude of costs, typically

expressed as rates of return / discount rates.



■ There is little agreement in the literature about which of the above factors is the most important, or that any of the factors suffices to account for observed behaviour.

The “bottom-up” approach to estimating transaction costs has met with limited success

■ One approach to explaining the observed behaviour has been to supplement standard costs with bottom-up estimates of transaction costs.

■ This is unusual in the academic literature, although there are some isolated examples. It has been more common in the applied or policy-related literature. The below table summarises some of the more extensive recent efforts, spanning both the household and non-domestic sectors, and between them span the large majority of key small/medium-sized renewables and energy efficiency measures.

Table B.1 Examples of Sources on Bottom-Up Estimates of Transaction Costs Faced by

Households and Small/Medium Firms

Source Method Measures Extent of transaction cost

Ecofys (2009) Literature review, expert interviews/survey, and judgement

Energy efficiency: Measures in household sector

5-10 percent, rising to 35-100 percent for individual measures.

Enviros (2006) Literature review, expert interviews / survey, and judgement

Energy efficiency measures: across industry, commercial, and public sectors.

Larger measures typically around 5 percnet, rising to 20 percent or more for smaller or more complex measures.

Element Energy (2008) Stated preference survey

Renewables: for small and micro generation of heat and electricity

Focus on the largest measures, with estimates in the region of 20-40 percent

Enviros (2008a, 2008b) Interviews, expert judgement

Renewables: Heat generation, covering all sectors

1-5 percent for key measures, depending on measure and scale of measure. Negligible for large measures.

Björkqvist and Wene Survey, desk-based judgement

25-30%, based on assumptions about time use

Sathaye et al. (2004) Survey, desk-based judgement

[25-30%, based on assumptions about time use]

■ The purpose of these studies has typically been to augment models to better understand and model household and firm behaviour. However, this cannot be said to have been a success in bridging the gap between technological assumptions and observed behaviour.



None of the above studies has resulted in estimates that correspond to the magnitude implied by observed behaviour.

■ Some of the key difficulties include:

- The lack of data and need for subjective judgement in defining costs

- The specificity and idiosyncracy of relevant costs, and therefore necessary incompleteness of bottom-up estimates.

- The bias introduced by focussing on issues that are more readily quantified

- The likelihood that many factors other than transaction costs (see above list) are important.

■ Our assessment is that these are likely inherent in the methodology. Bottom-up estimates do not succeed in spanning the full range of relevant costs and other factors.

■ The implication for this study is that the more limited estimates available from bottom-up assessments should be supplemented with the much wider data on hurdle rates.

Our approach makes joint use of additions to capex, discount rates, and payback criteria, and is informed by the wider literature on discount rates and “payback” criteria

In addition, these buildings are assumed to be less sensitive to cost differentials between measures, and we also limit the applicability of whole-building measures where the necessary institutions are absent.

B.1.2. Large-scale projects

■ Different considerations arise with large, capital-intensive projects that are at the core of a firm’s business. Here it may be more feasible to itemise transaction costs, although the problems of idiosyncracy and boundaries between transaction costs and other factors (standard capex, risk premia, cost of financing) remain.

■ Evidence is often anecdotal. Examples of sources consulted in the course of developing our estimates include:

- Interviews have suggested that, for example, 10 percent was a reasonable indicative figure for large, capital intensive projects in Ukraine.

- CDM and JI project documents.

For example, estimates of costs for an individual windfarm itemised capex and transaction costs separately, but included interest during construction as a transaction cost. Removing the interest payments, a reasonable estimate of pure transaction costs (site surveys, consulting, contracting, etc.) is 10-15 percent of capex (depending on financing terms).

- Interviews with industrial stakeholders in Turkey, Kazakhstan, and Ukraine

For example, one interviewee noted the higher up-front cost required for investments in industrial capacity in Kazakhstan compared to China or some western countries (citing $200/t instead of $150/t). This datum is a composite of factors: greater delays (higher interest rate payments, higher interest rate, higher



risk); higher capex because of more vertical integration (e.g., need to invest in auxiliary or transport infrastructure); as well as more traditional transaction costs (administrative requirements, more difficult contracting, etc.)

It is clear that there are diverging practices for defining “capex”. For example, some stakeholders did not agree with the distinction, considering land costs and contracting part and parcel of capex; or considering overheads or staff costs as costs to be covered by the hurdle rate criteria used in investment appraisal, rather than as individual line items.

- Project Team JI and investment advisory experience.

E.g., comparisons of client experience of estimates of total project costs vs. published engineering cost estimates for key technologies in the power sector. (However, here too conventions for the boundaries between “capex” and other project costs are nearly never well defined)

■ The data arising from these sources is complex and subject to interpretation. We have centered on a 10 percent addition to transaction costs as a reasonable central estimate.

■ An important observation is that key barriers (likelihood of getting permits, quality of available local contractors, small supplier markets, requirements for political connections) are factors that are crucial to whether projects can realistically go ahead, but not items that can be readily monetised. Rather than affecting cost, they affect whether projects are viable propositions.

B.1.3. Background: Overview of McKinsey assumptions

McKinsey’s assumptions can be summarised as follows:

■ Costs are expressed as a share of capex for project transaction costs. For a given lifetime, this is arithmetically equivalent to expressing costs as a premium on the discount rate.

■ 30%: for household (energy efficiency, waste). Based on two “bottom-up” studies (e.g., time required to find out about energy efficient washing machines).

■ 10% for large measures (energy efficiency, renewables). Based broadly on interviews with Bashinform, EBRD bankers, and Global Carbon, and supplemented by McKinsey judgement.

■ 15% for mid-sized (energy efficiency, renewables, waste). No particular source cited, but “per-project” nature of cost is rationale for higher number than for large projects.

■ Additional assumptions:

- 3% for transport. This is extrapolated from the household number, by comparing vehicle capex to appliance capex.

- 12% for nuclear, CCS. Given lack of (recent) investment history in these, these are speculative.



B.2. Summary of Estimates

We summarise our assumptions for key sectors overleaf.

The following are explanations of columns three to five:

■ Transaction costs, expressed as an addition to up-front cost in terms of a share of the capex.

■ Discount rate and payback period: these are the terms used in the formula to levelise costs.42 For new investments, the equipment lifetime is used. For retrofit, a more stringent requirement may be applied.

42 Costs are levelised by calculating the stream of annual payments would be required over the payback period to generate

a present value equivalent to the capex + transaction costs, when future payments are discounted at the discount rate.



Table B.2 Summary of Barriers Estimates

Category Examples of abatement measures

Transaction costs

(% of capex)

Discount rate (%)

Payback period43 (years)

Notes / motivation

Power and Utilities

Utilities: conventional technologies

New coal plant New gas plant

10% 10% 20 This incorporates a country risk premium

Utilities: renewables Wind power Biomass

10% 10-15% 20 Higher hurdle rates for investment in technologies with less mature supply chains.

E.g., no additional premium for technologies with proven track record of investment (e.g., Turkey hydro); but higher premiums for biomass power, which faces significant supply chain issues.

Utilities: power Power transmission and distribution

10% 10% 20 Lower hurdle rates for utilities where cost-recovery of investments is possible.

Utilities: heat distribution DH networks rehabilitation and upgrades

10% 10% 20 Lower hurdle rates for utilities where cost-recovery of investments is possible.

Households

General Household-scale / small business, insulation measures

House insulation (wall, floors, loft)

Window double/triple-glazing

20% 18% 10 Shorter payback periods motivated by shorter tenure and / or rental and leasing agreements.

Overall hurdle rate consistent with range of published studies.

Household-scale renewable energy

Small-scale heat pumps Domestic biomass boilers

20% 18% 10 Shorter payback periods motivated by shorter tenure and / or rental and leasing agreements.

Overall hurdle rate consistent with range of published studies.

Household water heating Solar thermal 20% 18% 10 Shorter payback periods motivated by shorter tenure and / or rental and leasing agreements.

Heat controls Heat controls Thermostats

20% 18% 10 Shorter payback periods motivated by shorter tenure. Overall hurdle rate consistent with range of published studies.

43 For retrofit measures. New capacity is evaluated at 20 years or the equipment lifetime, whichever is the smallest.




Transaction costs

(% of capex)

Discount rate (%)


Notes / motivation

Passenger transport Passenger vehicles 20% 18% 10 Shorter payback periods motivated by shorter useful lifetime of vehicles

Lighting Low-energy light-bulbs 20-30% 18% 3 Shorter payback periods reflect shorter equipment lifetime

Domestic appliances Energy-efficient appliances 20% 18% 5 Shorter payback periods reflect shorter equipment lifetime

Refrigeration Low-energy fridges and freezers

20% 18% 10 Shorter payback periods reflect shorter equipment lifetime

Air-conditioning Low-energy / modern AC systems

20% 18% 15 Shorter payback periods reflect shorter equipment lifetime

Communal / multiple occupancy buildings

Building fabric of apartment and office blocks

30% 18% 10 Additional transaction costs arise from common action problem (e.g., landlord/tenant split, condominium associations).

Business scale Renewable energy

Biomass boilers Large heat pumps

15% 18% 10 Shorter payback periods motivated by shorter tenure or lease and / or rental and leasing agreements.

Industry, Fugitives, Waste Experimental / end-of-pipe CCS 20% 18% 15 Measures whose sole or main motivation is abatement are

more risky and more difficult to implement than ones that affect energy use or cost.

New industrial production capacity

New Cement capacity New Steel capacity

10% 12% 15 Lower transaction costs reflect established supply chains and well-known planning requirements.

Waste Industrial waste firing 20% 18% 15 Waste-based measures start from a low base (lack of collection and infrastructure), and often face significant regulatory hurdles

Waste (landfill) management

Landfill gas capture 20% 18% 15 Waste-based measures start from a low base (lack of collection and infrastructure), and often face significant regulatory hurdles

Wastewater treatment (municipal and industrial)

Mechanical and biological treatment

Anaerobic digestion

20% 18% 15 Waste-based measures start from a low base (lack of collection and infrastructure), and often face significant regulatory hurdles

Waste heat capture Waste heat recovery in Paper and Pulp industries

10% 12% 15 Lower hurdle rates for energy intensive industry for which energy is a key part of operating cost.

Energy intensive industry Process improvements Energy management systems





Transaction costs

(% of capex)

Discount rate (%)


Notes / motivation

Electricity energy efficiency More efficient motors (pumps, variable speed drives, compressors) Adequately sized motors


Chemical processes Nitric acid catalysts 10% 12% 15 Lower hurdle rates for energy intensive industry for which energy is a key part of operating cost.

Coal Mining Coal mine methane 20% 18% 15 Measures that are unproven are likely to face additional hurdles.

Gas distribution Gas leakage prevention 10% 10% 15 Lower hurdle rates for established technology and processes.

Freight transport Freight road transport Efficient vehicles, improved

maintenance Improved vehicle fleet management

10% 12% 15 Lower hurdle rates for commercial vehicles for which fuel cost and opportunity cost of maintenance time is key part of operating cost.

Agriculture and Forestry Agriculture – crops

Low-tillage; Precision fertiliser application; Ionophores Crop rotation

30% 18% 15 Measures are often dispersed and require changes to practices of cultural importance in sensitive industry.

Agriculture – land use Land conversion Pasture management

30% 18% 15 Extensive coordination with often dispersed land rights. Additionally, land-rights often poorly delineated

Agriculture – livestock Improved manure management

Improved livestock diet

30% 18% 15 Dispersed measures Efficient use of animal waste complicated in the absence of sufficient on-site energy demand (e.g. seasonality issues).

Forestry Afforestation / reforestation Degraded forest restoration

30% 18% 15 Extensive coordination with often dispersed land rights.



Box 3 Comparison of Assumptions to Project Finance Criteria

We have compared the above assumptions to alternative formulations of investment criteria, notably project finance. To take an example, consider project finance for a wind farm investment with the following features

■ 80% debt, 20% equity stake

■ 12% cost of capital

■ 10-year debt maturity, one-year grace period

■ 20 year investment lifetime

■ 25% return on equity

■ DSCR of 1.2

In many configurations, the binding constraint is the DSCR, which requires revenue in individual years to be relatively high – on a par with revenue streams that would result in an effective IRR of 20 percent if sustained throughout the equipment lifetime. We have assumed somewhat lower “equivalent” rates for Turkey, where investment in key renewables appears to be going ahead at IRRs below this level.

Greenhouse Gas Abatement in Turkey Fuel Price Assumptions


Appendix C. Fuel Price Assumptions

In this appendix, the fuel price assumptions are presented – below in Table C.1, and in graphical form in Figure C.1, Figure C.2 and Figure C.3 below.

Table C.1 Fuel Price Assumptions, Year and Scenarios

Sector Fuel Unit 2010 2020 2030All SQ PP EP SQ PP EP

Coal €/tonne 89 97 97 97 100 100 100Gas €/MWh 28.9 40.3 44.4 40.3 44.1 48.5 44.1Oil €/tonne 598 852 852 852 949 949 949Biomass €/MWh 29.7 37.2 37.2 37.2 45.6 45.6 45.6Lignite €/tonne 26.9 27.5 27.5 27.5 25.2 25.2 25.2Electricity 0.01€/kWh N/A N/A N/A N/A N/A N/A N/ACoal €/tonne 115 126 126 126 130 130 130Gas €/MWh 28.9 40.3 44.4 40.3 44.1 48.5 44.1Oil €/tonne 598 852 852 852 949 949 949Biomass €/MWh 29.7 37.2 37.2 37.2 45.6 45.6 45.6Lignite €/tonne 33.7 34.4 34.4 34.4 31.5 31.5 31.5Electricity 0.01€/kWh 10.1 12.3 12.9 13.7 11.8 10.4 13.3Coal €/tonne 178 194 194 194 201 201 201Gas €/MWh 30.5 42.0 46.2 42.0 45.8 50.4 45.8Oil €/tonne 748 1,066 1,066 1,066 1,186 1,186 1,186Biomass €/MWh 31.3 49.5 49.5 49.5 60.7 60.7 60.7Lignite €/tonne N/A N/A N/A N/A N/A N/A N/AElectricity 0.01€/kWh 12.3 14.4 16.9 18.0 13.8 13.5 17.2

Industry

Commercial / Residential

Power

Source: IEA (coal, gas, oil), E4Tech (biomass), IBS (lignite) supplemented by NERA/BNEF estimates and modelling.



Figure C.1 Fuel Price Assumptions - Status Quo

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Figure C.2 Fuel Price Assumptions - Planned Policies

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Figure C.3 Fuel Price Assumptions - Enhanced Policies

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Greenhouse Gas Abatement in Turkey Policy Transaction Costs


Appendix D. Policy Transaction Costs

There is also recognition that the cost of policy should itself be accounted for, however, the practice is not widespread. E.g., the UK Committee on Climate Change does not account for policy costs when compiling its MACC analyses, even though in many cases policies are required to bring forward the abatement measures that are represented. A number of estimates have been made of the administrative and transaction costs associated with the EU Emissions Trading Scheme. For large plants these are quite low, at well below €1 per tCO2, but for smaller plants the costs can become a significantly larger share of the total cost of the policy. Similar estimates have been made of the administrative and transaction costs associated with white certificate schemes or with other energy efficiency policy (NERA, 2006). Credit-based emissions trading has also been analyzed, and typically has higher transaction and administrative costs than cap and trade systems, because of the substantial requirements for determining baselines. Excluding small projects, transaction costs have been estimated at around 15 percent, although there is little agreement.

■ General agreement that there are transaction costs associated with policies. Indeed, the intention of some policies is to create additional time costs to force management attention on energy efficiency

■ The literature estimates on trading transaction costs fall broadly in two camps:

■ For small projects, costs are prohibitive. Household-scale projects tend to entail costs of €40-50 / tCO2. Unsurprisingly, such projects are rarely or never undertaken under credit-based emissions trading like CDM or JI.

■ For large projects that are actually undertaken, costs vary from negligible to up to €3 / tCO2. These we regard as within the margin of error of most abatement cost estimates (dwarfed, for example, by fuel price risk)

Greenhouse Gas Abatement in Turkey MAC Curve Data


Appendix E. MAC Curve Data

This appendix provides the underlying data for the full MAC curves presented in the main body of the report.

Table E.1 Full MACC, Status Quo Policy, 2030

Sector Description Abatement potential (MtCO2)

Abatement cost (€ / tCO2)

Buildings Air Conditioning (high-efficiency models) 1.0 -300

Buildings Non-Residential Lighting (fluorescent, halogen and LED light bulbs) 0.3 -300

Industry Cement (high clinker substitution, fuel switching and waste firing, kiln modernisation, process improvements) 1.2 -300

Buildings Residential Lighting (fluorescent, halogen and LED light bulbs) 1.0 -300

Buildings Residential Water Heating (condensing gas boilers, solar water heaters) 3.5 -259

Transport Passenger Road transport (increased fuel efficiency, hybrid and electric vehicles, LPG retrofit) 13.3 -246

Buildings Residential Buildings (fuel switching, floor / roof insulation, double- and triple-glazing, external wall cladding, cavity wall insulation) 7.1 -241

Industry Copper (improved monitoring and targeting, modern furnaces) 0.1 -211

Industry

Steel (process improvements including coal moisture control, heat recovery, energy monitoring and management, hot blast stove automation) 1.4 -197

Transport Passenger aviation (increased fuel efficiency in passenger aviation (lighter airframes, improved aerodynamics) 0.2 -194

Buildings Refrigerators (energy efficient models) 0.8 -188

Buildings Non-Residential Water Heating (condensing gas boilers, solar water heaters) 0.2 -187


Industry Paper (waste heat recovery, process control and pinch analysis) 0.1 -144

Buildings Non-Residential Buildings (fuel switching, floor / roof insulation, double- and triple-glazing, external wall cladding, cavity wall insulation) 3.2 -141

Industry Ceramics (improved drying and firing) 0.4 -137


Industry Petrochemicals (improved processes including drying, distillation and evaporation; waste heat recovery) 0.1 -119


Industry Oil refineries (energy management, improved process controls, pumps / motors / compressed air, waste heat recovery) 1.0 -104


Buildings Residential thermostats / heat allocators (allowing heat control) 2.2 -94

Buildings Non-Residential Water Heating (condensing gas boilers, solar water 0.4 -66





heaters)


Industry Glass (advanced burner systems, waste heat recovery, external cullet) 0.1 -65

Industry Lime (shell heat loss reduction, improved kiln combustion, process control) 0.8 -50


Buildings Non-Residential thermostats / heat allocators (allowing heat control) 0.3 -47

Power Wind (High-quality sites) 10.8 -39

Power Hydroelectric power (High-quality sites) 11.5 -22

Power Wind (Medium-quality sites) 5.6 -22

Industry Bricks (improved drying and firing) 1.0 -21


Industry Gas pipelines (repair of leaks, replacement of high-bleed pneumatic devices, preventative maintenance) 1.5 -16



Agriculture Livestock (improved manure and enteric management) 0.3 -7

Transport Passenger Road transport (increased fuel efficiency, preventative maintenance) 6.6 -1

Power CCGT Power (New plants) 18.8 -1

Power CCGT Power (Upgraded existing plants) 0.1 -1

Industry Coal mine methane (enhanced degasification, flaring, power production) 1.5 -1

Power Hydroelectric power (Medium-quality sites) 0.1 -1

Power Geothermal power 0.1 -1

Power Wind (Medium-quality sites) 0.8 5

Industry Coal mine methane (enhanced degasification, flaring, power production) 0.5 5

Transport Passenger Road transport (increased fuel efficiency, hybrid and electric vehicles, LPG retrofit) 0.3 6

Waste Municipal waste water (flaring, waste treatment and anaerobic digestion) 2.3 6

Power CCGT Power (New plants) 58.1 7

Industry Acid production (Nitric acid: extended use of catalysts) 1.7 9

Waste Landfill gas (composting, waste treatment, energy generation) 0.9 10

Buildings Residential Water Heating (condensing gas boilers, solar water heaters) 0.4 12

Agriculture Livestock (improved manure and enteric management) 0.9 13

Power CCGT Power (Upgraded existing plants) 0.4 13





Waste Industrial waste water (flaring, waste treatment and anaerobic digestion) 0.7 15

Power Hydroelectric power (Medium-quality sites) 14.0 15

Power Lignite power generation - Biomass co-firing 0.3 15


Industry Petrochemicals (improved processes including drying, distillation and evaporation; waste heat recovery) 0.1 16

Transport Passenger Road transport (increased fuel efficiency, preventative maintenance) 1.5 17

Industry Ceramics (improved drying and firing) 0.1 17

Industry Oil refineries (energy management, improved process controls, pumps / motors / compressed air, waste heat recovery) 0.1 17

Buildings Non-Residential Buildings (fuel switching, floor / roof insulation, double- and triple-glazing, external wall cladding, cavity wall insulation) 0.3 20

Power Geothermal power 10.8 22


Buildings Residential Buildings (fuel switching, floor / roof insulation, double- and triple-glazing, external wall cladding, cavity wall insulation) 4.3 24





Industry Bricks (improved drying and firing) 1.1 29






Power Nuclear power 12.5 41







Waste Industrial waste water (flaring, waste treatment and anaerobic 0.1 48





digestion)

Industry

Steel (process improvements including coal moisture control, heat recovery, energy monitoring and management, hot blast stove automation) 0.1 49



Industry Cement (high clinker substitution, fuel switching and waste firing, kiln modernisation, process improvements) 0.2 51



Power Lignite power (upgraded existing plant) 0.1 56









Industry Gas pipelines (repair of leaks, replacement of high-bleed pneumatic devices, preventative maintenance) 0.3 73



Power Wind (High-quality sites) 0.1 77




Power Wind (Offshore) 0.6 91


















Power Coal power generation - Biomass co-firing 0.3 133

Industry













Table E.2 Full MACC, Planned Policies Scenario, 2030


Abatement cost (EUR

/ t)










Power Power Transmission and Distribution (improved monitoring, control and fault detection, reduced losses) 2.7 -194



Industry

















Abatement cost (EUR

/ t)



Power Nuclear power 47.7 -80





















Power IGCC Power 0.1 5

Power Hydroelectric power (Imports from Georgia) 3.4 5






Power Hydroelectric power (Medium-quality sites) 13.7 10




Abatement cost (EUR

/ t)



Buildings Non-Residential Water Heating (condensing gas boilers, solar water heaters) 0.1 15





























Abatement cost (EUR

/ t)




Industry






























Abatement cost (EUR

/ t)














Industry












Table E.3 Full MACC, Enhanced Policies Scenario, 2030


Abatement cost (EUR /

t)












Buildings

Non-Residential Buildings (fuel switching, floor / roof insulation, double- and triple-glazing, external wall cladding, cavity wall insulation) 4.3 -239



Industry











Power Lignite power (upgraded existing plant) 0.4 -136






t)












Power Hydroelectric power (Imports from Georgia) 2.4 -86


Power Wind (Low-quality sites) 12.2 -86






Buildings

Non-Residential Buildings (fuel switching, floor / roof insulation, double- and triple-glazing, external wall cladding, cavity wall insulation) 2.8 -56




Industry Acid production (Nitric acid: extended use of catalysts) 0.9 -30



Waste Landfill gas (composting, waste treatment, energy generation) 5.8 -12

Waste Industrial waste water (flaring, waste treatment and anaerobic digestion) 0.5 -12

Waste Municipal waste water (flaring, waste treatment and anaerobic digestion) 1.2 -12





t)

Waste Industrial waste water (flaring, waste treatment and anaerobic digestion) 0.1 -11

Waste Municipal waste water (flaring, waste treatment and anaerobic digestion) 3.5 -9









Industry





Buildings

Non-Residential Buildings (fuel switching, floor / roof insulation, double- and triple-glazing, external wall cladding, cavity wall insulation) 3.5 16






Power Coal Power (Upgraded existing plants) 0.1 26










t)







Buildings














Industry


Buildings








Buildings Non-Residential Buildings (fuel switching, floor / roof insulation, 0.2 89





t)

double- and triple-glazing, external wall cladding, cavity wall insulation)




Buildings







Buildings







Buildings







Buildings




Table E.4 Full MACC, Capital Grants Scenario, 2030


Abatement cost (EUR

/ t)















Industry
















Abatement cost (EUR

/ t)















Power Wind (Low-quality sites) 12.2 -30

Power Hydroelectric power (Imports from Georgia) 2.4 -30















Waste Municipal waste water (flaring, waste treatment and anaerobic 2.3 6




Abatement cost (EUR

/ t)

digestion)









Power Power Transmission and Distribution (improved monitoring, control and fault detection, reduced losses) 0.1 18













Power Coal Power (New plants) 0.7 36




Power CCGT Power (Existing plants) 0.1 45



Industry Steel (process improvements including coal moisture control, heat recovery, energy monitoring and management, hot blast stove

0.1 49




Abatement cost (EUR

/ t)

automation)


















Power Coal Power (Upgraded existing plants) 0.2 82










Industry Steel (process improvements including coal moisture control, heat recovery, energy monitoring and management, hot blast stove

0.2 105




Abatement cost (EUR

/ t)

automation)














NERA Economic Consulting 15 Stratford Place London W1C 1BE United Kingdom Tel: +44 20 7659 8500 Fax: +44 20 7659 8501 www.nera.com

NERA UK Limited, registered in England and Wales, No 3974527 Registered Office: 15 Stratford Place, London W1C 1BE

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