J U L I A R E I N A U D

I N T E R N A T I O N A L E N E R G Y A G E N C Y

February 2005

INDUSTRIAL COMPETITIVENESSUNDER THE EUROPEAN UNIONEMISSIONS TRADING SCHEME

INTERNATIONAL ENERGY AGENCYAGENCE INTERNATIONALE DE L’ENERGIE

IEA INFORMATION PAPER

Industrial Competitiveness under the European Union Emissions Trading Scheme

IEA Information paper Julia Reinaud

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ACKNOWLEDGEMENTS Julia Reinaud is the principal author of this paper, with contributions from William Blyth and Richard Baron under supervision of Richard Bradley (IEA). The author would like to thank Gilles Reinaud (Commodities and Environment Consulting Services), Martina Bosi, Pierpaolo Cazzola, Douglas Cooke, Jonathan Coony, Peter Fraser, Dolf Gielen, Nicolas Lefèvre, Ulrik Stridbaek, and Noé van Hulst (IEA) for the information, comments and ideas they have provided throughout this research. Frank Branvoll (Storaenso), Karl Buttiens (Arcelor), Jean-Marie Chandelle (Cembureau), Jean-Pierre Debruxelles (Eurofer), Yann De Lassat (Arcelor), James Leake (J.E. Hyde), Claude Lorea (Cembureau), Alessandro Profili (Alcoa), Eirik Nordheim (EAA), John Scowcroft (Eurelectric), Florian Reinaud (Apax Partners), and Peter Zapfel (European Commission) also provided very useful suggestions and advice.

The ideas expressed in this paper are those of the author and do not necessarily represent views of the IEA or its member countries.

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TABLE OF CONTENTS

EXECUTIVE SUMMARY INTRODUCTION METHODOLOGY AND APPROACH 1. ENERGY-INTENSIVE USERS UNDER THE EU ETS .......................................................................... 17 1.1. COMPETITIVENESS AND EMISSIONS: DEFINITION AND SCOPE .................................................. 17 1.1.1. COMPETITIVENESS: DEFINITION AND SCOPE ......................................................................... 17 1.1.2. INDUSTRIES COVERED ........................................................................................................... 18

1.1.2.1. CEMENT ..................................................................................................................... 18 1.1.2.2. STEEL ......................................................................................................................... 20 1.1.2.3. PULP AND PAPER ........................................................................................................ 21 1.1.2.4. ALUMINIUM ............................................................................................................... 22

1.1.3. DEFINING INDUSTRIAL EMISSIONS ........................................................................................ 24 1.2. THE WEIGHT OF INDUSTRY’S CO2 EMISSIONS IN EUROPE ......................................................... 24 2. POTENTIAL IMPACT OF EMISSIONS TRADING ON INDUSTRIES UNDER THE EU CAP-AND-TRADE REGIME .................................................................................................................................................. 27 2.1. ASSUMPTIONS ON THE INDUSTRIES COVERED IN THE STUDY.................................................... 28

2.1.1. STEEL ............................................................................................................................. 28 2.1.2. PULP AND PAPER ............................................................................................................ 36 2.1.3. CEMENT ......................................................................................................................... 39 2.1.4. ALUMINIUM ................................................................................................................... 43

2.2. DIRECT IMPACT OF ETS ON INDUSTRIES ................................................................................... 46 2.2.1. Direct CO2 emissions from process related emissions and from energy consumption . 46 2.2.2. Potential increase in industries’ costs ............................................................................ 46

2.3. INDIRECT IMPACT OF ETS ......................................................................................................... 48 2.3.1. The impact of ETS on electricity prices ........................................................................ 48 2.3.2. Sensitivity analysis based on different CO2 prices and different passing-on ranges ..... 49 2.3.3. Potential increase in industries’ costs ............................................................................ 51

2.4. ESTIMATES OF THE TOTAL COST OF THE EU ETS ..................................................................... 52 3. FROM COSTS TO COMPETITIVENESS .............................................................................................. 55 3.1. IMPACT ON OPERATIONAL PROFITABILITY MARGINS ................................................................ 55 3.2. IMPACT OF A COST FEED-THROUGH TO PRODUCT ..................................................................... 56 3.2.1. DEMAND RESPONSE ............................................................................................................... 56 3.2.2. MARKET CONCENTRATION .................................................................................................... 57 3.2.3. TRADE OPENESS .................................................................................................................... 59 3.3. EXPOSURE TO INTERNATIONAL MARKETS ................................................................................. 59 3.3.1. INTERNATIONAL FREIGHT MARKETS ..................................................................................... 60 3.3.2. ASSUMPTIONS FOR FREIGHT COSTS ....................................................................................... 62 3.3.3. COMPARING CO2 IMPACTS ON MARGINAL PRODUCTION WITH FREIGHT COSTS ................... 62 4. FROM COST TO CARBON LEAKAGE ................................................................................................. 67 5. EXPLORING POTENTIAL PROBLEMS AND SOLUTIONS .................................................................... 70 5.1. TACKLING THE INDIRECT IMPACT OF EU-ETS .......................................................................... 71

5.1.1. TAXING PROFITS AND RECYCLING REVENUES TO INDUSTRY ........................................ 71 5.1.2. DIRECT PLUS INDIRECT EMISSIONS ............................................................................... 72 5.1.3. BENCHMARKING ALLOCATION FOR THE POWER SECTOR WITH EX-POST ALLOCATION 72 5.1.4. SEPARATING CO2 PRICES FROM POWER PRICES ............................................................. 73 5.1.5. TREATMENT OF NEW ENTRANTS IN THE ELECTRICITY MARKET .................................... 74 5.1.6. REGULATORY MEASURES .............................................................................................. 76

5.2. PROCESS RELATED EMISSIONS: THE BENCHMARKING ALTERNATIVE ....................................... 76 5.3. THE CASE OF TRANSFERRED EMISSIONS FROM BLAST FURNACE GAS (BFG) EXPORT .............. 78 5.4. IMPLEMENTING TARIFFS ON IMPORTED PRODUCTS FROM NON-CARBON CONSTRAINED COUNTRIES ............................................................................................................................................ 79

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6. CONCLUSIONS ............................................................................................................................... 81 7. REFERENCES .................................................................................................................................. 82 8. ANNEX 1: SHARE OF INDUSTRY’S CO2 EMISSIONS IN EU-15 AND EU-25 .................................... 86 9. ANNEX 2: IRON AND STEEL ........................................................................................................... 86 EASTERN EUROPEAN INTEGRATED STEEL MILL ................................................................................... 88 10. ANNEX 3: STEEL TRADE IN 2002 ............................................................................................... 89 11. ANNEX 4: CONCENTRATION OF INDUSTRY ON A WORLD-SCALE .............................................. 89 12. ANNEX 5: WORLD PRICES FOR HRC STEEL (FROM INTEGRATED MILLS) .................................. 90

LIST OF TABLES

Table 1: Key Features of the EU Emissions Trading Scheme .............................................................. 14 Table 2: Energy use in the EU-15 industry ........................................................................................... 25 Table 3: CO2 emissions in the EU-15 and EU-25 industry ................................................................... 27 Table 4: Cost Breakdown for a Western BOF Plant ............................................................................. 30 Table 5 Cost Assumptions for a Western BOF (Greenfield Project) .................................................... 31 Table 6: Representative integrated steel plants in Europe .................................................................... 32 Table 7: CO2 Emissions from Electricity in a Western Integrated Plant ............................................... 33 Table 8: Total CO2 emissions from a Western BOF plant .................................................................... 33 Table 9: Cost Breakdown for an Electric Arc Furnace Plant ................................................................ 34 Table 10: Cost assumptions for an EAF plant ....................................................................................... 35 Table 11: CO2 Emissions from electricity consumption in an EAF Plant ............................................. 36 Table 12: Total CO2 Emissions from an EAF Plant (tCO2/t of steel) .................................................... 36 Table 13: Breakdown of Costs for a Newsprint Mill in Europe (average) ........................................... 37 Table 14: Cost Assumptions for a Newsprint Mill................................................................................ 38 Table 15: CO2 Emissions from Electricity in a Mixture of Newsprint Mills ........................................ 38 Table 16: CO2 Emissions from Energy Combustion in a Newsprint Mill ............................................. 39 Table 17: Total CO2 emissions from a newsprint mill .......................................................................... 39 Table 18: Average Price per Tonne of Cement ..................................................................................... 40 Table 19: Cost Assumptions for a Cement Plant .................................................................................. 41 Table 20: CO2 Emissions from Energy-use in a Representative Cement Test Plant ............................. 42 Table 21: CO2 Emissions from Electricity in a Cement Test Plant ....................................................... 43 Table 22: Total CO2 Emissions in a Cement Test Plant ........................................................................ 43 Table 23: Cost Breakdown for an Aluminium Plant ............................................................................. 44 Table 24: Cost Assumptions for an average aluminium plant in the EU .............................................. 44 Table 25: Indirect CO2 Emissions from Electricity Use in an Aluminium Plant .................................. 45 Table 26: Total CO2 emissions covered under the first EU-ETS trading period per tonne of product . 46 Table 27: Increase in costs for marginal products ................................................................................. 47 Table 28: New cost structure for marginal cement production plant, including the direct impact of a

EUR10/tCO2 price ......................................................................................................................... 47 Table 29: Increase in electricity prices in Continental Europe assuming full opportunity cost ............ 50 Table 30: Increase in total costs per tonne of finished product assuming full opportunity cost ........... 51 Table 31: Direct plus indirect impact for a EUR10/tCO2 price for marginal products ......................... 52 Table 32: Direct and indirect cost increase under 2 per cent scenario (EUR10/tCO2) .......................... 53 Table 33: Direct and indirect cost increase under 10 per cent scenario (EUR10/tCO2) ........................ 54 Table 34: Effect of the EU ETS on industries’ operational margins (at EUR10/tCO2) ........................ 55 Table 35: New market price (EUR per tonne of finished product) for a EUR10/tCO2 allowance price

....................................................................................................................................................... 56 Table 36: Demand reductions from price increases with constant profitability margins for a

EUR10/tCO2 allowance price ........................................................................................................ 57 Table 37: World fleet of bulk and general cargo carriers ...................................................................... 60 Table 38: Fleet in Million DWT and % change year on year ............................................................... 61 Table 39: Simulation of imported steel in Europe from China ............................................................. 66 Table 40: CO2 Emissions from Combustibles and Electricity in a Western Integrated Plant ............... 86 Table 41: Cost Assumptions for an Eastern BOF ................................................................................. 88

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LIST OF FIGURES

Figure 1: Process Steps in Cement Manufacture ................................................................................... 19 Figure 2: 2003 World Cement Production by Region ........................................................................... 19 Figure 3: Steel Prices for Hot Rolled Coil (HRC)................................................................................. 21 Figure 4: Aluminium Making Process .................................................................................................. 22 Figure 5: Steel Export Prices from Brussels 2003-06/2004 .................................................................. 30 Figure 6: Gases Emitted and Recycled in an Integrated Steel Plant ..................................................... 32 Figure 7: Steel Export Prices from Eastern Europe 2003-06/2004 ....................................................... 34 Figure 8: Primary Energy Consumption by Carrier (TJ, 2002)............................................................. 37 Figure 9: Consumption of Energy Sources used in Kilns (2002) .......................................................... 41 Figure 10: Aluminium LME Prices (Monthly, USD / tonne) ............................................................... 44 Figure 11: European merit order and impact of a EUR15/tCO2 carbon price ....................................... 50 Figure 12: Increase in power prices following different carbon prices and passing-on ranges ............ 51 Figure 13: Openness to extra-UE 15 Competition and CO2 emissions in 2001 .................................... 59 Figure 14: Freight rates on several trade routes (in USD per tonne)..................................................... 62 Figure 15: CO2 allowance prices with freight costs in EUR/tonne of cement bulk .............................. 63 Figure 16: CO2 allowance prices with freight costs in EUR/tonne of paper rolls ................................. 64 Figure 17: Freight costs in EUR/tonne of wire rod steel ....................................................................... 64 Figure 18: CO2 allowance prices with freight costs in EUR/tonne of HRC steel ................................. 65 Figure 19: Prices of HRC steel (USD/t) ................................................................................................ 66 Figure 20: CO2 allowance prices with freight costs in EUR/tonne of aluminium ingots ...................... 67 Figure 21: Estimated production change as a function of the EU15 emission CO2 price ..................... 69 Figure 22: Repartition of roles under CO2 price separation from power prices .................................... 73 Figure 23: Share of Industry’s CO2 emissions in EU ............................................................................ 86 Figure 24: Steel Export Prices from Eastern Europe 2003-06/2004 ..................................................... 87 Figure 25: Global steel trade in 2002– China’s importance (tonnes) .................................................... 89 Figure 26: Concentration level world-wide .......................................................................................... 89 Figure 27: Price of HRC steel (USD/t) ................................................................................................. 90

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EXECUTIVE SUMMARY

The European Union has decided to introduce an emissions trading scheme to curb Europe industry’s emissions, starting with a pilot phase running from 2005 to 2007, followed by a second phase from 2008-2012. In its first phase, the EU emissions trading scheme (EU ETS) will cover carbon dioxide (CO2) emissions from power generation, oil refineries, coke ovens, iron and steel, cement, lime, glass, ceramics, and pulp and paper, as well as from all combustion plants with a rated thermal input of more than 20MW of capacity.

The industry sector (excluding electricity) is an important source of greenhouse gas emissions especially CO2 in IEA countries. Since 1990, the share of these emissions has decreased by over 7 per cent in IEA countries. Nevertheless, in countries such as Japan, industry emissions have grown by approximately 5 per cent since 1990. Currently, CO2 emissions related to industry represents on average 15 per cent of total energy-related emissions of IEA countries (i.e. 1 705 MtCO2). In 2002, industry CO2 emissions equalled 561.7 MtCO2 in EU-15 – or 18 per cent of EU-15 total CO2 emissions. Industry’s share of CO2 emissions was 19.4 per cent of the total EU-25 in the same year – or 602.4 MtCO2 in EU-25.

The World Energy Outlook (WEO) 2004 Reference Scenario projects that the industry sector will increase its CO2 emissions in EU-25 by 0.1 per cent per year from 2002 to 2030. Power generation CO2 emissions will rise from 1308 MtCO2 in 2002 to 1669 MtCO2 in 2030 (+0.9 per cent per year), taking into account government policies and measures on climate change and energy security that had been adopted mid-20031.

The stated purpose of the EU ETS is to cap industry’s emissions with a policy instrument that helps to minimise cost, so that it affects its competitiveness the least. The economic rationale behind emissions trading, applied to a large number of installations belonging to heterogeneous sectors, is that no source should pay more, at the margin, than another to reduce its emissions.

Objective

The EU ETS is embedded in the broader regime created by the Kyoto Protocol, but it applies only to a subset of countries whose industry, in some cases, competes with producers whose emissions are not limited. This step has triggered a debate among industrialists on how much the EU ETS would affect their competitiveness while leaving others’ unharmed. This study seeks to bring an analytical perspective on this question. It should not be, however, taken as a critical evaluation of the instrument that was adopted by EU governments to promote greenhouse gas reductions towards their commitments under Kyoto2. Our scope is to assess short to medium term impacts of emissions trading from the standpoint of international competitiveness, including cost differential, losses of output, and the possibility of leakage. An important element of this issue is industry’s ability to pass carbon cost increases associated with emissions trading onto product prices.

1 It does not take into account a fixed cap on emissions introduced by the EU-ETS. 2 A full assessment of the regime would require comparing it to other policy options (a tax on emissions, command-and-control regulations, industry benchmarks, unilateral policies implemented by EU Member States, etc.), assuming an identical environmental goal, which we do not propose to do.

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Methodology

The introduction of the EU ETS is likely to increase production costs of industrial activities covered by the Directive. These will incur cost to control their emissions or to acquire emission allowances if they need to cover emissions above their initial quotas. The price of CO2 allowances, a price to be paid on marginal emissions, ought to guide industry to conduct emission abatement measures that it would not have undertaken otherwise. There may of course be cases where CO2 emission reductions will trigger savings. Parts of industry will also be in position to sell allowances into the market – there will be no market without sellers. Nevertheless in what follows, our working assumption is that the EU ETS will entail a net cost. Its magnitude is what is considered here.

Beyond the direct cost of complying with an emissions cap, there is an indirect cost attached to the likelihood that carbon intensive power plants will pass their CO2 costs onto wholesale markets, resulting in higher electricity prices. In theory, the value of carbon emission allowances should be reflected in the short run generating costs of fossil-fired plants, since any excess emissions would imply the purchase of allowances – and in return, every unused carbon allowance has a market value (the so-called opportunity cost) (Reinaud, 2003). The increase in electricity costs will affect the cost structure of all electricity users, including industry, inside EU-25.

This study considers both the direct and the indirect costs associated with emissions trading for several industries (i.e. steel, cement, pulp and paper, and aluminium) and the likely impact on these industries’ competitiveness. Loss of competitiveness is defined in this paper as a loss in output – including reduction in demand and production leakage via industry relocation outside the region.

Evaluating the direct cost of meeting an emission cap under emissions trading

For every source covered by an emissions trading, the cost of complying with the set goal can be described as follows:

Compliance cost = internal abatement cost + allowance cost (or - allowance revenue)

where the allowance cost is the expenditures incurred to buy allowances to cover emissions – the allowance revenue being the monetary value of allowances sold to other participants. Since it is not possible to predict to which degree plants or companies will undertake abatement investments to meet their objective and to which degree they will rely on the market to comply, we assume that every avoided emission carries a cost equal to the allowance market price. This leads to overestimating near-term compliance costs: 1) In theory, sources invest in internal reductions that are less expensive than the market price; 2) Some sources, in so doing, become net sellers and therefore offset part of their investment. Our aim is therefore only to provide upper bounds for orders of magnitude, i.e., not to predict compliance costs under the EU ETS.

We work from two different allocation scenarios: industry would be allocated allowances covering either 98 or 90 percent of its CO2 emission needs (hereafter referred to as 10 per cent and 2 per cent scenarios).The total cost of emissions trading in this study includes both this direct cost and indirect costs triggered by increased power prices.

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Caveats

Our cost assumptions for various industries are not meant to illustrate a particular installation, but rather an average plant in the sector in the EU region In reality, details in plant economics will deviate from the average reported here. The findings on the near-term costs of emissions trading may thus be over-estimated as several potentially important factors are not considered. Other reasons prevent us from claiming full accuracy:

• The study does not rely on actual National Allocation Plans (i.e., official national data describing allowances allocated on a plant by plant basis); rather, we rely on an aggregate description of the key sectors’ technologies and products. In reality, there are differences among European countries’ National Allocation Plans. Different interpretations of the scope of the scheme could thus distort competition across the European Union. This could clearly provide affected sectors with a competitive advantage over similar installations in other states which are covered (Leigh, 2004);

• We do not consider CO2 reduction options available in these sectors – nor the effect of endogenous technological change and learning effects that could decrease reduction costs. With the exception of the power sector, abatement costs are not well documented. In addition, the variety of industries covered by the EU-ETS and uncertainties on the total allocation and on the resulting CO2 price make it impossible to evaluate the actual cost of abatement that each sector will face.

• Efforts to maintain emissions under the agreed cap also hinge on the level of activity of each sector. A higher demand for steel would trigger higher emissions, making it more costly to comply, but would also result in higher steel prices and allow for a larger portion of carbon cost to be passed on to steel consumers;

• The carbon content of electricity is the average for the EU in 2001. In reality, the carbon content per MWh differs from country to country – from a high 0.822 tCO2/MWh in Greece to 0.004 tCO2/MWh in Norway. Depending on pricing mechanisms, different carbon contents could lead to different electricity price increases for a similar price of CO2. On the other hand, parts of industry still have long-term power supply contracts that would somewhat protect them from a full pass-through of the carbon cost into power prices. Unfortunately, it is not possible to take such specifics into account in any aggregate analysis;

• Allowance trading will require buyers and sellers. Sellers would be better off than the representative plants used in our scenarios – unless we assume that all the allowances needed by industry and power generation in Europe will be supplied via the Clean Development Mechanism and Joint Implementation projects;

• Industrial competitiveness is a controversial and multi-faceted notion. It depends on a number of factors including primary factor and other input costs, the availability of a skilled labour force, company’s ability to compete on quality as well as cost and to generate product innovations. Some of these strategic considerations are outside the scope of this discussion. In particular, we

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exclude the possibility that the carbon constraint would trigger innovations leading to overall cost reductions, product improvements or other sources of competitive advantage3.

Implications on Production Costs

In what follows, we assume an average allowance price of EUR10 per tCO2. Assuming that electricity pricing would lead to a full pass-through of the carbon opportunity cost in power prices, this carbon price would result in an 11 per cent price increase in Continental Europe. On top of this indirect cost, industry would face the cost of complying with its own emission objective. The following table indicates the impact of both direct and indirect carbon cost for the 2% and 10% scenarios.

Table ES-1: Cost increases in industry for a EUR10/tCO2 allowance price

Scenario / Sector Steel (Basic

Oxygen Furnace)

Steel (Electric Arc

Furnace) Cement Newsprint Aluminium

2% allowance needs 0.7% 0.8% 1.9% 1.1% 3.7%

10% allowance needs 1.3% 0.9% 3.4% 1.6% 3.7%

Based on our assumptions and methodology, aluminium, a sector not directly covered by the EU ETS, would incur a production cost increase as a result of increased power prices. Cement also faces a relatively high cost increase resulting from a high CO2 content combined with a low output price.

On the whole, the above results suggest that they EU ETS would only have modest impacts on the cost structure of these industries in the short run, when considered through the lens of an average EU plant. Some caveats remain, which may move these estimates up or down from the above picture or exacerbate intra-EU differences:

• Some industries in some countries may be closer to the 2% scenario while others are in the 10% scenario in their respective national allocation plans These differences cannot be taken into account here.

• Similarly, for sectors with a high degree of exposure to the so-called indirect effect, the marginal generation technology that is most prominent in their market will set the tone on overall electricity price increases. Here again, effects may differ greatly. Only experience will indicate whether these differences matter and if power market prices reflect the CO2 cost at the margin or not.

Demand Response

The increase in cost mentioned above could either be absorbed by industry through a reduction of its operational earnings or be passed onto consumers through product price increases. Any price increase should be followed by a reduction in sales; the crucial question is these sectors’ ability to maintain profits while sustaining output levels.

3 This is known as the Porter hypothesis, which has been demonstrated in specific case studies (Porter and von der Linde, 1995). See also Golombek and Raknerud (1997) for an analysis of the impacts of strong environmental policy on industrial employment.

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If we assume perfect competition in these industries’ markets, i.e., the inability to increase product prices as a result of the carbon cost, reductions in operational earnings would be from modest to significant.

If industry were to pass on the total carbon cost increase to consumers, it would incur a reduction in product demand, as shown below.

Table ES-2: Demand reductions with product prices assuming constant profitability margins (EUR 10/tCO2)

STEEL BOF STEEL EAF CEMENT NEWSPRINT ALUMINIUM

Price elasticity: -1.56 -1.56 -0.27 -1.88 -0.86 Scenario

2% allowance needs -0.8% -0.5% -0.4% -1.8% -2.9% 10% allowance needs -1.6% -1.2% -0.7% -2.3% -2.9%

Market concentration and market power, but also the degree of market openness to non-EU competitors, affect capacity to reflect cost increases in product prices. More work is needed to provide a more complete evaluation framework for this issue. We note however that among the sectors studied, the one which is more open to international competition than the European average is the non-ferrous metals sector, including aluminium. This suggests that this sector would be most exposed to a loss in competitiveness on the international market.

Impacts on Trade Flows

Assessing competition between EU and non-EU countries for both exports and imports of industrial products requires taking freight costs and border tariffs into account. A comparison of international transportation costs with CO2 cost provide an indication of the level at which products from non-carbon constrained countries – including freight costs and cost differentiation – would become cost-competitive.

Freight prices have risen strongly since 2003, following sharp increases in traded volumes (in steel and coal, mostly going to China), yet this may only be temporary. At current levels, freight costs would protect the European industry from imports from countries with no carbon constraints. However, foreign imports could compete in European markets for some steel products and, most of all, aluminium, for which freight costs would be less than the increased cost of electricity as a result of the carbon constraint. The study did not consider competition from near regions such as Southern Mediterranean, for which freight costs are lower than for American and Far-East imports. Neither does the study cover the impacts on EU competitiveness in foreign markets.

One of the main concerns relates to the threat of CO2 re-location, known as “carbon leakage”: reductions achieved domestically would be partly offset by increased emissions from competitors or resulting from relocation of production outside the region. Economic models project important leakage rates for the above industries with a carbon tax of EUR20/tCO2. The free allocation of the vast majority of allowances under the EU ETS and the lower production cost increase that this allocation mode entails when compared with a carbon tax suggest that any leakage would be considerably lower than previously projected, at least in the near term.

Potential Problems

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The above results cannot be taken as perfect forecasts. There may be cases, especially in the future as the CO2 constraint could be more binding, where competitiveness effects would become visible and leakage would emerge. How could the emissions trading regime be adjusted to mitigate these problems without losing its cost-effectiveness as a pollution control policy? The report lays out some of these concerns (the impact of indirect effects, physical limits on emission reductions) and includes a discussion of solutions to potential competitiveness problems as raised by industry in Europe, touching on rising electricity prices, the issue of process-related emissions, benchmarking and trade measures solutions.

Concerns have been voiced by industry regarding the potentially damaging effects of power pricing reflecting the full marginal cost of CO2 emissions – referred to as the indirect effect in this study. This is often presented as more damaging to competitiveness than the direct cost of industry’s own CO2 emissions. Various stakeholders have explored ways to limit these so-called indirect costs. In looking at this question, it is important to keep in mind that marginal cost pricing is coherent with the assumed cost-effectiveness of emissions trading as an instrument whereby economic agents are encouraged to lower the consumption of emission-intensive inputs and products.

Other industries have also asked for a special treatment of so-called process emissions, i.e., emissions that are inherent to the manufacturing process of the product in question. Benchmarking – setting an industry wide standard – is presented as a solution to encourage innovation towards reducing these emissions. The administrative cost and the uncertainty on overall emission volumes (goals would be set per unit of output) implied by these options need to be considered carefully in light of the expected gains and the existing alternative (grandfathering based on past emission levels, including process-related emissions).

In Closing

The main objective of the allocation process in an emissions trading scheme should be to create a level playing field for all sources that must now control their emissions and direct investment and management toward less CO2-intensive production processes, while remaining competitive with the rest of the world. It is therefore important to provide some degree of certainty to investors – in terms of total allowances allocated to industry in the medium run, future structure of the scheme, etc. – to avoid discouraging investments in Europe and to create a robust and reliable emissions trading scheme for industrial sources looking for the least cost solution to comply with CO2 emission objectives. The lack of visibility with respect to medium-term objectives post-2012 could become a problem as industry decides on the location of new and major production units, but also on the nature of its production processes.

An objective monitoring of the development of the EU ETS will be needed to assess the efficiency of this innovative, large-scale, market mechanism for long-term pollution control. This analysis sheds some light prior to the beginning of the EU ETS, not deemed to be a forecast, but rather to indicate static orders of magnitude of the economic effects of the scheme. It also calls for more work to discover how industry reacts to this new constraint.

INTRODUCTION

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The industry4 sector is an important direct and indirect source of greenhouse gas emissions, especially CO2, in IEA countries. CO2 emissions related to industry represents on average 15 per cent of total energy-related emissions of IEA countries (i.e. 1,705 MtCO2). The industry sector is also a highly heterogeneous sector that has seen both rapid increases and decreases in direct emissions from different sources over the last decade. Since 1990, the share of these emissions has decreased by over 7 per cent for the IEA as a whole, although, in countries such as Japan, industry emissions have grown by approximately 5 per cent since 1990.

On 22nd July 2003, the European Commission voted in favour of a Directive establishing an EU emissions trading scheme (ETS) in 2005 – as the centrepiece of its strategy to meet its Kyoto emissions commitment. Emissions trading is a market instrument and as such leaves it to economic actors to identify and implement the best possible technology or management solution to meet the identified the environmental goal. It sets a fixed cap on total emissions for covered installations, but provides flexibility on how to achieve it. With the creation of a market for emission allowances, emissions trading is meant to ensure that the emission reductions take place where the cost of the reduction is lowest thus decreasing the overall costs of combating climate change.

Under the Directive implementing the EU ETS, several sectors are explicitly mentioned as covered by an absolute emission cap (see Table 1 for other key features of the Directive). These are: the mineral industry (cement, glass and ceramic production), paper and pulp sector, the production and processing of ferrous metals and the power generation sector, which accounts for the vast majority of these sectors’ total emissions in Europe. The Directive also includes any installation with boilers over 20 MW which could cover installations in many other sectors (e.g. chemicals, food, etc.). Due to the diverse nature of these sectors, the case studies in this paper will focus on sectors covered by the Directive (i.e. steel, paper and pulp, and cement) and the effects of emissions trading on a sector not covered by the regime (i.e. aluminium5).

The study sheds light on the possible consequences of emissions trading for those industries, with particular focus on the energy consumption component in the industry. The objective of the study is to assess short to medium term first-order impacts on a sector’s competitiveness of the broader effects of emissions trading, including indirect impacts6. The study also seeks to assess the foundation for prevailing concerns about relocations to countries which do not cap their CO2 emissions. However, we do not provide estimates of potential carbon leakages, i.e. the increase in emissions outside the region that could offset emission reductions inside the EU.

An important element of our assessment is the possibility for industries to pass onto their prices the cost increases associated with emissions trading and thus the effects on exports and imports. The cost feed-through for industries will depend on elements such as the demand response, market concentration, and international exposure.

4 Industry includes power generation, iron and steel, manufacturing and construction, paper and pulp, chemical and petrochemical, non-ferrous metals and non-metallic minerals, textile and leather, food and tobacco, and wood products. 5 In this report, we do not look into the effects on energy supply and prices, other than electricity. 6 In addition to the industry sectors themselves, emissions trading and therefore a cap on CO2 is applied on fossil fuels used as inputs in electricity generation.

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Section 1 defines the scope of the study: the relevant level at which to assess competitiveness; the industries covered in the analysis; and the industries’ emissions. The section also offers brief descriptions of production processes of each industry, and of their global context.

Section 2 describes the source of emissions, electricity and energy use for each industry. It also explores direct and indirect impacts of the introduction of the cap on the industries’ marginal and average production costs depending on the level of CO2 prices and on whether the power producers pass their CO2 costs onto the wholesale market.

Section 3 assesses the impact on the industries competitiveness. Competitiveness does not only hinge on a firm’s profitability: it is a multi-faceted concept. This section provides insights on the impact of emissions trading from several angles: international, regional, and national competitiveness; and loss of a firm’s competitive position on the domestic and international markets (exports). It will not, however, cover the loss of an industry’s market share (e.g. product substitution). Section 4 considers the risk of emissions leakage based on existing modelling work. Section 5 presents potential problems and solutions as discussed in various European fora.

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Table 1: Key Features of the EU Emissions Trading Scheme

Source: Updated from OECD/IEA (2003); Directive 2003/87EC.

FEATURES DESCRIPTION/REQUIREMENTS

Type of target Absolute target, e.g. X tCO2e. One allowance in the EU-ETS allows the owner to emit one tonne of CO2e; its validity is limited to a specific period.

Allocation mode

During 2005-2007, mostly free allocation by Member states following common criteria Up to 5% auctioning allowed during 2005-2007 Up to 10% auctioning allowed for 2008-2012

Sectors included CO2 emissions from large combustion installations (>20MWth rated input) from all sectors (i.e. including power generation), plus emissions from oil refineries, coke ovens, and the iron and steel, cement, lime, glass, ceramics, and pulp & paper sectors (coverage of these sectors is subject to certain size criteria)

Coverage Initially CO2 only. After 2008, other gases may be included, provided adequate monitoring and reporting systems are available and provided there is no damage to environmental integrity or distortion to competition.

Banking Banking allowances from the first to the second trading period is at the discretion of each Member State. As of 2012 onwards, it is a provision in the directive.

New entrants Member States shall take into account the need to provide access to allowances for new entrants; how and how much is to be decided by each Member State.

Links with Kyoto units

The council of ministers and the European Parliament agreed (April 2004) on a text for the EU “Linking Directive” that will allow entities covered by the EU-ETS to use emission units from the Kyoto Protocol’s project-based mechanisms (i.e. Joint Implementation and the Clean Development Mechanism) towards meeting their emissions targets. The use of the mechanisms is to be “supplemental” to domestic action, in accordance with the relevant provisions of the Kyoto Protocol and the Marrakech Accords. The EU Directive does not include recognition of assigned amount units (i.e. governments’ overall emissions allocation under the Kyoto Protocol).

Links with other countries’ schemes

The Directive includes the possibility of linking with third Parties with Kyoto commitments and that have ratified the Kyoto Protocol, based on agreements that provide for the mutual recognition of allowances between the EU ETS and other domestic GHG trading schemes.

Penalties A non-compliance penalty tax of EUR40 per tonne of excess CO2

emissions in the first compliance period and of EUR100 in the second period, plus restoration of the GHG emitted without having surrendered allowances.

15

METHODOLOGY AND APPROACH

A full assessment of the emissions trading scheme would require comparing it to other policy options (a tax on emissions, command-and-control regulations, industry benchmarks), assuming an identical environmental goal, which we do not propose to do. Rather, we offer orders of magnitude of the cost effects of the Directive, based on sector-specific data collected from a range of industry and independent sources.

The industries’ cost assumptions should not be considered as illustrating a particular installation. In reality, details in plant economics will deviate from the average. The energy efficiency of installations can vary by +/- 50 per cent. Some of the effects described below would therefore be exacerbated for less efficient plants, and minimised for others.

A first order assessment on the cost and competitiveness implications of the EU-ETS is provided here. The findings on the costs of emissions trading may thus be over-estimated as several potentially important factors are not considered:

• Low-cost or negative cost emission mitigation potentials may exist, but not be exploited until a specific incentive is provided. The introduction of the carbon cap could help reveal such opportunities7;

• We do not reflect technological change that might occur as a result of a sector’s effort to minimise emissions. One of the stated goals of cap-and-trade instruments is indeed to trigger innovations and solutions that would not have been considered otherwise;

• Moreover, it may be that meeting CO2 objectives can lead to greater market opportunities for some industries, through new production processes.

These caveats are important to keep in mind in the interpretation of results, because they are based on the assumption that all other factors are unchanged. This is reasonable for short term and low CO2 permit prices. For long term (post 2015) and/or high permit prices (EUR 25/tCO2 and higher), the analysis could lose part of its validity.

Likewise, competitiveness is a complex notion. It depends on a number of factors including the cost of inputs, market prices, a firm’s product quality, all of which eventually determine its market share. The ability to maintain low production costs also depends on factors such as skills of the labour force, future expectations of industry concerning competitive conditions, technological innovations, etc. In this analysis, these other factors were held constant in an effort to focus on the implications for costs. Loss of competitiveness is defined in this paper as the loss in output – including reduction in demand and/or the potential displacement of production from one country to another.

7 “Counterintuitively, BP found that it was able to reach its initial target of reducing emissions by 10 percent below its 1990 levels without cost. Indeed, the company added around USD 650 million of shareholder value, because the bulk of the reductions came from the elimination of leaks and waste” (John Browne, “Beyond Kyoto”, Foreign Affairs, July/August 2004.)

16

The study does not rely on the actual national allocation plans (i.e. the table describing the quantity of allocated allowances on a plant by plant basis); rather, we rely on an aggregate description of the key sectors’ technologies and products. It also does not address the possibility of intra-EU relocation as a consequence of different allocation schemes in different countries.

The following methodology is used to assess the effect of the emissions trading directive on industry’s costs:

1. We define the direct cost of emissions trading as the sum of abatement cost and allowance cost. For illustrative purposes, we first assume that this overall cost increase applies only to production whose emissions is not initially covered by the allocation – referred to as “marginal production.”

A

P

A: Internal abatement costs

P: Purchased allowances

Cap

2 or 10% of emission reductions

2. A full-blown abatement cost analysis is beyond our scope. It would, in particular, require estimating actual abatement costs for specific industries, while data is not readily available for such analysis. We offer upper bounds, based on two different allocation scenarios, in which industry would be allocated allowances covering either 98 or 90 percent of its emission level for the commitment period (see above), had they not been subject to a CO2 constraint. In reality, companies are bound to implement mitigation options in their installations up to the point where these cost as much as the market price of CO2. In our estimates, we cost such abatement at the full carbon price. The following figure gives an indication as to why this method leads to an overestimate. The total direct cost of complying with the imposed cap is to first reduce emissions, incurring cost shown by area 1, and to acquire allowances at the market price, with a cost shown by area 3. In our estimate however, we also add area 2, to avoid making assumptions about the share of reductions achieved internally and the quantity of allowances purchased from the market. In addition, our estimates are also upper bounds because we do not cover situations of companies or sectors that would sell allowances. Rather, in all cases presented below, companies purchase allowances to achieve compliance.

Purchased allowances

A PEmission Reductions

/tCO2 2 or 10 % emission reductions

1

2

3

17

3. The indirect cost of emissions trading – the increase in input prices caused by a cap on another sector’s emissions – is also included, focusing exclusively on the potential increase in electricity price. The total cost of emissions trading in this study is the sum of the direct and indirect costs, as estimated above.

4. Last, effects on either profits or product prices are estimated, assuming that industry would seek to transfer this increase in cost by means of an average pricing strategy8. Alternatively, industry could decide to reflect the full opportunity cost of holding allowances, i.e. charging carbon cost as if an equivalent carbon tax were in place.

1. ENERGY-INTENSIVE USERS UNDER THE EU ETS

1.1. COMPETITIVENESS AND EMISSIONS: DEFINITION AND SCOPE

1.1.1. COMPETITIVENESS: DEFINITION AND SCOPE

Competitiveness can be evaluated at different levels – national, industrial, or firm – as well as domestically, regionally, and internationally. As both national and industry comparisons are based on aggregate measures, the clearest analytical way to look at competitiveness is at the firm level9. Many factors affect competitiveness. The relevant definition of competitiveness in this study is the firm’s ability to maintain and/or expand market position based on its cost structure. Loss of competitiveness thus can be caused by a relative increase in a firm’s costs compared with its competitors. Loss of competitiveness is defined in this paper as the loss of output.

From an international perspective, competitiveness concerns arise if the additional costs incurred by the affected industries are not shared by all trade partners. This loss in competitiveness could translate into a decline in net exports and the relocation of these industries, with a negative impact on industrial value added and employment, but also on environmental benefits, as “domestic” reductions could be partly offset by an increase in emissions outside the region – the so-called emission “leakage”.

A full assessment of these mechanisms at the level of a specific industry requires integrating a broad range of mechanisms:

• The industry’s ability to reduce CO2 emissions at low cost;

• The impact on this industry’s current cost structure and profitability margins;

• The industry’s exposure to international markets (i.e. exports and imports, freight prices);

• The possibility to increase product prices, with full account taken of the competitive nature of the market, partly reflected in the price elasticity for the product at stake.

8 Carbon Trust (2004). 9 Baron, Econ, 1997. See Krugman (1994) for why competitiveness may be a misleading notion when used to evaluate countries performance.

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International industrial competitiveness is generally viewed as an industry’s ability to export its goods, with industry being defined as a group of firms that produces similar goods. However, an industry is often very heterogeneous in what it produces, in how it produces it, and to whom it sells. In some industries, such as in the steel sector, the means of production are entirely different depending on the location and the raw materials used. The cost functions vary greatly among regions, as different regions and countries have, for example, different labour and input costs, different fiscal regimes and associated investment risks. Furthermore, the market can be segregated, as in the case of cement, where the cost of transportation reduces the scope for international trade. The result of such heterogeneity is that the impact of an emissions trading system is likely to vary among firms within the same industry.

In this study, to illustrate the impact of emissions trading on an industry’s competitiveness, conclusions are extended from the impact on an “average” firm to the entire industry, including elements such as the extent of international trade in the industry, etc.

Maintaining everything else equal (technology, non-energy related costs, other taxes), the change in competitiveness will be determined by differences in total costs, the firm’s ability to minimise the cost impact from the price of emission allowances by investing in energy efficient options, and changes in trade patterns at a regional or international level. To the degree that the new carbon cost reduces profitability – a risk most acute for firms subject to competition from outside the scheme – the firm’s return on investment declines, thereby encouraging a shift of investment in less emission-intensive activities or in the same activity in other locations where the carbon constraint does not exist. While the first effect is, to some extent, an intended outcome of the emission constraint, the other could undermine the environmental effectiveness of efforts to cap emissions.

1.1.2. INDUSTRIES COVERED

In the industrial sector, energy intensive industries such as cement, steel, pulp and paper and oil refining are the main sources of greenhouse gas emissions after power generation (IEA, 2003). Under the EU-ETS, their carbon emissions will need to be covered by allowances. The existence of this environmental constraint will trigger a reallocation of cost towards emission abatement or the purchase of allowances, a net cost for the industry.

The selected industries in this report are: cement; iron and steel; pulp and paper; and aluminium. These industries’ products are largely traded at the international level and could suffer from their carbon-constrained position in Europe. Secondly, if energy prices – and especially power prices – increase as an outcome of emissions trading, they could also trigger a decrease in demand for electricity-intensive industrial products such as aluminium, while the power sector could substantially increase revenues. This justifies including aluminium, recognising that it is not in the perimeter of the EU directive, except for combustion installations owned by the industry.

1.1.2.1. CEMENT

Cement production is a highly energy-intensive activity, estimated to amount to 2 percent of global primary energy consumption10. The cement industry contributes to about 3 per cent of the total anthropogenic emissions of energy-related CO2 in the European Union. Manufacturing one tonne of

10 World Energy Council, 1995, Efficiency Use of Energy Utilising High Technology: An Assessment of Energy Use in Industry and Buildings, London.

19

cement releases approximately 0.6-0.9 tCO2, depending on the process used as well as the share of additives. The cement industry is a major source of CO2 emissions because of its dominant use of carbon-intensive fuels, such as coal in clinker making. Besides energy consumption, the clinker-making process emits CO2 from the calcinating process as well. Figure 1 illustrates the main production process for cement making.

Figure 1: Process Steps in Cement Manufacture

Cement

Raw materials

preparation: grinding, homogenising ,

drying or slurrying

Pyro -processing:

pre-heating, calcinationclinkering , cooling

Cementgrinding:grinding,blending

Bagging &transport

Additive

preparation:crushing,

dryingFuelsPreparation:crushing, grinding

drying

Raw material supply

quarrying, mining, crushing

Clinker production

Clinker

nodules

Additives

Source: Ellis, 2001 ; Ruth et. Al., 2000.

Due to the importance of cement as a construction material, and the geographic abundance of the raw materials, i.e. limestone, cement is produced in virtually all countries (see Figure 2). This is also explained by the low product price and the relatively high cost of transporting it inland. The transport cost, for long distances may even exceed the product price. Bulk shipping is changing that, and it is often cheaper to cross the Atlantic Ocean with 35,000 tonnes of cargo than to truck it 300 km. In large countries transportation costs normally cluster the markets into regional areas, with the exception of a few long-distance transfers (e.g. where sea terminal facilities exist). In all, international trade in cement is limited, when compared to global output (IEA GHG R&D, 1999).

Figure 2: 2003 World Cement Production by Region

Source: Cembureau Activity Report 2003.

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China is the largest cement market in the world, consuming an estimated 640Mt in 2002 – nearly six times that of the second-largest market, the US (ABN AMRO, 2003). As considerable as this may sound, China is still a relatively minor market from the perspective of the European cement majors (HeidelbergCement, Holcim and Lafarge). For many European companies, the US is in fact their single largest cement market. It is also the largest import market for cement in the world and as such is crucial from a global trading perspective. Foreign access in China is limited by tight governmental restrictions on foreign investment, such that overseas participation is restricted to joint ventures with local firms. The world cement industry is, thus, a highly fragmented market.

Although produced from raw materials which vary from plant to plant, cement can be considered a standard product – there are only a few classes of cement and there is some substitutability between classes. Therefore, the price is the most important sales parameter next to customer service. Quality premiums exist but are rather limited.

1.1.2.2. STEEL

Today there are two steel-making processes that account for nearly all the world’s steel production: the integrated route (blast furnace) and the electric arc furnace (EAF) route:

• The integrated route11 is the most capital intensive and involves the production of liquid iron from iron ore, coke and limestone. The liquid iron is subsequently transformed into steel in an oxygen converter – a Basic Oxygen Furnace (BOF process). This process is called the primary route;

• The EAF mini-mills12 where steel is produced from recycled scrap13 and reduced iron substitutes in an Electric Arc Furnace (EAF process). This process is called the secondary route.

In the BOF process, scrap is added as a raw material at the BOF stage to reduce CO2 emissions. The share of scrap or scrap substitutes (i.e. directly reduced iron) varies between 10 and 25 per cent. The liquid steel coming out of the BOF is continuously cast into semi-finished products (slabs, blooms or billets) which are further rolled into the various steel products. Steel production through the traditional blast furnace route is very capital intensive. The minimum economic scale is high, and the investments in this sector are very specific. As a result, there are very high entry barriers. Vertical integration is, with few exceptions, the rule. Many producers control an important part of the raw material production chain and most are integrated downstream into steel distribution and first transformation products such as sheets, panels, profiles and tubes, and steel distribution.

The EAF route has several advantages over the integrated route. The main advantage is its flexibility in production rates depending on demand and their ability to be designed to make specific product qualities for particular end markets. As they are usually small units, supplied by scrap, they can be located near the end-user markets. In contrast, integrated steel plants are generally located away from end-user markets, near large port or rail facilities due to their large raw material

11 It has a market share of 60 per cent in EU15 (Eurofer). 12 It has a market share of 40 per cent in EU15 (Eurofer). 13 Other feed used in the EAF process includes direct reduced iron and pig iron. These scrap substitutes are mainly used in the production of higher quality flat products where they account for around 35 % of metallic inputs.

21

requirements. Furthermore, the cost of capital of a minimill can be as low as half that of an integrated plant (Crampton, 2001) per tonne of steel.

Today, EAF technology is primarily used to produce lower quality long products such as those in the construction industry. These plants have largely been unable to produce high quality flat products, due partly to technology limitations and partly to limited availability of scrap with low enough residual impurities. Recent advances in casting technology and the availability of low residual scrap alternatives, however, have enabled some minimill producers to expand their product range into higher quality steel products suitable for flat applications.

China has been the key growth driver for the global steel industry in the past four years. Input prices (iron ore, etc.) have reached record-highs due to strong Chinese steel imports. What happens in China has repercussions on steel making worldwide. It is the world’s largest single steel producer and consumer, accounting for almost 25 per cent of the world’s crude steel output and even more of total finished steel consumption in 2003. According to Eurofer (2004), the dependence of world markets on developments in China should be a source of concern: freight capacity is being saturated at present. In the future, there is also the possibility that once China satisfies its domestic demand, its exports would swamp the international market.

Figure 3: Steel Prices for Hot Rolled Coil (HRC)

Prices of HRC steel (US$/Mt)

0

100

200

300

400

500

600

01-01-00

01-01-01

01-01-02

01-01-03

01-01-04

Xports from Brussels

Imports to China

Xports from China

Xports from Brazil

Imports to US

Source: Datastream.

1.1.2.3. PULP AND PAPER

Overall, Europe represents a quarter of world paper production and consumption (CEPI). In Europe, the paper industry produces per year 90 million tonnes of paper and board; and 40 million tonnes of pulp. Per annum, the industry uses 145 Mt of wood; and 41 Mt of recycled paper.

The European pulp and paper industry is characterised by a large variety of raw materials, products and manufacturing routes. The paper industry is a capital-intensive industry in a strong competitive international market. It also faces competition from alternative materials such as plastics in the packaging sector and alternative media in communication (CPI, 2000).

In 25 years, the number of paper machines in Europe has been reduced by about 60 per cent while the total capacity has almost doubled (CEPI). Many companies have grown by investing in new

22

capacity but also by consolidating a large number of relatively small paper and board mills. Thus, the European paper industry comprises a relatively small number of very large multi-national groups at one end of the scale, yet a large number of small businesses at the other.

The pulp and paper industry is frequently subject to extreme price variations. The price variations are not the same, however, for all pulp and paper products. The closer a company is to the ultimate consumer, the smaller the price fluctuations of the product. For example, the price of pulp is much more volatile than that of tissue paper. Moreover, waste paper is an internationally-traded commodity and is also subject to wide fluctuations in price. Prices of virgin pulp affect the price that mills will pay for recovered paper and the additional costs of sorting and transporting waste paper can cause paper recycling to become uneconomic (CEPI).

Approximately, 72 per cent of the pulp produced around the world is chemical as opposed to mechanical. In this study, only the so-called chemical forest industry is dealt with because its CO2 emissions are dominant, compared to those from the wood product industry. It includes the production of chemical and mechanical pulp, as well as the making of paper and paperboard. It uses mechanical pulp, based on mechanical treatment of wood; chemical pulp, a process relying on high temperature and pressure; and recycled pulp.

Recycled paper is an ideal raw material for certain products. However, it sometimes contains impurities (plastics, metals, printing ink, etc.) which can be avoided when fresh wood is used. The yield of recovered paper is normally between 55 and 90 per cent, depending on the different quality demands of the paper and board that is produced (Rein, 2002). Recovered paper has become an indispensable raw material for the paper manufacturing industry. The share of recovered paper out of the total raw material consumption of the European paper industry is 42 per cent; virgin pulp represents 43 per cent; the rest being mainly non-fibrous materials like minerals. Recovered paper has its own market price. Paper mills producing virgin fibres, nevertheless, continue to be required since paper cannot be recycled indefinitely (about 5 to 7 per cent) and the system needs a constant flow of fresh fibres to operate.

1.1.2.4. ALUMINIUM

Although the aluminium industry is not covered by the EU-ETS Directive, the implementation of the EU ETS may have heavy consequences on the industry’s costs as a result of electricity price increases – we turn to this issue in section 2.

There are two main production routes for aluminium production, illustrated in Figure 6. The major energy consuming process in aluminium production is the Hall-Heroult process for electrolysis of primary aluminium. The second is based on the remelting of aluminium scrap. The production of primary aluminium is very electricity-intensive. The energy requirements for refining aluminium scrap is only 5-10 per cent of that of the primary production process (Gielen and van Dril, 1997).

Figure 4: Aluminium Making Process

23

Source: EU-SAVE Project, 2002.

Four main processes can be distinguished in the primary aluminium production process14,15.

• Extraction of alumina (Al2O3) from Bauxite ore. In this phase, the energy use is approximately 25 GJ/tonne of aluminium;

• Anode production consumed in the Hall Héroult16 process for primary aluminium melting at a rate of about 1.5 tCO2/tonne aluminium. The baking of the anodes consumes 2.3 GJ/tonne of aluminium;

• Primary electrolysis and smelting of alumina into aluminium. Primary aluminium is obtained from alumina by the Hall-Héroult electrolytic smelting process. Oxygen and the anode carbon react to produce CO2. The aluminium liquid metal is poured into ingots;

• Semi-fabrication of aluminium and aluminium alloy products by rolling, extrusion, etc. (Gielen and van Dril, 1997).

Competition in the aluminium production takes place in the international arena where companies, not countries, are the main actors. Since aluminium is a relatively expensive metal to produce as a result of its high electricity consumption, aluminium smelters are concentrated in locations with access to cheap energy, such as hydroelectricity. But costs are inflated for many aluminium companies by the fact that the raw materials – bauxite and alumina- are found several thousand miles away from where their smelters are situated, adding the expense of long-distance shipping. Smelting capacity is being expanded in several areas of the world, from Russia to the Middle East and Africa (Financial Times, 5/11/2003).

14 The overall chemical reaction can be written as: 2 Al2O3 + 3 C 4 Al +3 CO2. 15 On average, between 4 and 5 tonnes of bauxite are needed for 2 tonnes of alumina, from which 1 tonne of aluminium can be produced. 16 The basis for all modern primary aluminium smelting plants is still the Hall-Héroult Process, invented in 1886. Alumina is dissolved in an electrolytic bath of molten cryolite (sodium aluminium fluoride) within a large carbon or graphite lined steel container known as a "pot". An electric current is passed through the electrolyte at low voltage, but very high current, typically 150,000 amperes. The electric current flows between a carbon anode (positive), made of petroleum coke and pitch, and a cathode (negative), formed by the thick carbon or graphite lining of the pot. Molten aluminium is deposited at the bottom of the pot and is siphoned off periodically, taken to a holding furnace, often but not always blended to an alloy specification, cleaned and then generally cast. A typical aluminium smelter consists of around 300 pots. These will produce some 125,000 tonnes of aluminium annually. However, some of the latest generation of smelters are in the 350-400,000 tonne range. http://www.world-aluminium.org/production/smelting/index.html

Alumina production:

Bayer process

Anode baking

Primary aluminium: Hall-Heroult

Selection recycling rate

Secondary aluminiumCollection and

l i

Primary aluminium

Secondary aluminium

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1.1.3. DEFINING INDUSTRIAL EMISSIONS

1.1.3.1. Process and Energy-Related

Industry’s direct emissions can be divided in two distinct categories: process emissions and energy-related emissions. Energy-related emissions are greenhouse gas emissions (CO2 mostly) from fossil-fuel combustion. Process emissions are not generated by fuel combustion, but as a result of chemical reactions in defined as non-energy related emissions and are emitted during the production process of a product.

Cement manufacture in particular releases important quantities of process emissions: when calcium carbonate is heated (calcined) in a kiln, it is converted to lime and carbon dioxide, the latter being emitted to the atmosphere. There are numerous other industrial processes in which carbonate minerals are used in ways that release carbon dioxide into the atmosphere, including the use of limestone in flue gas desulphurisation and the manufacture and some uses of soda ash.

1.1.3.2. Direct and Indirect

Under an emissions trading scheme, another distinction is essential in setting the boundaries of a facility’s total emissions. Emission allowances are allocated on the basis of an installation’s direct, on-site, emissions whether process or combustion-related. This leaves out emissions associated to the production of an industry’s inputs – the most obvious being electricity – and transportation emissions related to the industry’s activity. We refer to the former as indirect emissions.

As a result of these indirect emissions, consuming industries will see an increase in the cost of one of their inputs. Emissions arising from the consumption of electricity purchased from the grid are an example of indirect emissions. Under the EU-ETS, the power generators will be allocated allowances on the basis of their direct emissions – the cost of which is fed through to industrial and other consumers, introducing an additional cost related to the constraint on emissions.

1.2. THE WEIGHT OF INDUSTRY’S CO2 EMISSIONS IN EUROPE

Emissions of CO2 from the industrial sector17 are a significant proportion of emissions in Annex I countries18. In 2001, industry accounted for approximately 15 per cent or 2081 Mt CO2 of the group’s direct CO2 emissions from fuel combustion and a similar proportion, although indirectly, from emissions associated with industry use of electricity (IEA, 2004).

Industry also generates process-related emissions of CO2 as well as fluorinated gases. The United Nations Framework Convention on Climate Change UNFCCC19 assessed that they represent between 3-8 per cent of total Annex I countries’ emissions and that their weight depends on individual industry sectors. In the cement, iron and steel industries and in the aluminium industry, those emissions represent an important share of the industries’ total emissions. They can also be

17 Manufacturing and construction only. 18 Defined in the International Climate Change Convention as those countries taking on emissions reduction obligations: Australia, Austria, Belgium, Bulgaria, Canada, Croatia, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Japan, Latvia, Liechtenstein, Lithuania, Luxembourg, Monaco, Netherlands, New Zealand, Norway, Poland, Portugal, Romania, Russian Federation, Slovakia, Slovenia, Spain, Sweden, Switzerland, Ukraine, United Kingdom, USA. 19 The UNFCCC is an international environmental treaty (1992) aimed at reducing emissions of greenhouse gas, pursuant to its supporters' belief in the global warming hypothesis.

25

particularly important in countries with low carbon-intensive electricity production such as France, where process-related emissions accounted for 23 per cent of emissions in 2000 (OECD/IEA, 2003).

Table 2: Energy use in the EU-15 industry20

SECTOR FINAL ENERGY USE (MTOE)

FINAL ENERGY USE (MTOE)

1990 2000 TOTAL INDUSTRY 266.01 271.68 Iron and Steel 56.04 51.49 Glass, pottery and building materials (cement included)

35.65 34.88

Chemicals 50.59 45.33 Food, drink and tobacco 22.02 25.02 Engineering and other metals 27.35 24.51 Paper and printing 17.99 31.12 Textile, leather and clothing 8.75 8.45 Non-ferrous metals 10.83 10.44 Ore extraction 2.99 2.68 Other industries 20.64 34.96

Source: Eurostat.

Focusing on the EU-15,

20 Under the United Nations’ Statistic division, aluminium belong to division SITC 68 “Non-ferrous metals”; paper, paperboard and articles of paper pulp SITC division 64 “Other semi-manufactures”; cement SITC 66 “Other semi-manufactures”.

26

Table 3 indicates that the iron and steel industries accounted for 21 per cent of final energy consumption and 27 per cent of emissions in the total manufacturing sector in 1990. Almost the same shares are observed in the year 2000 (19 per cent and 28 per cent respectively).

27

Table 3: CO2 emissions in the EU-15 and EU-25 industry

Source: IEA.

In Europe 25, the iron and steel direct CO2 emissions amount to 23 per cent of emissions covered by the trading Directive. Comparatively, the electricity industry amounts to approximately 66 per cent of covered emissions. The CO2 emissions associated with iron and steel production differ across countries and regions (Maestad, 2003), but it is in all cases a very CO2 intensive activity. Approximately 75 per cent of the global CO2 emissions from steel production are related to the use of coke and coal in iron making. Other notable emission sources are the use of electric power for scrap melting (indirect emissions) and the use of natural gas in the production of directly reduced iron.

In 2002, the pulp and paper sector represented 5 per cent of European CO2 emissions. CO2 emissions from non-integrated paper mills result primarily from energy generation rather than the papermaking process itself as will be described further in this paper. Its share is relatively low compared to other sectors since market pulp and paper mills are established mostly in European countries with low carbon-intensive electricity generation.

Data on CO2 emissions from cement and aluminium is more difficult to find for earlier years – generally included in larger categories. In 2002, the cement’s share of CO2 emissions – included in non-metallic minerals - represented 15 per cent of total EU15 emissions. In 2002, aluminium-related CO2 emissions represented only 2 per cent of EU-25’s total CO2 emissions21.

2. POTENTIAL IMPACT OF EMISSIONS TRADING ON INDUSTRIES UNDER THE EU CAP-AND-TRADE REGIME

Under the EU-ETS, all installations covered by the scheme will need to surrender allowances for every tonne of CO2 emitted during each year. The Directive stipulates that the majority of allowances will be allocated freely and a portion will be auctioned (i.e. up to 5 per cent auctioned during 2005-2007 and up to 10 per cent during 2008-2012).

21 Aluminium also emits PFCs not covered under current EU-ETS which focuses on CO2, but may be included later.

MT CO2 NON-

FERROUS

METALS

NON-METALLIC

MINERALS

PAPER

PULP AND

PRINT

INTEGRATED

IRON &

STEEL

OTHER

INDUSTRIAL

ACTIVITIES

TOTAL

INDUSTRY

1990 EU15 13,162 93,896 31,019 160,433 336,785 635,295 2% 15% 5% 25% 53% 100% 1990 EU25 Nd Nd Nd Nd Nd Nd

2002 EU15 11,722 84,471 30,764 118,901 315,833 561,692 2% 15% 5% 21% 56% 100% 2002 EU25 13,865 97,882 34,150 148,527 360,970 655,394 2% 15% 5% 23% 55% 100%

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As a first order impact, the EU-ETS directly increases the production costs for any output that leads to emissions that are not covered by the initial allocation: the installation will need to acquire allowances corresponding to these emissions. Installations are also likely to take abatement measures, which are not treated explicitly in the present study, for lack of certain information on allocation levels, the price of CO2 and the abatement potential for all covered industries, with the corresponding cost per avoided tonne of CO2. Furthermore, these industries – who also consume significant amounts of electricity – would also bear increases in their power costs as a consequence of the cap on power generator’s emissions (the so-called indirect costs). In this section, the cost structure for each industry is described, highlighting the share of energy combustion and electricity in total costs.

The CO2 emissions are detailed and classified according to direct emissions – energy combustion and electricity generated by each plant – and indirect emissions related to purchased electricity.

2.1. ASSUMPTIONS ON THE INDUSTRIES COVERED IN THE STUDY

At the level of an individual firm, competitiveness is primarily a matter of being able to produce goods that are either cheaper or better than those of other firms22. Ultimately, business competitiveness is a matter of relative performance. The impact of environmental regulation, whether in the form of conventional “command-and-control” measures or market mechanisms, may be complex, and may well vary between firms. It is important to recognise that although pollution control requirements will generally increase business costs, some firms may be affected significantly more than others, and it is likely that some firms would benefit (in terms of profitability) from environmental regulation (e.g. rewarding companies that have already invested in lower emitting technologies or opening new markets). The following sections indicate the assumptions taken for steel, cement, paper, and aluminium plants.

2.1.1. STEEL

For the steel plant scenarios, assumptions are made for the two process routes to mirror the European situation. They imply significant differences in terms of fuel consumption, CO2 emissions, sale prices and profitability ratios. The ranges in energy use to produce steel for a given technology type are influenced by the quality of the fuel and iron/scrap inputs, but also by variations in the relative proportion of fuel input used.

The primary route (basic oxygen furnace)

The blast furnace cost structure differs significantly depending on the location of the installations.

22 In this report, since the products traded are either commodities or standard products, the quality factor is ignored – although in practice it may very well have an impact.

29

Table 4 highlights the cost breakdown for a reference23 integrated steel plant in Western Europe in terms of share of labour costs, importance of raw materials, and the share of electricity.

23 Note that this steel plant is not a benchmark for European steel plants.

30

Table 4: Cost Breakdown for a Western BOF Plant24

WESTERN PLANT % OF TOTAL COSTS

Fixed costs Depreciation 12% Labor 15% Maintenance 4% Other overhead 3% Variable costs Raw materials 56% Combustibles 5% Electricity 4%

Source: CECS, WSD, Arcelor.

Figure 5: Steel Export Prices from Brussels 2003-06/2004

MB - Steel,Brus. Hot Coil $/Mt

250300350400450500550

Jan-

03

Mar

-03

May

-03

Jul-0

3

Sep

-03

Nov

-03

Jan-

04

Mar

-04

May

-04

Source: Datastream; Metal Bulletin

For the Western plant scenario (Table 4: Cost Breakdown for a Western BOF Plant), an annual capacity of 4 million tonnes of steel is assumed, operating at 90 per cent of its capacity25. The rate is higher than that of the EAF plant (see next section) as flexibility in the production pattern is lower. The market price is estimated by using the price for Brussels exports. An average HRC price over 2003 –Figure 5– was applied – totalling USD313 per tonne of steel. The 2004 prices were not considered as they are significantly higher because of increasing Chinese demand – a situation that may not reflect the future trends (see Section 3.3.1 for further discussion). Using data from CECS, the profitability of a Western European plant reaches 14.5 per cent for total costs equalling 268USD/tonne of steel.

24 See Annex 1 for information on a typical Eastern Europe integrated mill. 25 This can reach up to 97 per cent.

31

Table 5 Cost Assumptions for a Western BOF (Greenfield Project)

Source: CECS

In contrast, the profitability level in 2003 of a steel plant located in Eastern Europe reaches about 29 per cent (Annex 2), with a total cost of USD199 per tonne of HRC steel. The reason for this difference lies in lower costs of raw materials, labour, energy, and electricity.

Regarding the carbon dioxide emissions in the BOF process, the majority of CO2 emissions come from pig iron production in the blast furnace, and from coal coking. Coke is used as a chemical reducer, as well as a source of energy. Coke28 is produced in coke batteries, where special qualities of coal are heated in the absence of air. The coke making process produces a large amount of coke oven gas29, which is used as a fuel in other segments of the process or recovered in power stations. The blast furnace, where iron ore is reduced to pig iron, emits blast furnace gases which are also used as a

26 These costs are ‘out of the plant costs’ and do not include certain costs e.g. general overhead, marketing, etc. 27 Earnings before interest, tax and amortisation. In other words, revenues minus costs of revenues, personnel costs, depreciation and other operating costs. 28 The emission factor for coke reaches 0.105tCO2/GJ, compared to coal for which the rate is 0.095. 29 The carbon dioxide emission rate for coke oven gas is 0.044tCO2/GJ.

Capacity 4 Mtonnes Fixed asset cost 650 USD per tonne Variables Price 313 USD/tonne Capacity utilization 90% Revenue Volume 3.6 Mt Price 313.0 USD/t Total revenue 1126.80 $M Fixed costs Depreciation 32.5 USD/t Labor 41.4 USD/t Maintenance 11.5 USD/t Other overhead 6.90 USD/t Variable costs Raw materials 150.0 USD/t Combustibles 13.80 USD/t Electricity 11.50 USD/t Total costs26 268 USD/t Total costs 963 $M Profit Turnover 1126.80 $M operating income 163.44 $M Operating profit EBITA27 14.5%

32

fuel in a power generation facility. Integrated steel mills may30 generate therefore most of their electricity use (Figure 6) and purchase the remainder from the local power grid. The rate of gases which are sold to an external power. Nevertheless, as shown below, the CO2 emissions rates are much lower in the Western steel plant may vary from 0 per cent (autarky) up to approximately 60 per cent (fully externalised power plant). In terms of calculations for GHG emissions, it will have a direct impact on CO2 direct emissions. In contrast, the secondary route emits a limited amount of GHG (below) and uses electricity – accounted as indirect emissions.

Figure 6: Gases Emitted31 and Recycled in an Integrated Steel Plant

Source: Arcelor, 1999

For an integrated steel plant, our analysis assumes that the gases emitted in the coke oven and the blast furnace are fully recycled. They are recovered either in the processes – Facility B – or in a power plant at a 62 per cent rate – Facility A.

Table 6: Representative integrated steel plants in Europe

FACILITY A

FACILITY B

Blast Furnace

Coke rate tCO2/t pig 324 321 Coal rate tCO2/t pig 165 163 Merchant sinter

tCO2/t pig 1.718 1.533

Sinter plant

Coke rate tCO2/t sinter 54 30 Coal rate tCO2/t sinter 0 17 Limestone tCO2/t sinter 100 130

BOF shop Hot metal rate tCO2/t crude steel 893 1,018

BF gas utilisation

Coke plant 0% 23% BF plant 28% 33% Other shops 5% 7% Owned boilers 4% 36% Sales 62% 0%

Electricity purchase kWh/t crude steel 374 116

30 Coke gas and/or blast furnace gas can be burned in a power generation facility inside or outside the steel plant’s perimeter. 31 Gases can also be exported and coke can be purchased.

Coke plant

Hot blast stoves

Power plant

Flares

Sinter plant

Blast furnace

Steel shop

Hot strip mill

33

Source: Arcelor The average numbers, however, describe a fictive plant.

An integrated steel plant requires approximately 374kWh/tonne of crude steel according to data from Arcelor. In the case where the steel plant has fully externalised its electricity – Facility A – this amount of electricity is purchased. However, for the steel plant which owns its generation facility – B – approximately 116kWh/tonne of crude steel32 still need to be purchased from the grid. The rest of its power needs are satisfied by its own combustion33. The carbon factor of purchased electricity from the grid is given by 2001 IEA data – by dividing the total emissions from the electricity sector by the number of TWh produced the same year in EU-15.

Table 7: CO2 Emissions from Electricity in a Western Integrated Plant

Table 7 gives the total amount of CO2 per tonne of steel for each type of facility. If we take the case of Facility A which sells 62 per cent of its blast furnace gases to the power plant, this equals a transfer of emissions equal to 0.81tCO2/tonne of steel. However, whether or not the steel plant receives the corresponding allowances depends on the allocation methodology of each country (see Section 5 for further details and discussion). In Europe, only the German national allocation plan indicates that the process-related component of CO2 emissions is in each case attributed to the end user of the blast furnace gas – to the power producer in case A.

Table 8: Total CO2 emissions from a Western BOF plant

FACILITY

A FACILITY

B

DIRECT CO2 EMISSIONS 1.93 1.93 CO2 EMISSIONS FROM PURCHASED

ELECTRICITY 0.144 0.045

TOTAL TCO2/T OF STEEL 2.074 1.975 TOTAL DIRECT CO2 EMISSIONS COVERED / T

OF STEEL34

1.93 1.93

Source: Eurofer, WBCSD/WRI.

Overall, in a typical Western steel plant, emissions reach about 1.93tCO2/tonne of steel. In comparison, an existing steel plant located in Eastern Europe is often less efficient and therefore needs more combustibles than technologies which are available in Western Europe. Between Eastern and Western Europe, differences are mainly due to the diversity of processes, their efficiency, fuel input, and the penetration of new technologies.

32 The emissions corresponding to the purchase of power are accounted as indirect emissions. 33 This aspect is key in the total amount of CO2 emitted by an integrated plant. 34 Excluding Germany for which Facility A would only be accounted for 1.09 tCO2/t of steel =1.93- (62%*1.356).

MWH/TSTEEL TCO2/MWH TCO2/TFacility A 0.374 0.3853 0.144Facility B 0.116 0.3853 0.045

34

The secondary route (electric arc furnace)

Table 9 shows the cost breakdown of an illustrative Electric Arc Furnace (EAF) plant. The largest single component of the total costs is raw materials. In an EAF, scrap is melted in an electric arc furnace to produce directly crude steel. Raw materials that have been increasingly used as scrap substitutes include direct reduced iron (DRI) whose process implies producing significant amounts of CO2

35. The use of these alternative raw materials, however, require more electrical power than using scrap alone which affects the competitiveness of this process. In contrast with the blast furnace route, the secondary route is more variable intensive.

Table 9: Cost Breakdown for an Electric Arc Furnace Plant

% OF TOTAL COSTS

Fixed costs Depreciation 4% Labor 1% Maintenance 10% Other 13% Variable costs Raw materials 62% Combustibles 2% Electricity 8% Total 100%

Figure 7: Steel Export Prices from Eastern Europe 2003-06/2004

MB - Steel,Brus. Wire Rods $/Mt

250

300

350

400

450

500

03-0

1-03

03-0

3-03

03-0

5-03

03-0

7-03

03-0

9-03

03-1

1-03

03-0

1-04

03-0

3-04

03-0

5-04

Source: Datastream.

35 In the EAF plant assumptions, we will, however, consider that the plant is 100 per cent supplied with scrap.

35

Table 10: Cost assumptions for an EAF plant

Source: CECS 2004, IEA, Datastream.

Electric arc furnace plants vary greatly in size from 50 to 400 tonne capacity with the majority having a 70-120 tonne capacity. We consider that our representative EAF plant (Table 10) has a capacity of 120 tonne capacity and is able to produce 1 million tonnes, operating at 85 per cent capacity. The cost of asset is USD200 per tonne of produced steel (CECS).

The price for steel products from EAF plants is estimated by using an average of wire rod prices exported from Brussels in 2003 (Figure 7) – sold approximately USD312/t. 2004 figures were not used here as they are not representative of “normal” steel market conditions.

The total costs for one tonne of steel reaches 226USD. This confers the plant an earnings before interests, taxes and amortization of 14.8 per cent. This is much lower than for an integrated plant,

36 These costs are ‘out of the plant costs’ and do not include certain costs e.g. general overhead, marketing, etc.

Plant breakdown Capacity 1 Mtonnes Asset cost 200 USD per tonne Variables Price 312 USD/tonne Capacity utilisation 85% Revenue Volume 0.85 t Price 311.8 USD/t Total revenue 265 $M Fixed costs Depreciation 10.00 USD/t Labor 3 USD/t Maintenance 21.6 USD/t Other and overhead 29.70 USD/t Variable costs Raw materials (2003 average) 140.25 USD/t Combustibles 3.60 USD/t Electricity 17.50 USD/t Total costs36 226 USD/t Profit Turnover 265 $M operating income 39 $M Operating profit EBITA 14.8%

36

although this depends on the price for a tonne of finished product; but it provides a better return on asset or capital employed than an integrated mill.

Significant CO2 emissions come from rolling and finishing of products in the EAF route. Electricity can account for between 50-85 per cent of total energy inputs into an EAF37. The electricity consumption of an EAF reaches 650 kWh/tonne of liquid steel for an average EAF plant (Arcelor). The global CO2 emissions from the EAF process therefore depends on the fuel used to produce electricity.38. In this case, we suppose that all consumed electricity is acquired from the grid; the corresponding CO2 emissions are therefore not emitted by the steel producer. Our assumption on the carbon content of electricity is similar to the one used in the blast furnace route.

Table 11: CO2 Emissions from electricity consumption in an EAF Plant

MWH/T TCO2/MWH TCO2/T

0.65 0.385 0.25

EAF plants also emit process emissions from the use of solid and gaseous fuels such as coke and natural gas – although in a much smaller quantity than the integrated route. These fuels are used to heat the scrap – assumed in this report as the only raw material in the EAF plant.

Table 12: Total CO2 Emissions from an EAF Plant (tCO2/t of steel)

DIRECT CO2 EMISSIONS 0.15 CO2 EMISSIONS FROM PURCHASED ELECTRICITY 0.25 TOTAL DIRECT CO2 EMISSIONS COVERED / T OF

STEEL 0.15

2.1.2. PULP AND PAPER

In the pulp and paper industry, no mill resembles another: several processes can be used to produce a given paper product. Process and energy consumption will change depending on the type and grade of paper being produced. Table 13 therefore does not necessarily reflect the most energy efficient technology.

37 Jeremy Jones, Electric Arc Furnace Steelmaking, (www.steelmaking.or/learning/howmade/eaf.htm). 38 Whether the capacity of the generation plant is over 20MW, and thus covered by the EU-ETS directive, is also important.

37

Table 13: Breakdown of Costs for a Newsprint Mill in Europe (average)

Source: CEPI.

To build our representative mill, an EBITA of 14 per cent return on sales was assumed39. This represents an average return over a cycle. A top down approach then provided each cost in monetary figures.

Newsprint mills are very capital intensive plant. In operating costs, energy is a key factor, although the share of raw material costs is increasing with the growth of wood prices (Paper and Pulp Institute).

Figure 8: Primary Energy Consumption by Carrier (TJ, 2002)

Biomass, 52.2%

Coal, 3.7%Gas, 34.5%

Fuel oil, 7.5%

Other fossil fuels, 1.7%

Other , 0.4%

The CO2 emissions from non-integrated paper mills result primarily from electricity usage rather than from the papermaking process itself. The electricity consumed depends on the paper grade produced. On average, the power consumption is 1-3 MWh per tonne of newsprint (CEPI). The lower range of power consumption relates to recycled pulp, while the top end range represents virgin fibres. For our assumptions, we considered that the electricity was purchased and we used the average primary energy consumption in 2002 for CEPI40 countries (described in Figure 8), accounting only for direct fossil fuel emissions.

39 In contrast with the steel and aluminium sector, for the paper and cement sector, a top down method was used. Here, the return on sales is given and not deduced from specific costs. 40 Confederation of European Paper Industries: 16 European Union Member States plus Norway and Switzerland

% OF TOTAL COSTS

Fixed costs Depreciation 18% Labor 18% Maintenance 18% Other overhead 21% Variable costs Raw materials 11% Combustibles 2% Electricity 12% Total 100%

38

Table 14: Cost Assumptions for a Newsprint Mill

Source: CEPI.

Table 15: CO2 Emissions from Electricity in a Mixture of Newsprint Mills

KWH PURCHASED

POWER/TPAPER

MJ PURCH POWER/TPAPER MTCO2/TWH TCO2/GJ TCO2/TPAPER

1,744 6,279 0.385 0.107 0.67

Source: CEPI.

Plant breakdown Capacity 0.35 Mtonnes Asset cost 1200 USD per tonne Variables Price 450.0 EUR/tonne Capacity utilisation 85% Revenue Volume 0.2975 Mt Price 450.0 USD/t Total revenue 133.88 $M Fixed costs Depreciation 20.72 $M Labor 21 $M Maintenance 21 $M Other overhead 24.18 $M Variable costs Raw materials 12.66 $M Combustibles 2.05 $M Electricity 13.82 $M Total costs 115.13 $M Profit Turnover 133.88 $M operating income 18.74 $M Operating profit EBITA 14 %

39

Table 16: CO2 Emissions from Energy Combustion in a Newsprint Mill

CONSUMPTION OF ENERGY

SOURCES USED IN MILLS 2002

% OF TOTAL

ENERGY BALANCE

% OF FOSSIL FUEL

GWH MWH/

TNEWSPRINT

GJ/

TNEWSPRINT

EMISSION FACTOR

(TCO2/GJ)

TCO2/

TPAPER

Biomass 52% 0.0% 0.0 - - 0.00 - Coal 4% 30.0% 1518.9 0. 42 1.51 0.096 0.145001 Other 0% 0.0% 0.0 - - 0.096 - Gas 35% 27.0% 1367.0 0.38 1.36 0.056 0.076261 Fuel oil 8% 30.0% 1518.9 0.42 1.51 0.074 0.111922 Other fossil fuels 2% 13.0% 658.2 0.18 0.65 0.096 0.062834 100.0% 5063.0 1.40 5.03 0.396018

Source: CEPI.

Table 17: Total CO2 emissions from a newsprint mill

EMISSIONS FROM FOSSIL FUEL USE 0.4 EMISSIONS FROM ELECTRICITY

(INDIRECT) 0.67 TOTAL CO2 EMISSIONS/T NEWSPRINT 1.07

Source: CEPI.

In spite of being a rather energy-intensive activity, a newsprint mill emits relatively little CO2 per unit of energy consumed, a result of the significant share (i.e. 50%) of biomass – which is carbon free according to the IPCC methodology.

2.1.3. CEMENT

The cost structure of a representative cement plant is given in Table 19. It highlights the significance of fixed costs involved in the production of cement. As shown, total energy consumption – combustibles and electricity – is the single largest component, accounting for over a quarter of total cost.

To illustrate this breakdown in absolute figures, the representative plant in the industry has an annual capacity of 1 million tonnes of cement per year, operating at 85 per cent of its total capacity. The cost of the asset is estimated at USD150 per tonne of cement (ABN AMRO).41 The average price per tonne of cement in EU-15 is EUR 64.40, although prices vary from EUR 39.5 in Germany to EUR 76 in France (Table 18). However, in this analysis, an average42 price is taken for European cement. Using the cost assumptions from table 22 and assuming that the return on sales before taxes reaches 14 per cent, the total cost of a tonne of cement is approximately EUR 47.

41 In this report, one euro equals one US dollar. 42 Differences in prices between European countries may lead to differences in profits. This caveat is important to keep in mind when interpreting results based on average figures.

40

Table 18: Average Price per Tonne of Cement

END 2002 EUR/T

Austria 70 Belgium 70.65 Denmark 58 Finland 63 France 76 Germany 39.5 Greece 57 Ireland 71.1 Italy 63.3 Netherlands 70 Portugal 69 Spain 63 Sweden 63 UK 68

European average 64.40

Source: JP Morgan February 2004, Cembureau 2004.

Note: The prices shown are for most common type of cement used in the country, and are therefore a mixture of bulk and bagged prices, and ex-works and delivered prices.

41

Table 19: Cost Assumptions for a Cement Plant

Plant breakdown Capacity 1 Mtonnes Asset cost 150 USD per tonne Variables Price 64.0 USD/tonne Capacity utilisation 85% Revenue Volume 0.85 Mt Price 64.0 USD/t Total revenue 54.40 $M Fixed costs Depreciation 6.55 $M Labor 10 $M Maintenance 10 $M Other overhead 2.81 $M Variable costs Raw materials 4.68 $M Combustibles 6.55 $M Electricity 6.55 $M Total costs 46.78 $M Profits Turnover 54.40 $M operating income 7.62 $M Operating profits EBITA 14.00%

Source: IEA, ABN AMRO, JP Morgan, Cembureau.

Carbon dioxide emissions in cement manufacturing come directly from combustion of fossil fuels in the kiln – producing clinker – and from calcinating the limestone in the raw mix, i.e. process emissions. An indirect and significantly smaller source of CO2 is from consumption of electricity.

The fuels combustion relates primarily to the fuel that is burnt to heat the kiln during the process of clinker production. The primary fuels used are petcoke and coal, and in some of the older plants, heavy fuel oil (Figure 9). After the oil crises, the importance of alternative fuel sources43 increased since the latter prices are less volatile than conventional fossil fuel energy prices – often driven by the oil price. Many of these alternatives are considered CO2 neutral, and therefore offer an important option for reducing emissions.

Figure 9: Consumption of Energy Sources used in Kilns (2002) 43 The main alternative fuels used come from: animal meal, bone meal, animal fat, tires, paper, wood, cardboard, plastics, impregnated saw dust and other hazardous waste, sludge (paper fiber, sewage), refused derived fuels, packaging waste, agricultural and organic wastes.

42

Coal24%

Petcoke50%

Gas1%

Other fossil fuels0%

Fuel oil4%

Lignite shale schiste

5%

High viscosity fuel oil

2%

Total alternative fuels14%

Source: Cembureau.

In a cement plant, CO2 is generated from three independent sources: de-carbonation of limestone in the kiln (approximately 525 kg CO2 per tonne of clinker); combustion of fuel in the kiln; and use of electricity – as indicated in Table 20.

Table 20: CO2 Emissions from Energy-use in a Representative Cement Test Plant

IN % IN MJ/KG

OF CLINKER

KGCO2/GJ TCO2/GJ TCO2/T CLINKER

TCO2 FROM ENERGY

CONTENT/T CEMENT

Coal 24.2 0.89 96 0.096 0.09 0.068 Petcoke 50.3 1.84 100 0.1 0.18 0.148

Lignite shale schist 4.7 0.17 107 0.107 0.02 0.015 Other fossil fuels 0.2 0.01 96 0.096 0.00 0.001

Fuel oil 3.7 0.14 74.1 0.0741 0.01 0.008 High viscosity fuel oil 1.5 0.06 77.4 0.0774 0.00 0.003 Gas 1.2 0.04 56.1 0.0561 0.00 0.002

Total alternative fuels44 14.1 0.52 80 0.08 0.04 0.033

Total energy 0.35 0.278 Source: Cembureau.

In the representative cement plant, the quantity of electricity needed to produce one tonne of cement totals 103kWh (Cembureau, 2002). In most cases, cement producers purchase power from the grid and lead to indirect emissions.

44 http://www.ghgprotocol.org/standard/Current_Tools/cement_WBCSD_guidancev1.6.doc Cement industry increasingly uses a variety of waste-derived alternative fuels and raw materials (AFR) which, without this use, would have to be disposed of in some other way, usually by landfilling or incineration. AFR include fossil-based fractions (such as e.g. waste tires, waste oil, plastics and others) and biomass fractions (such as e.g. waste wood, sewage sludge and others). AFR serve as a substitute for conventional fossil fuels.

43

Table 21: CO2 Emissions from Electricity in a Cement Test Plant

KWH/T CEMENT MTCO2/TWH TCO2/TCEMENT

Electricity 103 0.385 0.040

Source: Cembureau.

Table 22: Total CO2 Emissions in a Cement Test Plant

PER TONNE OF

CEMENT

PROCESS EMISSIONS 0.525 EMISSIONS FROM ENERGY 0.278 EMISSIONS FROM ELECTRICITY 0.040 TOTAL CO2 EMISSIONS 0.84 TOTAL CO2 EMISSIONS COVERED BY ETS 0.80

Source: Cembureau.

Using the CO2 factors given by the WBCSD/WRI “GHG Protocol Initiative”, the carbon content of energy combustibles is 0.35 tonnes of CO2 per tonne of clinker; and 0.28 tonne of CO2 per tonne of cement – 0.8 tonne of clinker is needed to produce a tonne of cement. The total amount of CO2 per tonne of cement covered under the EU-ETS reaches 0.80 tonnes.

2.1.4. ALUMINIUM

Aluminium smelting consumes large quantities of electricity and therefore tends to be located near abundant and cheap power resources. Many locations are remote, with electricity generated specifically for the aluminium plant. As electricity accounts for a large share of total production costs, energy efficiency is a major area of research for aluminium companies.

On average, in Europe in 2002, it took approximately 15.4 kWh of electricity to produce one kilogram of aluminium from alumina. Aluminium is formed at about 900°C, but once formed it has a melting point of only 660°C. In some smelters, spare heat is used to melt recycled metal. Recycled aluminium requires only 5 per cent of the energy required to make primary aluminium. Blending recycled metal with new metal allows considerable energy savings, as well as the efficient use of process heat. In terms of quality or properties, there is no difference between primary and recycled aluminium.

The aluminium smelter industry is very much focused on variable cost. The share of variable costs reaches 68 per cent, equivalent to the share in the steel sector. The main reason is the high cost of raw material: bauxite and alumina are produced thousands of kilometres away from European smelters. Two countries own nearly half of the total economically recoverable bauxite reserve (Guyana: 25 per cent and Australia: 20 per cent). Likewise, trade in alumina is largely controlled by a limited number of countries active on both the demand and the supply side (Gielen and Van Dril, 97).

44

Table 23: Cost Breakdown for an Aluminium Plant

% OF TOTAL COSTS

Fixed costs Depreciation 9% Labor 11% Other 10% Variable costs Raw materials 35% Electricity 35% Total 100%

Source: EAA, IEA assumptions.

Unlike the other commodities examined, the LME – London Metal Exchange – sets the aluminium world price in USD. The aluminium LME price is a worldwide price determined by a market mechanism which can sometimes demonstrate volatile behaviour (Figure 10). In May 2004, the three –month aluminium price was trading around USD1600/t.

Figure 10: Aluminium LME Prices (Monthly, USD / tonne)

Source: EAA

Direct emissions from aluminium production are about 3.5 tCO2/tonne of primary aluminium – including the alumina process (EAA)45. Carbon dioxide is also produced when burning directly fossil fuels such as crude oil and propane gas. However, during the first phase of the EU-ETS, the direct CO2 emissions of aluminium production are not covered nor capped. Hence, they shall not be discussed in a more detailed manner in the sections dealing with the first trading phase. In this report, we shall thus assume that the industry’s direct emissions are zero. Due to its reliance on electricity, it has significant indirect emissions, however, and is exposed to potentially high increase in cost.

Table 24: Cost Assumptions for an average aluminium plant in the EU 45 Although not included in the EU-ETS, aluminium smelting also emits perfluorocarbons (approximately 2 t CO2 equivalent per tonne of aluminium). Emissions result from petcoke anode use (approximately 1.5 t/t Al).

0

500

1000

1500

2000

2500

3000

1973

1975

1977

1979

1981

1983

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

45

Source: CECS, EAA, IEA

Table 25: Indirect CO2 Emissions from Electricity Use in an Aluminium Plant

MWH/T PRIMARY ALUMINIUM TCO2/MWH TCO2/TALUMINIUM

15.2 0.385 5.9

Capacity 0.150 Mtonnes Asset cost 4125 USD per tonne Variables Price 1600 USD/tonne Capacity utilisation 93% Revenue Volume 0.140 Mt Price 1600 USD/t Total revenue 223.2 $M Fixed costs Depreciation 124 USD/t Labor 150 USD/t Other 144 USD/t Variable costs USD/t Raw materials 500 USD/t Combustibles 0 USD/t Electricity 500 USD/t Total costs 1417 USD/t Profit Turnover 223 $M operating income 25.5 $M Operating profit EBITA 11.4%

46

2.2. DIRECT IMPACT OF ETS ON INDUSTRIES

The direct impact of an emissions trading scheme on a source’s cost comes from any measure to mitigate emissions and spending to acquire allowances when these are needed to offset emissions above the initial allocation. As mentioned above, we take a methodological shortcut to avoid forming assumptions on actual abatement cost and initial allocation levels. Rather, we approach this through the direct cost of acquiring allowances, knowing that this represents an upper bound for the cost of achieving a given reduction target. In this section, we implement this approach in the steel, cement and paper sectors.

We start by assuming that a plant would have to cover all its emissions through the purchase of allowances, a scenario that is not different from a carbon tax. This approach may be relevant for long term investments if new capacity is not granted any significant share of its allowance needs for free.

2.2.1. Direct CO2 emissions from process related emissions and from energy consumption

As discussed earlier, industrial emissions are divided between emissions resulting from fossil energy consumption and those from the production process. Table 26 summarises the total CO2 emissions per tonne of products based on the assumptions of the previous section.

Table 26: Total CO2 emissions covered under the first EU-ETS trading period per tonne of product

WESTERN

BOF PLANT

EAF PLANT

CEMENT PLANT

NEWSPRINT MILL

ALUMINIUM SMELTER

Total CO2 emissions/tonne of product 1.93 0.15 0.80 0.4 N.A.

2.2.2. Potential increase in industries’ costs

The largest emitting industry per tonne of product is the integrated steel industry. It emits more than twice the amount of direct CO2 emissions of cement and over four times the emissions from a newsprint mill. This information is nevertheless insufficient to assess the direct cost of the CO2 constraint under the EU ETS: based on the share of carbon costs in total variable costs for each industry, the carbon cost in the cement plant is twice that of the integrated steel plant.

Increases in costs resulting from allowance purchasing for industries covered by the EU-ETS are illustrated in Table 27, for a range of CO2 prices. Note that these costs would only be incurred by marginal production, i.e. production whose emissions is not covered by the initial allocation to this installation.

47

Table 27: Increase in costs for marginal products

CARBON PRICE EUR/TCO2

WESTERN BOF

EAF CEMENT NEWSPRINT

5 4% 0% 9% 1% 10 7% 1% 17% 3% 15 11% 1% 26% 4% 30 22% 2% 51% 8% 50 37% 3% 86% 14%

Trading under the EU-ETS scheme so far has led to CO2 prices have been in the range EUR5-10/tCO2 (for 2005-2007 vintages). For illustrative purposes, a greater range is taken, reflecting a general expectation that the CO2 price will increase in the 2008-2012 trading period. Regardless of CO2 price levels, the cement industry is the most impacted by the direct cost of emissions for its marginal units. The price of a tonne of cement is much lower than a tonne of steel, so additional carbon cost has a higher impact. Table 28 shows the new cost structure46 including the direct cost of CO2 allowances at a EUR10/tCO2 price.

Table 28: New cost structure for marginal cement production plant, including the direct impact of a EUR10/tCO2 price

% OF TOTAL

COSTS

Fixed costs Depreciation 12 Labor 18 Maintenance 18 Other overhead 5 Variable costs Raw materials 9 Combustibles 12 Electricity 12 Carbon 14 Total 100

If these industries were to pay the carbon cost for every tonne emitted at EUR10/tCO2, the carbon exposure would amount to 14 per cent of a typical cement plant’s cost structure, 5.5 per cent for a Western European steel furnace; and 3.4 per cent for a newsprint mill.

However, allowances are also assets which, although distributed for free, will carry a value on the market. If the price of carbon amounts to EUR10/tCO2, then an integrated steel plant would receive the equivalent of 4.3 per cent of its fixed assets for free in Western Europe47, 3.7 per cent in Eastern Europe. A cement plant would receive 5.3 per cent of its assets for free, a newsprint mill 2.7 per cent.

46 The new cost structure relates to the marginal products – i.e. those whose emissions are not covered by free allowances. 47 4.3 EUR/tonne of steel = (1.865tCO2/tonne of steel * EUR10/tCO2 ) / EUR500/tonne of steel

48

Ultimately, the economic logic should drive industry towards reflecting the value of this rent, i.e., the full opportunity cost of holding allowances, in its product prices. At present this behaviour corresponds to the costing mechanism on which generators base their production decision. However, the ability of heavy industry to increase product prices may be limited by competition on international markets. We return to this question in Section 3.

2.3. INDIRECT IMPACT OF ETS

The increase in power prices as a consequence of the power sector’s emission cap under the EU ETS and its marginal pricing mechanism is an important part of the economic picture of the scheme – some parts of industry are complaining about the so-called “windfall profits” that power generators will record as the price of CO2 is reflected in the electricity price. As such, this is the only so-called indirect impact covered in this report.

2.3.1. The impact of ETS on electricity prices

Large electricity producers work daily with mixed integer linear programming (MILP) computer programs to optimise the utilisation of the production of their power plants. These advanced programs are necessary to produce at lowest cost in very complex systems (minimum load of each plant, different fuel cost contracts for each type of fuel, different selling prices attainable in the market, etc.).

Electricity generators optimize their production portfolio by running their plants according to their marginal costs (Eurelectric). The revenue of a power plant depends mainly on the wholesale power price – whether the producer is buying from the spot market or tied to a bilateral contract indexed on the forward price market. If the market price is below the plant’s marginal production costs it is uneconomical to operate a power plant. Hence the profitability of a power plant essentially depends on the wholesale market where prices are determined by wholesale power demand and the industry’s short-run marginal costs.

In theory, the value of carbon emission allowances should be reflected in the short run generating costs of fossil-fired plants, because emissions from generation have to be offset with allowances held or purchased on the CO2 market (Reinaud, 2003). If the market price does not cover its incremental costs including the value of the allowances, the power producer is better off not to produce and to sell unused allowances.

Nevertheless, the decision to pass-on the full opportunity cost of allowances or only part of it depends on several factors – notably on the nature of the power market design and on type of contract the generator has with its customers, including energy-intensive users in a liberalised market.

• Markets with Dispatch Priority and System Balancing

Forms of this model, based on the Scandinavian NordPool, became popular in the late 1990s for new markets in the USA (California; Pennsylvania, New Jersey and Maryland; New York), Spain and now in the UK. This model has a feature that causes competition to be more aggressive than in mandatory pools by requiring to win a physical contract in order to be dispatched (World Energy Council). Supply contracts tend to be similar, whether from baseload plants or from marginal peaking plants. Large customers who contract tend to be more baseload. Consequently, excess capacity in marginal peaking plants will have to offer contract prices that compete with the lower priced baseload

49

generation. In addition, contracts provide the right of dispatch for a long time period, which encourages generators to offer cost-plus prices.

• Markets with Bilateral Trading

In case of bilateral contracting between a generator and an energy-intensive user, wholesale generators can be in intense competition. In order to maintain their share of the wholesale market, generators must keep their prices competitive. In this case, grandfathered allowances might be considered as “soft” costs48. The only CO2 emission costs generators would pass onto their prices are the ones resulting from the purchase of allowances and abatement expenditures (Reinaud, 2003) – i.e. the net cost rather than the full opportunity cost. Generators may therefore only increase their prices to the level which compensates the average carbon emission cost (total emission allowance costs / total amount of GWh produced in the year).

• Regulating prices in power markets

In certain countries, governments may explicitly regulate increases in power prices resulting from a carbon constraint. Spain and Ireland recently announced increases resulting from emissions trading would be contained. In Spain, in July 2004, the government decided not to allow electricity companies to raise tariffs to compensate for the cost of implementing the EU ETS. Moreover, any increase in wholesale prices would be offset in lower stranded cost compensation to generators until the expiration in stranded costs49 (Reinaud, 2003). In Ireland, the government announced in April 2004 that it would take steps to prevent “windfall” gains for Irish state-owned power companies arising from the free allocation of allowances50 and to ensure there is no major increase in the price of electricity for consumers. This initiative would minimise any increase in power prices to between 1 and 2 per cent51.

Overall, when the EU emissions trading market enters in force, there may not always be a one-to-one transfer of the opportunity cost of allowances onto power prices. Furthermore, high carbon generation is not the marginal source of supply all year long (Eurelectric), which would imply differences in the CO2 cost of electricity depending on the time of the year.

2.3.2. Sensitivity analysis based on different CO2 prices and different passing-on ranges

We conducted a simplified sensitivity analysis of the indirect impact of the EU-ETS based on different carbon prices and two assumptions on the pass-through of the opportunity cost of CO2 allowances (50 to 100 per cent).

Figure 11 illustrates a hypothetical merit order based on the total European installed capacity, and facilities’ operating costs and a carbon intensity is attached to each power technology (see Reinaud, 2003, for assumptions). Carbon costs are added to the latter based on their carbon intensity and thermal efficiency. Neither hydro nor nuclear facilities emit carbon. Coal plants emit approximately 0.918 tCO2/kWh, running at a 37 per cent thermal efficiency rate. In contrast, CCGT plants emit 0.412 tCO2/MWh, under a 49 per cent thermal efficiency rate.

48 Such cost could be absorbed by the company without any “real” financial losses (Reinaud, 2003) 49 This assumes that stranded costs are larger than the revenue upside which is almost certainly the case. 50 Privately-owned generators could not be concerned. 51 http://www.politics.ie/modules.php?name=News&file=article&sid=4333

50

Figure 11: European merit order and impact of a EUR15/tCO2 carbon price

125

56

3634

27

18

106

3

132

64

4541

3332

10

3

0

20

40

60

80

100

120

140

0 100 200 300 400 500

Installed capacity Europe (GW)

Sh

ort

ru

n m

arg

inal

co

st

/MW

h

Short run marginal cost without carbon constraint Short run marginal cost with carbon at 15 /tCO2

NuclearHydro

WindCoal CCGT Gas

Boiler

GasTurbine

Oil

GT Diesel Fired

Assuming the merit order in Figure 11 and a demand level at 255 GW, the weighted average carbon cost on the market is EUR7.5 per MWh for a carbon price of EUR15/tCO2 assuming a full pass on their carbon costs to their wholesale prices (Figure 12). This represents a total price increase of 16 per cent.

Table 29 estimates the effects of varying carbon emission prices on Europe’s wholesale power prices. If we assume that the full opportunity cost of allowances is passed on to wholesale prices, the power price increases are very similar to the monetary value of carbon allowances, for a reference electricity price of EUR47/MWh.

Table 29: Increase in electricity prices in Continental Europe assuming full opportunity cost

CARBON PRICE EUR/TCO2 0 5 10 15 30 50

Increase in electricity price 0% 5% 11% 16% 32% 53%

Power prices EUR/MWh 47.12 49.62 52.13 54.63 62.14 72.16

The full opportunity cost of CO2 allowances may not necessarily be passed on. Figure 12 illustrates the differences in power price increase following varying passing-on ranges of the opportunity cost associated with carbon – in this case, 50 per cent and 75 per cent.

51

Figure 12: Increase in power prices following different carbon prices and passing-on ranges

404550556065707580859095

100

0 5 10 15 30 50 100

Carbon price /tCO2

Po

wer

pri

ces

/MW

h

50%passing-on 75% passing-on 100% passing-on

44

45

46

47

48

49

50

51

52

53

0 5 10

Carbon price /tCO2

Pri

ce o

f el

ectr

icit

y /M

Wh

100% passing-on 75% passing-on 50%passing-on

For a carbon price around EUR10/tCO2, the impact on power prices ranges between 3 and 5 per cent of the wholesale price for a 50 to 100 per cent pass-through of the opportunity cost passing on. This range of deviation naturally increases if the price of carbon emissions increases (Figure 12).

Although it is impossible to estimate the exact increase following the introduction of emissions trading, it is possible to approximate the minimum power price increase if we suppose that the power producers’ emissions are, say, 5 per cent above their initial allocation of allowances – following the method used to determine the abatement + purchase cost in other industries. Considering that the average carbon intensity for Europe equals 0.385 tCO2/MWh (IEA, 2003), the minimum amount by which power prices could increase at a EUR 10/tCO2 price is EUR 0.2/MWh52.

2.3.3. Potential increase in industries’ costs

The installations’ operating costs increase as a consequence of reflecting the full opportunity cost of CO2 allowances in the generation sector is shown in Table 30.

Table 30: Increase in total costs per tonne of finished product53 assuming full opportunity cost

CARBON PRICE

EUR/TCO2

INCREASE IN ELECTRICITY

PRICES

WESTERN BOF

EAF CEMENT NEWSPRINT ALUMINIUM

5 5% 0.2% 0.4% 0.7% 0.5% 2.0% 10 11% 0.5% 0.8% 1.5% 1.1% 3.7% 15 16% 0.7% 1.3% 2.2% 1.6% 5.6% 30 32% 1.5% 2.5% 4.5% 3.3% 11.2%

In practice, whatever level of opportunity cost is passed onto wholesale electricity prices, the effect on operating costs is greatest for aluminium, where electricity accounts for 35 per cent of the plant’s

52 EUR 0.2/MWh = EUR10/tCO2 * 5% * 0.385tCO2/MWh 53 Note that the direct impact of emissions trading will only be for marginal products which are not covered by free allowances.

52

total cost54. If, however, the opportunity cost is only partly passed on, the indirect effect of emissions trading should be less significant. This will have important consequences on the potential loss in operational profitability of these industries.

2.4. ESTIMATES OF THE TOTAL COST OF THE EU ETS

This section offers orders of magnitude of the cost increases likely to be incurred by energy-intensive industries in Europe as a result of the implementation of the EU ETS. As made clear earlier, for each range of reduction, we consider these estimates to represent upper bounds of compliance costs. Taking into account the cost of implementing in-house reductions would in fact lead to a lower compliance cost, as these reductions ought to be conducted only if they are cheaper than the price of traded CO2 allowances.

Our cost estimates reflect the actually incurred cost, not the opportunity cost of withholding allowances55, since we assume that industry – with the exclusion of power generation – will spread the cost of compliance with the CO2 constraint on their entire production, and not on a hypothetical marginal output56. For the sake of illustration, we first indicate the cost increase of so-called marginal output, based on a carbon price of EUR10/tCO2 (Table 31).

Table 31: Direct plus indirect impact for a EUR10/tCO2 price for marginal products

WESTERN BOF EAF CEMENT NEWSPRINT ALUMINIUM

Cost increase (%) 7.7% 1.5% 18.6% 3.9% 3.75% Total cost increase (USD/t of finished product) 20.6 3.4 8.7 4.5 53.1

We work from two different allocation scenarios: industry would be allocated allowances covering either 98 or 90 percent of its CO2 emission needs (hereafter referred to as 10 per cent and 2 per cent scenarios). In summary, the main assumptions in this analysis are as follows:

• Total costs = Direct cost of compliance + Indirect costs from electricity price increases;

• Companies must abate / purchase either 2 or 10 per cent of their ex-ante emissions;

• Industry prices its products based on average cost – with the exception of power generation;

54 - compared to 14 per cent in the cement plant, 10 per cent in the newsprint mill, and 8 per cent of costs in the electric arc furnace 55 This method is similar to that used in the Carbon Trust study on the effect of the EU ETS on UK industry (2004). 56 The notion of applying the cost of purchased allowances only to marginal production above the initial allocation makes sense in a longer term perspective, when an industry has the possibility of investing in a new installation for which no allowances may be provided for free. In this long-term perspective, the treatment of new plants will prove crucial for the economics of these activities.

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• Power generators price electricity based on the full opportunity cost of CO2 allowances.

Table 32 and Table 33 gives the cost increase for the bulk production following a rise in power prices, reflecting our assumption that products at priced at average cost, not marginal cost. They assume 2 or 10 per cent allowance needs.

Table 32: Direct and indirect cost increase under 2 per cent scenario (EUR 10/tCO2)

UNIT WESTERN BOF57 EAF CEMENT

58 NEWSPRINT ALUMINIUM

59

Unit cost increase from indirect effect (electricity price increase)

(USD/t) 1.34 1.8 0.7 1.3 53.1

Total EU production (Mt) 96.3 64.2 196 8.8 3.8

Total cost increase from indirect effect (A) (M$) 129 115.6 140 11.4 108.7

Marginal cost increase (direct and indirect) per unit

(USD/t) 20.6 3.4 8.7 4.5 53.1

Output covered by marginal allowances (2%)

(Mt) 1.926 1.284 3.92 0.0176 0

Total cost increase from direct plus indirect on marginal output (B)

(M$) 39.68 4.37 34 0.08 0

Total cost increase (A+B) (M$) 168.68 119.97 170 11.48 108.7

Total cost increase per tonne (USD/t) 1.75 1.87 0.87 1.3 53.1

Cost increase (% of

product cost)

0.7 0.8 1.9 1.1 3.7

57 The total production in Europe is for Western Europe in 2003. It totals 160.5Mt for both routes (IISI). 58 Total production of cement reached 196 million tonnes in 2002 for EU-15 (Cembureau). 59 Source: EAA, 2004.

54

Table 33: Direct and indirect cost increase under 10 per cent scenario (EUR 10/tCO2)

UNIT STEEL BOF

STEEL EAF CEMENT NEWSPRINT ALUMINIUM

Unit cost increase from indirect effect (electricity price increase)

(USD/t) 1.34 1.8 0.7 1.3 53.1

Total EU production (Mt) 96.3 64.2 196 8.8 3.8

Total cost increase from indirect effect (A)

(M$) 129 115.6 140 11.4 108.7

Marginal cost increase (direct and indirect) per unit

(USD/t) 20.6 3.4 8.7 4.5 53.1

Output covered by marginal allowances (10%)

(Mt) 9.63 6.42 19.6 0.9 0

Total cost increase from direct plus indirect (B)

(M$) 198.4 21.8 170 4.05 0

Total cost increase (A+B) (M$) 327.4 137.4 310 15.45 108.7

Total cost increase per tonne (USD/t) 3.4 2.1 1.6 1.8 53.1

Cost increase (% of final

product cost)

1.3 0.9 3.4 1.6 3.7

Based on this analysis and the above assumptions, we find that the implementation of the EU ETS would only have modest impacts on the cost structure of these industries, when considered through the lens of an average EU plant. Beyond this assumption, some caveats remain, which may move these estimates up or down from the above picture.

• First, allowance trading implies buyers and sellers. Sellers are likely to be better off than the above suggests, since they would not need to acquire allowances for compliance – unless we assume that all the allowances needed by industry and power generation in Europe will be supplied via the Clean Development Mechanism and Joint Implementation projects.

55

• Second, some plants may be closer to the 2 per cent scenario and others to the 10 per cent scenario. It is not certain, but not impossible, that variations in allocation levels could distort competition.

• Third, the magnitude of indirect effects hinges on the specific power generation in regional markets. Here again, effects may differ greatly (consider Poland, with the immense majority of power generated from coal, and France, with a very low carbon intensity). Only experience will indicate whether these differences matter in an increasingly integrated electricity market and if power market prices and actual costs incurred by consuming industries reflect the CO2 cost at the margin or not.

3. FROM COSTS TO COMPETITIVENESS

As mentioned in Section 1, the approach to assess competitiveness is multi-faceted. It can be evaluated at different levels – national, industrial, or firm – as well as domestically, regionally, and internationally. At each level of aggregation, there are different indicators of competitiveness. For a nation, competitiveness implies a country’s capacity to achieve sustained economic growth and employment while remaining open to international trade. For a firm, being competitive involves winning market shares over competitors, either through more competitive pricing or quality improvements. In this section, we remain focussed on cost. We explore the effect of carbon cost on profits and on product demand. To complete this picture, we take into account freight costs, which are critical in comparing EU products to external competition.

If costs increase for a determined product, a firm can either reduce its profitability60 level; or decrease its production volume. The latter could arise as a result of a decrease in demand. This decrease in demand could be accompanied by an increase in output from outside competitors. How concentrated product markets may be and how exposed to international competition will of course matter as well, but these two dimensions are not fully explored here. The purpose of this section is to provide first-order estimates of output losses in industries studied above. This will serve as a proxy for what the impact on competitiveness may be.

3.1. IMPACT ON OPERATIONAL PROFITABILITY MARGINS

Industries exposed to international markets will need to prioritise between maintaining market share and profitability – notwithstanding the possibility that new product strategies emerge and make it possible to sustain both. If the former is favoured, profitability margins should decrease, other things being equal. Table 34 illustrates estimated change in the profitability level following the introduction of a EUR10/tCO2 carbon price and a 100 per cent passing-on of carbon costs to power prices. The decrease in operational margins is calculated by adding both the direct and indirect costs associated with emissions trading, following the approach of the previous sections.

Table 34: Effect of the EU ETS on industries’ operational margins (at EUR 10/tCO2)

DECREASE IN OPERATIONAL PROFITS

WESTERN BOF EAF CEMENT NEWSPRINT ALUMINIUM

Scenario

60 The impact would be financial (e.g. lowering returns to shareholders) which may also have a competitiveness impact – although this is not studied in this report.

56

2% allowance needs -3.8% -2.1% -5.0% -0.4% -29% 10% allowance needs -6.8% -2.2% -8.1% -0.5% -29%

Based on our assumptions, the aluminium industry would incur the most important reduction in profitability.

The following section evaluates the effect of maintaining profitability through product price increases.

3.2. IMPACT OF A COST FEED-THROUGH TO PRODUCT

Maintaining profits margins constant when faced with a cost increase requires passing such cost onto product prices. Two factors need to be accounted for to assess the feasibility of this strategy. The first component is the demand response, essentially related to the existence of substitutes for the product. The second is the competitive nature of the market, i.e., whether the market is monopolistic, oligopolistic or fully competitive. In particular, whether the sold product can be produced abroad and sold on international rather than just domestic markets, will affect the impact of the price increase.

3.2.1. DEMAND RESPONSE

In each industry, the rule for every firm is to maximise its profits under market constraints, including an appreciation of the demand response to prices. The price elasticity of each product varies mainly with the number of competitors – both on the domestic and international market – and product substitutability.

If we suppose that the price elasticity in each studied sector is close to zero – inelastic demand –, demand will remain constant whatever the price increase may be. Traditionally, the demand curve in the power market is described as rather inelastic – with an elasticity between -0.1 and -0.3. In contrast, commodities produced by several firms and traded internationally such as steel and aluminium record price elasticities closer to -1: a 10 percent increase in price will trigger a 10 percent reduction in demand.

Table 35 gives the new prices per tonne of finished product if the costs associated to carbon were fully passed on to consumers and profit margins were maintained. Here again, the electricity price is assumed to reflect in full the increase in marginal cost of generation.

Table 35: New market price (EUR per tonne of finished product) for a EUR 10/tCO2 allowance price

NEW MARKET PRICE WESTERN BOF EAF CEMENT NEWSPRINT ALUMINIUM

Scenario Business as Usual (w.o. EU

ETS) 313 312 64 450 1600 2% allowance needs +0.5% +0.3% +1.6% +1.0% +3.4%

10% allowance needs +1.0% +0.7% +2.6% +1.2% +3.4%

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These price increases should trigger a reduction demand. Price elasticities in Western European countries equals -0.27 for the cement industry (La Cour and Mollgaard, 2002; sourced by Oxera, 2004); -1.88 for the paper industry (AEA Technology, 2003); -1.56 for the steel industry (Humphry, 2002 sourced by AEA Technology, 2003); and -0.86 for the aluminium industry (AEA Technology, 2003). Table 36 quantifies reductions in demand based on these price elasticities for each allocation scenario (i.e., 2 per cent or 10 per cent of allowance needs must be fulfilled by the market).

Table 36: Demand reductions from price increases with constant profitability margins for a EUR 10/tCO2 allowance price

STEEL BOF STEEL EAF CEMENT NEWSPRINT ALUMINIUM

Price elasticity: -1.56 -1.56 -0.27 -1.88 -0.86 Scenario

2% allowance needs -0.8% -0.5% -0.4% -1.8% -2.9% 10% allowance needs -1.6% -1.2% -0.7% -2.3% -2.9%

The effect of price rise on output should take place in the short term. In the longer run, these industries could make the choice to reduce investments inside the EU and to relocate production where it would be more profitable – assuming that they can re-export production into the EU. It would typically depend on several factors61, including the level of allocation to industry, its ability to develop less CO2-intensive processes and to pass on any remaining cost increase to consumers. Section 4 offers a survey of results on the risk of so-called leakage, i.e., the compensation of an industry’s greenhouse gas reductions by an increase in the same industry’s emissions in regions situated outside this constraint as a result.

3.2.2. MARKET CONCENTRATION

How a firm approaches pricing strategies depends on the market structure for its products. At one end of the spectrum, perfect competition sets the standard against which all other types of competitive behaviour are evaluated. Firms are price takers: they have no control over the price they charge – they must take the price set by the market. At the other end, monopoly represents an absolute lack of competition: the one and only firm in the industry has a high degree of price-making ability. In between these two extremes, the market structure can often be oligopolistic: a few large firms represent a significant share of the total market.

In sectors such as iron ore mining and aluminium, the top five producers hold over or close to fifty per cent of the world market share. In the steel and cement sectors, in contrast, the market structure is more competitive (see Annex 3). Nevertheless, in each industry, the market share is reasonably consolidated for a commodity market, with top three or ten producers holding over 30 per cent of the market. The assumption of oligopoly therefore holds for these industries.

While building material producers such as cement, aluminium and steel may not be able to determine the size of the market into which they sell – demand is set by broader macroeconomic factors such as GDP –, they can influence the share of the market they supply by adjusting their prices. In the

58

industries studied, competition occurs along a price dimension – a Bertrand type of competition (see Box for further explanation). However, as opposed to a Bertrand-like competition, players tend to set a disciplined approach towards pricing since they aim to earn a desired return on their investment.

Price Competition with Homogeneous Products – The Bertrand Model

Two firms producing a homogeneous product (e.g. cement) choose to set their prices (not their outputs) and to let the market decide what level of production can be sold at that price. Each firm still wants to maximise its own profits. Each needs to take account of the possible actions of the other(s).

Consider the logic of the first firm. It argues that for any given price (p2) set by firm two, its own best price will be just below this level. However, the second firm also thinks that its best price is a price just below any price that might be set by firm one. Henceforth, the only stable (equilibrium) outcome, where both are doing their best given what the other is doing, is one where price equals the competitive level and above normal economic profits are squeezed to zero. In conclusion, with just two firms theory says we get a competitive outcome.

The equilibrium of this model highlights the importance of differentiating the product. If firms can differentiate their product this may allow them a way out of the destructive logic of price competition. This is no doubt why firms in industries like steel and aluminium spend heavily on differentiation activity. Source: http://homepages.strath.ac.uk/~hbs96107/mbmch7.ppt

61 Many of such factors are not related to climate policy: the availability of skilled labour, transportation and communication infrastructure, a favourable fiscal policy, regulatory certainty, low-cost resources, to name a few.

59

Unless each competitor is under similar market constraints, firms operating in an oligopolistic market structure will tend to limit the passing of costs increases onto prices. In the case of emissions trading, European firms might restrict the full inclusion of carbon costs onto their sales price since they compete against non-European firms who are not carbon constrained. However, freight costs and border tariffs effectively seem to limit competition from non-European companies.

3.2.3. TRADE OPENESS

Figure 13 illustrates for each sector the openness ratio used by the OECD as well as the emissions/turnover ratio. The OECD openness ratio is defined as: X/Q + (1-X/Q)*M/D, where X are exports, Q production, M imports and D final domestic demand. The first element of the sum takes into account international competition on foreign market, and the second competition on the domestic market (Hourcade, Quirion, 2004).

Figure 13: Openness to extra-UE 15 Competition and CO2 emissions in 2001

Pulp, paper, printing and publishing

Non-metallic minerals

Non-ferrous metals

Average manufacturing

industryIron and steel

industryChemicals

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

Source: Hourcade, Quirion, 2004

Among the sectors studied, the most open to international competition is the non-ferrous metals sector, which includes aluminium. This implies that aluminium is more exposed to a loss in competitiveness on the international market. We should note also that if it were directly covered and if other greenhouse gases were included in the ETS, its competitive position could be undermined further, assuming that the constraint imposes an additional cost to the industry.

3.3. EXPOSURE TO INTERNATIONAL MARKETS

Having identified the sectors that could be most affected by an increase in costs and the extent to which those products are traded worldwide, we now turn to the assessment of the potential increase in import penetration and loss of exports for European industry,. This section compares transportation costs with CO2 costs, and highlights at which level non-carbon constrained products – including freight costs – would be cheaper than domestic products – including direct and indirect CO2 costs and the production cost differential. Together, these figures give an indication of the extent to which an industry could be threatened by foreign competitors.

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We first consider international freight markets and freight costs and then offer a comparison with CO2 costs.

3.3.1. INTERNATIONAL FREIGHT MARKETS

Competition between EU and non-EU countries for exports and imports of commodities requires including freight costs in the sales price.

Ships predominantly used to transport cement, steel, aluminium and paper products, whether carrying raw or intermediate materials, are standard bulk carriers. These ships commonly carry a wide range of cargoes, all of which have their own markets that are often totally unrelated to each other. The ship operator, on the other hand, has a completely different perspective, considering a much wider range of cargoes available on the world market, comparing returns expected from undertaking specific business with a particular charterer (World Cement, 2004).

Table 37 gives the representative cargoes by type of transported product. As illustrated below, if any of the four industries covered by this report export or import their products, they are in competition for the type of ship they need: Handymax and Handysize. As a general rule, due to the economy of scale, the bigger the cargo parcels, and the faster the loading and discharging operations, the bigger the vessel transporting the cargo . In choosing between General Cargo, Handymax and Handysize, the market will therefore always seek to use larger vessels if available.

Table 37: World fleet of bulk and general cargo carriers

SHIP TYPE SIZE REPRESENTATIVE CARGOES

Capesize + 80,000 DWT* Iron Ore/Coal/Grain/Salt

Panamax 60 – 80,000 DWT Iron Ore/Coal/Grain/Bauxite/Phosphate

Handymax 40 – 60,000 DWT Grain/Coal/Steel Products/Potash/Minor Bulks

Handysize 25 – 40,000 DWT Minor Bulks**/Steel Products/ Cement

Handysize 10 – 25,000 DWT Minor Bulks*/Steel Products

General Cargo

10 – 25,000 DWT Minor Bulks/General Cargo

Source: Fairplay World Shipping Encyclopaedia. * DWT (Dead Weight Tons); total carrying capacity of vessel, including cargo, fuel oils, fresh water,

spares and stores etc. ** Minor Bulks include rice, sugar, gypsum, fertilisers, forest products, scrap, minerals, etc.

However, there is a general limitation in average ship sizes serving different routes due to factors such as a) port restrictions; b) infrastructure; c) trade limitations; and d) intra-area trades: the economy of scale only applies when vessels are at sea, and the shorter the distance the less time will be spent at sea (Thoresen62). As such, the smaller vessels (Handymax and Handysize) will remain very much in demand, and the larger vessels will not substantially infringe into their current market. The alternative is that terminals for cement, aluminium or paper and shore equipment be upgraded to take into account of shipping market trends for larger vessels (World Cement, 2004).

62 http://www.thoresen.com/investor/market.asp

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The supply of ships available to meet demand is the other factor influencing the choice of cargo and consequently the freight rates. As illustrated in Table 38, the Handysize sector has been decreasing the most over the past four years. The number of ships being scrapped exceeds the number of those being built (World Cement, 2004). Due to the current age profile of the smaller general cargo and bulk carriers, combined with more stringent regulatory requirements, it is widely expected that the supply of such vessels will continue to decline, at substantial rates, also in the coming years63. Hence, the supply of Handsize ships will become tighter in the future.

Table 38: Fleet in Million DWT and % change year on year

SEGMENT 2000 %

2001 %

2002 %

2003 %

Capesize 92.6 4% 92.6 0% 94.4 2% 100.9 7%

Panamax 72.3 0% 74.4 3% 74.9 1% 75.6 1%

Handymax 49.5 9% 52.2 5% 54.1 4% 57.5 6%

Handysize 75.4 -3% 73.9 -2% 72.5 -2% 72.1 - 1%

General Cargo 23.7 -7% 20.51-13% 19.81 -3% 18.92 - 4%

Total Available 313.5 3% 313.6 0% 315.7 1% 325.02 3 %

Source: Clarkson Research Studies, November 2002; Thoresen, 2003.

Regarding the freight rates, prices have strongly increased since 2003 (see Figure 14). The sharp rise is mainly attributable to the convergence of three factors: an increase in volumes traded (steel and coal mostly) – China raising its volume the most – a strong slowdown in cargo ship construction since the Asian crisis; and the retirement of older ships that no longer meet acceptable safety standards. A series of unrelated events caused rates to rise to unprecedented levels. Firstly, the Chinese coal industry underwent a series of mine explosions, affecting exports and causing coal buyers to seek supply from Australia or Indonesia (World Cement, 2004). Secondly, a cold winter increased the demand for electricity in China from December onwards. Aside from coal and steel markets, low rainfall in Europe during summer 2003 meant reduced electricity from hydro sources and thus a greater emphasis on coal-fired power stations with its consequences on coal imports.

63 http://www.thoresen.com/investor/page3.asp

62

Figure 14: Freight rates on several trade routes (in USD per tonne)

HANDY FREIGHT RATES

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FE R3 steel wire rods US

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EU R4 steel HRC US

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FE R3 JEHSUP steel HRC EU

FE R3 JEHSUP steel wire rods EU

FE R3 JEHSUP aluminium ingots EU

FE R3 JEHSUP paper rolls EU

FE R3 JEHSUP cement Bulk EU

Source: J.E. Hyde.

The future bulk cargo rates may strongly depend on China’s economic situation and raw materials demand (e.g. coal and iron ore). Considering that two years are generally necessary to build a ship, the high freight cost situation is likely to prevail until 2005 but may not cover the entire first period of the EU-ETS. Nevertheless, freight rates may decrease in the coming years if the Chinese government manages to control overproduction in an aim to lower inflationary pressures64 (ABN AMRO). Lower Chinese demand for raw products would have clear repercussions on freight rates.

3.3.2. ASSUMPTIONS FOR FREIGHT COSTS

For the purpose of this report, assumptions were made on the freight costs for each commodity studied. The freight costs have been converted from USD/day to USD/tonne of finished product65. For various routes, we have assumed that the freight rate is identical regardless of the direction. Figure 15, Figure 16, Figure 17,

Figure 18, and Figure 20 illustrate the freight prices for each studied commodity according to the different routes below (Route 1: EU-Far East; Route 3: One Trans Pacific; Route 4: Trans-Atlantic; Route 10: Brazil – EU; JESUP Route 3: Far-East – Atlantic).

3.3.3. COMPARING CO2 IMPACTS ON MARGINAL PRODUCTION WITH FREIGHT COSTS

The aim of this section is to determine how foreign products could compete with marginal production in Europe, i.e., in the extreme case of output whose emissions must be covered at 100% through the purchase of allowances and bear indirect costs via electricity price increase. This requires comparing EU prices of industrial products with the price of similar products that are produced in different conditions, but must carry a freight cost to access EU markets.

64 The Chinese government identified the steel sector as one of the overheated industries and announced mandatory closure of several illegal and/or environmentally unfriendly steel projects. 65 Data available on request.

63

In the following analysis, we rely on forward CO2 prices of EU allowances (vintage 2005). This price is used to compute the total CO2 cost for each product. We therefore indicate price variations over time, for the purpose of illustration only. Figures 17 to 19 show how the total carbon cost – again, measured for marginal output – compares with the freight costs to import cement, paper rolls, and wire rods into Europe from the Far East – Japan to Singapore including China –, USA, and Brazil, in EUR per tonne of finished products.

Unfortunately, data is not readily available on the cost differential between regions for these products, which will be needed to complete this comparison. We also note that competing products from nearer regions (Southern Mediterranean countries, for instance) would probably incur lower freight costs.

Figure 15: CO2 allowance prices with freight costs in EUR/tonne of cement bulk

Source: J.E. Hyde; Modified data from Point Carbon, 2004.

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Figure 16: CO2 allowance prices with freight costs in EUR/tonne of paper rolls

Source: J.E. Hyde; Modified data from Point Carbon, 2004.

Figure 17: Freight costs in EUR/tonne of wire rod steel

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Source: J.E. Hyde.

With such caveats in mind, we find that for cement, paper, and wire rods, freight costs constitute a likely barrier to exports into Europe, a barrier that may not be overcome by the cost of carbon borne by these sectors, at the prevailing price of CO2. For instance, the cost of freight alone is already high in comparison to the cost of producing cement in Europe – 74 per cent if freight cost is at USD40/t. Recall, also, that the carbon cost shown here are upper bounds, as they assume marginal cost pricing

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for all output, whereas the above sections have shown that average pricing in industry is more likely to be the rule.

There are two products that do stand out in this analysis, however. As illustrated in Figure 20, the marginal cost of CO2 would be near freight cost for HRC steel. A full comparison of European and imported steel requires taking into account potential cost differentials between domestic and imported products as well as tariff duties. For example, if an Asian exporter of hot-rolled coil wants to compete today on the European market, taking advantage of its cost advantage – the European price is currently USD490/tonne against USD440/tonne on the Chinese market – it must pay a duty amounting to 23.4 per cent, on top of a USD50/tonne for freight. As illustrated in Table 43, this would give a net price of USD593 per tonne, far above the European spot price and the Chinese domestic price. Lower freight costs, such as those experienced between 1999 and early 2003 (USD20/t instead of 50+ nowadays) would reduce the price differential to USD70 or EUR56, i.e., not enough to give Chinese steel a competitive edge in Europe. For Chinese steel to compute with marginal steel production in Europe, CO2 prices would need to be EUR28/tCO2 on average – assuming that the full carbon cost would be passed through the European steel price (every tonne emitted requires the purchase of an allowance and all electricity is charged at marginal cost including CO2).

Figure 18: CO2 allowance prices with freight costs in EUR/tonne of HRC steel

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Source: J.E. Hyde; Modified data from Point Carbon, 2004

66

Table 39: Simulation of imported steel in Europe from China

ORIGIN CHINA

Domestic price May ’04 (USD/t) 440Tariff cost (23.4%) 103Transport cost (USD/t) 50

Net price in Europe 593EU spot price (June’04) (EUR/t) 490

Regarding imports from countries such as Brazil or the US, their current domestic prices are above European prices (see Annex 5 and Figure 19). Hence, the introduction of a carbon constraint should not modify the attractiveness of the European market under current market prices.

Figure 19: Prices of HRC steel (USD/t)

2004 HRC steel prices

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The competitiveness of European steel on other markets does also depend on the price differential between foreign and European steel, including freight costs to destination and other duties. However, the loss of competitiveness from European products on foreign markets has not been calculated as data is missing on entry tariffs in countries outside of Europe. This aspect is an important factor of the competitiveness aspect and merits further inquiry to obtain a fuller picture of the trade aspects of the EU ETS.

Aluminium stands out on this issue, as a product for which freight costs offer limited protection against foreign competition. The LME price (around USD1800/tonne at the time of this report) is a worldwide reference although there are geographical premiums reflecting logistical constraints and supply-demand situations in every region66. Assuming a full passing on of the CO2 cost into electricity

66 The average levels of the premiums are: US Midwest 85-125USD; Far-East 60-85USD; Europe duty unpaid 30-55USD; Europe duty paid 110-135USD, in all, they represent less than 10% of the net price.

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price – including power generation that is dedicated to a particular smelter – we find that the carbon cost could well supersede freight cost for imports (Figure 20). In this particular case, maintaining market share would imply reducing profit margins. This is consistent with the result of the Carbon Trust study (2004) that concludes that, in contrast with power generation, cement, steel and paper newsprint, the UK aluminium industry would not be in a position to maintain profitability, even for CO2 prices as low as EUR 5/tCO2.

Figure 20: CO2 allowance prices with freight costs in EUR/tonne of aluminium ingots

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Source: J.E. Hyde

How do the results of this section affect our earlier assessment on the effects of the CO2 cost on output demand and competitiveness? First of all, freight costs do matter. For most of the products considered here, they seem to represent a natural barrier preventing imports from gaining market shares in Europe. Under our assumption of a high impact of CO2 costs – direct and indirect cost fully passed on to product prices –, only aluminium would be seriously exposed, even for a fairly low price of CO2. This assumes that power consumed by smelters is charged at the electricity market price and that CO2 cost is fully passed on to the price.

4. FROM COST TO CARBON LEAKAGE

In the context of the EU-ETS, a firm can reduce output to match its free allocation. However, if output reduction is to be avoided, five options are available, although not necessarily to all firms in all sectors. First, if the price of emissions is not significant to a firm’s cost, the effect is minimal and operations are barely affected, i.e. close to BAU. Second, if a firm acts as a price-maker, it can shift the CO2-related cost to its customers. Third, a firm can modify its production process to reduce its carbon intensity, notably via substitution of less carbon-intensive inputs and/or introduction of more carbon efficient processes. Fourth, a firm can relocate part or total production to where it is not subject to the additional carbon cost. Or finally, it can cease operations (Baron, 1997). This section focuses on the most adverse of these situations and the related risk of emission leakage.

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The implementation of an emissions trading scheme will compel industries to include CO2 caps in business plans after reviewing the options available to manage these impacts (e.g. investment in emissions reduction, emissions trading, reducing/divesting operations). If investors forecast a loss in the competitiveness of covered industries, it is likely that the risk premium of the industry will increase. Hence, as an example, a firm’s weighted average cost of capital67 (WACC), the overall required return on the firm as a whole, may increase. Likewise, investors may choose to relocate the production facilities in non-carbon constrained countries with a lower risk premium, although we have seen that transportation cost will play a significant part in this picture, especially if the alternative is between domestic production and a combination of relocation and increased imports. If we take the example of steel, under such a scenario, countries without a CO2 constraint would supply existing mills in the EU with semi-finished products.

There may also be opportunities for certain industrial products in a carbon constrained environment – e.g., a programme to improve buildings insulation could trigger higher demand for glass or buildings material; aluminium may have a competitive edge in the transport sector as demand for lighter and more efficient vehicles increases. Such aspects are beyond the scope of this analysis, which focuses narrowly on industry’s direct GHG emissions and carbon cost impacts, and not on its potential role in a broader GHG mitigation strategy. Neither do we explore the possibility that the carbon constraint could lead to process innovations leading to other sources of competitiveness for these industries covered here68.

Beyond the additional cost that may be imposed on industry, the effect on industry’s competitiveness could lead to relocation which would, in turn, lead to higher emissions than would have occurred otherwise, the so-called carbon leakage phenomenon. Leakage is of importance if it turns out that cost incurred by industry to control emissions – and other parts of society – do not lead to the expected environmental outcome.

Assessing the risk of carbon leakage of European industries, using a model industry – such as the iron and steel sector – requires simulating the specifics of the product market specifics, from inputs to international competition (Baron, 2004). In this section, we focus on the iron and steel sector, for which a number of studies already exist and shed interesting and complementary light on the results shown above.

Gielen and Moriguchi (2002) developed a model69 to analyse the impact of CO2 taxes70 on iron and steel trade. They find that if only Japan and Europe introduce such a tax, their CO2 emissions would indeed decline, but that lower production in these regions would be offset by increased production and emissions elsewhere, with a leakage rate of 35 per cent for a tax of USD12/tCO2, and 50 per cent at USD50/tCO2, by the year 2020. An OECD report (2002) finds that a unilaterally-applied carbon tax of

67 WACC, as the name implies, is the average of the cost of each of these sources of financing weighted by their respective usage. The sector average WACC is the median WACC of all contributing companies ranked within each sector. It is the appropriate discount rate to use for cash flows similar in risk to the overall firm. 68 This hypothesis has been developed by Porter and illustrated in various case studies, as quoted by Greaker (2003). 69 The Steel Environmental strategy Assessment Program developed for the analysis of CO2 emission potentials in the Japanese iron and steel industry. 70 However, the effects of tradeable allowances on industry are different than if the environmental policy were a tax. For steel and aluminium, trade takes place in a world market, where companies are price takers (EU accounts for 17% of global primary steel production). Hence, it is mostly their margins that will suffer if they

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USD25/tCO2 in EU-13 (excluding Finland and Sweden) would lead to a 12% reduction in steel output and a leakage rate of 60%.

The Institute for Prospective Studies (Hidalgo et al., 2002) also developed a simulation model of the world steel industry. Figure 21 shows the size of the production leakage for permit prices ranging from 0 to EUR50/tCO2. Unsurprisingly, the leakage rate increases with the level of the carbon tax.

Figure 21: Estimated production change as a function of the EU15 emission CO2 price

Source: IPTS Steel model (Hidalgo et al., 2002).

According to this analysis, there would be only a 1.87 per cent relocation of production from EU-15 – or 3 Mt of steel for a EUR20/tCO2 price. Other regions would only increase their production marginally. This result is somewhat lower than above-mentioned projections, although time frames differ. The difference may stem from the assumption that scrap prices will remain stable – scrap is the main input in the low-carbon emitting electric arc furnace route. In reality, however, scrap markets tend to be very tight, and prices could strongly increase if the outlook forecasts increases in the arc furnace route. However, freight costs are not taken into account whereas we have shown above that these can help protect EU domestic markets. Hidalgo et al. (2002) also ran a projection of an emissions trading including 27 European countries, resulting in a lower CO2 price overall and a lower cost of compliance for the steel sector.

Note that all of the above studies assume that the competitiveness impact of an emissions trading scheme would be identical to that of a homogenous carbon tax. This assumption is strongly contradicted by our analysis that shows how a grandfathered allocation would have much lower impact on final product prices than a tax applied to the totality of an activity’s emissions. Subject to a tax, a source has no choice but to drastically cut its profits and/or pass on the extra cost to consumers and to trigger a reduction in profit rates and sales volume. Grandfathered allowances give industry the flexibility not to pass on the full opportunity cost of CO2 allowances on to product prices. Hence, the above leakage rates (50%-60% for a tax at USD25/tCO2) should clearly be considered overestimates of the EU ETS impact on the steel sector.

have to pay a tax. With a permit allocated for free – and only a few per cents that have to be bought from the market- the effect on their margin would differ and thus their profitability.

70

Leakage concerns can also be extended to the cement industry, although the risk of relocation is unlikely to affect the entire production process. A potential consequence of a high carbon cost may be the relocation of the most carbon- and energy-intensive part of cement production, i.e., clinker. It is possible that clinker production facilities may be relocated to non-carbon constrained countries bordering Europe such as the Southern Mediterranean countries, for which freight costs may not constitute a major cost barrier. In this case, the only emissions from cement that would be covered in Europe would those associated with power consumption, under the power generators’ responsibility. The indirect cost would therefore remain.

The EU-ETS creates incentives to close least efficient plants. Under certain national allocation plans – such as the UK – when installations covered by the ETS are shut down, allowances already issued are retained up to the year after closure. Hence, allowances worth EUR15/tCO2 on the market and that are distributed for free make the closing of the least efficient plants in the electricity pool a more attractive option than it would have been without the ETS. If a plant with an annual capacity of 4Mt of steel is closed down, the company could receive up to EUR120 million71. Nevertheless, investments will be required to close the plant (e.g. decommissioning and leaning-up costs)72. This means that emissions trading would quicken the pace of planned closures, leading to an overall improvement in the energy efficiency of the remaining capital, without any significant impact on global market shares. Only experience with the scheme will tell us whether carbon costs do influence closure decisions, or trigger closures that would not have been decided otherwise.

5. EXPLORING POTENTIAL PROBLEMS AND SOLUTIONS

The above sections provide insights on the possible economic impacts of the EU ETS on some of the industrial activities covered by the scheme. We have indicated orders of magnitude of cost impacts for average plants including indirect effects via electricity prices; potential effects on product demand under various price assumptions; and the potential role of freight cost when considering overseas competition in these sectors. Specific national circumstances are bound to lead to outcomes that differ from this outlook. In particular, it is difficult to extrapolate our results beyond the medium term, where uncertainty remains about other countries – and/or industry in these countries – adopting emission reduction objectives, with or without emissions trading.

Current expectations are that prices in the EU-ETS are expected to remain low during the first commitment period. In addition, the majority of allowances has been allocated for free and it is not foreseen that this will have a significant impact on trade in these commodities, i.e., lead to production relocation and leakage – although aluminium may be much more at risk than other activities. Should actual carbon prices be significantly higher than those used in the analysis, the impact of competitiveness could become important and call for policy response. The purpose of this section is to present potential problems and solutions discussed in various circles.

The issue of the indirect effect of higher electricity prices has been the subject of much debate. The general perception is that the current market structure in Europe and the practice of marginal cost pricing in power generation will lead to a full pass-through of the carbon opportunity cost to

71 Assuming an integrated basic oxygen furnace with a carbon intensity of 2 tCO2 per tonne of steel. 72 In practice, if the costs of closure are too high, it will never be cost-effective to shut down the plant unless it was close to closure anyway.

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consumers, including industry. Industry itself may not be in a position to follow a similar pricing strategy: an increase in electricity costs would imply squeezing profits and/or output. This potential problem and various parties’ proposals to address it are discussed at some length in the following section. We also touch on specific problems related to the system’s boundaries for emissions measurement as well as process emissions. In closing, we present some thinking on what trade measures have been mentioned as potential solutions to leakage, if it turned out to be seriously threatening CO2 abatement efforts.

5.1. TACKLING THE INDIRECT IMPACT OF EU-ETS

The purpose of emissions trading is to trigger least-cost emission reductions through the introduction of a price attached to emissions. The further and the more transparently this price signal finds its way to consumers, the more efficient emission reductions measures are. In economic theory, this justifies that opportunity cost of holding allowances be passed on to consumers who will, in turn, have an incentive to lower their demand for electricity. Power generators have an incentive to reduce their emissions to reduce their carbon cost and to maintain the attractiveness of electricity with these consumers. While remaining aware of the issue of so-called “windfall profits” that would accrue to generators at the expense of their industrial – and other – consumers, we must not forget that blurring the market signal implies lowering the cost-effectiveness of the scheme. On the other hand, some industry parties complain about the non-competitive nature of current power markets and are worried about the add-on of a CO2 constraint in that context. We do not seek to touch on all these dimensions but must recognise the political dimension of this problem.

As highlighted earlier, it is possible that power prices may increase as a result of the opportunity cost associated with allowances. If the market price for carbon equals EUR10/tCO2, power prices may increase by up to 11 per cent, depending on the passing on range of the opportunity cost associated with allowances. This would in turn increase the production cost for aluminium smelters by up to 2.4-2.7 per cent. Studies concur to project that aluminium would be affected the most via this indirect cost generated by the cap on electricity generators’ emissions. This section presents several conceptual options that have been put forward to limit the increase in power prices as a consequence of emissions trading. Note that not all are compatible with the current design of the EU ETS.

5.1.1. TAXING PROFITS AND RECYCLING REVENUES TO INDUSTRY

Taxing the “increase” in power prices and recycling the revenues raised from allowance auctions to these industries – possibly through reduced tax burdens, could be means EU governments could use to soften the EU-ETS’ indirect impact of the passing-on of opportunity costs onto on power prices for energy-intensive industries. However, determining on which basis the increase in power prices should be calculated can be a challenging task. As power prices fluctuate independently of a CO2 price, isolating the CO2 impact on power prices may not be straightforward. How to recycle tax revenues without favouring any industry in particular may also prove difficult73.

73 Article 87 of the EC Treaty prohibits any aid granted by a Member State or through State resources in any form whatsoever which distorts or threatens to distort competition by favouring certain firms or the production of certain goods. The aid in question can take a variety of forms such as tax relief.

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5.1.2. DIRECT PLUS INDIRECT EMISSIONS

Another option, for the long term maybe, would be to allocate industry, on top of its own allocation, the allowances corresponding to the average content of their projected electricity consumption. Generators, also subject to an emissions cap, would need to purchase their allowances from the market – and primarily from their own customers (Harrison & Radov, 2002). This allocation would be done regardless of which sources were directly responsible for the power generation-related emissions. The facility would then be able to sell any additional allowances at the market price. In all, the so-called indirect cost of increased electricity prices would be partly offset by revenues from sales of allowances to power generators.

As noted by Harrison and Radov, “… recipients of an indirect emissions allocation could also offer electricity generators their (indirect) emission allowances in exchange for discounts on their electricity purchases”.

One drawback of this allocation method relates to the fairness of its distributional impact. A facility may be in a position to pass on the cost increase related to electricity prices, while it has already been compensated financially for this cost, via the sale of allowances (Harrison, personal communication). Since this is quite difficult to predict ex-ante and to disentangle ex-post74, this option could create endless controversy. One of its advantages is that it does not entail a loss of efficiency in the emissions trading system.

5.1.3. BENCHMARKING ALLOCATION FOR THE POWER SECTOR WITH EX-POST

ALLOCATION

Schyns (2004) considers that economic rents in electricity prices can be partly avoided by rate-based trading for power producers. Such a scheme would be based on an EU wide average CO2-benchmark (or) for fossil fuelled electricity; and ex-post control – currently not allowed in the Directive – to base allowances on actual production levels. Under relative targets, allowances are given based on an emission rate per unit of output. Just as typical baseline and credit schemes, allowances could only be sold if reductions from the benchmark take place. If emissions are above the benchmark, then allowances would need to be purchased. Such an allocation mode might prevent over- or under-allocation.

This proposal would reward efficiency and could encourage fuel switching, energy-efficiency, etc. in the generation sector. The CO2-benchmark could be based upon the average CO2 emission of fossil fuelled electricity in Europe. Schyns (2004) estimates that the average CO2 content is around 810 kgCO2 per MWh in Europe. Such a CO2-benchmarking option would penalise coal- or lignite-fired electricity – who generate the highest levels of CO2 per MWh – by the loss of market share by making them buy allowances compared to less emitting power plants. Relative targets would allow for entry and expansion at no extra costs to the source as long as the emissions per unit of output are below the target.

74 It will be difficult to attribute with any certainty a price increase of a given product to an increase in electricity costs. In international markets, supply – demand dynamics will sometimes have a much stronger impact on market prices than the price of any specific input.

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Schyns illustrates how such a system would, instead of penalising all fossil-fuel based generators at the margin, reward cleaner sources and penalise those with emissions above benchmark, although less than a standard cap-and-trade approach.

Benchmarking – be it for the power sector or process emissions – will be very cumbersome and time-consuming to develop. The main barrier to implementing this option would be to find a political consensus on what the average European CO2-benchmark should be. Moreover, relative targets give less certainty to governments about the future emission level of sources covered by their regime and may require adjustments to policies covering other sectors in order to achieve compliance with fixed, absolute national targets. Ex-post control could also raise problems as the uncertainty that comes with ex-post adjustment allocation may be at the expense of market liquidity, and may undermine the efficiency of the market. This is of paramount importance as power generation accounts for the lion’s share of the system’s total CO2 emissions, and could determine whether emission trading is a reliable instrument for industries that need allowances to cover excess emissions.

5.1.4. SEPARATING CO2 PRICES FROM POWER PRICES

This option goes against the conventional wisdom according to which power generators would pass the full opportunity cost of carbon allowances to electricity consumers. Here it is assumed that the only CO2 emission costs generators might pass on to their prices are the ones resulting from the purchase of extra allowances which were not grandfathered75.

Electrowatt-Ekono (2004) has developed a conceptual solution whereby electricity consumers would only pay for the purchased allowances. The grid operator would then charge a fee to all users. This would mean that users paid the exact cost of the carbon (see Figure 22 for details).

Figure 22: Repartition of roles under CO2 price separation from power prices

Source: Electrowatt-Ekono (2004).

During the first year, the emissions allowance fee would be based on the estimation of the cost of purchased allowances and on the forecasted power production. The fee would then be reviewed on a yearly basis in order to cover purchased allowances only.

75 Reinaud (2003) notes that this may also happen in a very competitive market setting in which producers compete for market shares and have an incentive to offer lowest possible prices.

Emission Trading Market

TSO

National Allocations: Free of charge

allowances

Electricity price

Emission allowances

Billing of purchased allowances

Allowance fee

Power producer Power consumers

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This solution potentially entails perverse consequences: the guarantee of being able to recoup any cost related to allowances significantly lowers the incentive to reduce emissions, all the more so as the related increase in power prices may not significantly affect power demand. In the standard setting, peak generators with a high CO2 content could be priced out of the market or consumers could seek alternatives to peak electricity demand. These mechanisms would not operate as efficiently with this option.

Likewise, monitoring and verification issues could also be quite complex. The proposed solution would not necessarily be an ideal one since it would necessitate significant monitoring by the authorities.

5.1.5. TREATMENT OF NEW ENTRANTS IN THE ELECTRICITY MARKET

Another solution to limit a one-to-one passing of the full carbon price onto wholesale would be to encourage greater competition in the power market. If new entrants were encouraged to enter the market, this would allow undermining incumbents’ position and avoid them passing on the full carbon price. One possible answer to rising electricity prices charged to industrial consumers is for them to produce electricity on site (so-called distributed generation, DG), assuming that the economics are favourable. The treatment of new generators in the emissions trading regime is especially important in this respect. We illustrate below that on-site capacity may, in some cases, be under the threshold of the EU ETS coverage (i.e., 20 MW).

Capacity need for an installed generation plant in the cement industry

If the assumptions for a cement plant in Section 2.1.3 were used, the dedicated generation plant would need to produce at least 103 kWh/t. Moreover, if we assume that the plant has a capacity of 1 million tonne of cement per year, annually, the power plant should produce 103GWh/year. Supposing that the power plant functions 8650 hours a year (including maintenance work, etc.), the installed capacity of the generation plant should be 11.9MW. Considering that under the EU-ETS the capacity of the combustion plants needs to be bigger than 20MW in order to have allowances, the power plant would not be considered as a new entrant on the emissions trading market. The operator would not be liable for its emissions under the EU-ETS.

In most cases, DG installations are connected to the grid at distribution-level voltages. Under an emissions trading scheme, the main benefit of distributed generation facilities is that industry would avoid an increase in power costs. On the contrary, owners of distributed generation would be able to arbitrate between consuming their power, and selling it to the grid. If wholesale prices are higher than the rate paid by industry, they could sell it and increase their margin. They could thus benefit from the opportunity costs of allowances, if these were allocated for free. Of course, opting for DG would imply upfront investment expenditures.

Several types of power plants could meet the needs of a specific industrial activity. Distributed generation technologies include gas engines, small turbines, fuel cells and photovoltaic systems (IEA, 2002). Through combined-heat and power (CHP) plants or by renewable sources, distributed

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generation could also have an important role in improving energy efficiency and reducing greenhouse gas emissions.

The concept of cogeneration, in principle, fits well with decentralised power production in industrialised plants and the availability of thermal energy as a by-product could lead to an increased energy efficiency with lower CO2 emissions for each kilowatt-hour produced. Cogeneration could be integrated with the industrial production, hence optimising the overall efficiency. The cogeneration system could be specifically designed for the process needs to avoid the availability of any waste energy that cannot be consumed within the manufacturing plant. Typical value for energy generation efficiency is for an electricity plant around 40-45 per cent; and for an on-site steam plant about 90 per cent. When these two production units are combined to a CHP plant, the efficiency increases to about 93 per cent76. However, CHP is viable only in plant with an adequate power to heat ratio.

While existing cogeneration plants are not always rewarded for their carbon efficiency, at least new entrants can, in some cases, expect support under allocation rules proposed in national allocation plans. Four allocation methods can be distinguished:

• A supplementary bonus allocation to cogeneration installations (Czech Republic, Slovenia, Germany);

• The coverage of 100 per cent of baseline emissions from cogeneration emissions from cogeneration plants (Luxemburg, Sweden);

• A correction factor, which reduces by half the emission cuts usually requested from plant operators (Austria);

• And benchmarking, i.e. allocation on the basis of efficiency or emission standards for electricity and heat outputs (Netherlands, Germany, and Ireland).

Yet the UK and others have not yet defined their benchmarks, and it is not always ensured that they are not only applied to cogeneration installations, but also to boilers and power plants. Yet, only if the NAPs create a distinctive advantage for cogeneration. An example is the Dutch benchmarking model, which applies the same benchmarks to all installations producing power and/or heat, thereby encouraging the most efficient generation mode – cogeneration. The 100 per cent method and the correction factor model should also work to encourage cogeneration.

In summary, how new entrants are treated and how more carbon-saving technology is encouraged may be crucial when dealing with the issue of indirect costs. On the one hand, while there is environmental and economic value in having a clear carbon signal, governments must make sure that existing power generators are not in a dominant position thanks to their grandfathered allocation. New generation with less CO2-intensive technology ought to be in a position to come into the market, to compete with existing generators to restrict their oligopolistic power and put downward pressure on prices as well as on the sector’s overall emissions. On the other hand, controlling overall emission levels also requires a careful treatment of new entrants.

76 Of the energy produced, the share of electricity produced is between one third and a half (European IPPC Bureau, 2000).

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5.1.6. REGULATORY MEASURES

Price caps or limits on power prices’ increase have been announced in two European countries (i.e. Spain77 and Ireland) as a result of the potential consequences of emissions trading. However, such political interventions may potentially discourage investments in the power generation sector. If generators believe that customers will be protected by government intervention from price increases and spikes that are needed to recover fixed costs, then markets may fail to deliver new, potentially more efficient, capacity (IEA, 2003).

5.2. PROCESS RELATED EMISSIONS: THE BENCHMARKING ALTERNATIVE

The cement industry and the steel industry both emit process emissions, on top of their energy-related emissions – although there are clear differences between the pig iron route and the cement industry78. Both industries have expressed difficulties in the short term to reduce those emissions below a certain physical level.

It is clearly important to maintain and incentive to reduce emissions wherever they occur: the purpose of emissions trading is precisely not to predict where and how reductions should take place. It should rather leave full flexibility for emitters to develop their least-cost solution to lower emissions. Exempting process emissions from the emission cap may thus not be the appropriate solution. However, it is important to recognise that a scheme which does not include major emitter nations carries the risk of leakage in the long term. Short of an international regime or agreement covering major international emitters, an agreement among industry players on common mitigation objectives could help reduce such risk. Similarly, at the EU level, it has been argued that a more level playing field may be created if all competitors within an industry were to be allocated allowances based on average national or regional CO2 process emissions performance rate (i.e., a benchmarking or performance based allocation).

A crucial question when using a benchmark or performance-based allocation mode, however, is the product or the level in the production process at which benchmarks will be made. For the steel industry, choosing the CO2 content of steel as the basis for the benchmark favours facilities consuming large amounts of scrap, i.e., electric arc furnace facilities. At present however, the EAF route cannot fully substitute the BOF route since their products differ. Blast furnace plants, much above the benchmark in terms of CO2 per tonne of steel, would need to purchase large quantities of allowances before they can continue operation. A proposed solution may be to go up one level in the production process and benchmark the production of pig iron. However, another issue appears since pig iron can be either produced by 100 per cent coal and ore or by adding scrap, which again lowers the CO2 content of output. By using scrap to make pig iron, the producers emit less CO2. However, the scrap market is limited. A corrective factor could be used to take the amount of scrap into account, for those plants able to purchase it. This would still put pressure on producers to meet the average performance level of available techniques to produce pig iron – and not put the pressure on the

77 Spain’s regulator has made the decision to cap industrial prices at the request of industrials who have complained about “windfall” profits in the power sector. 78 In the steel process, the carbon comes from coke, a derivative of coal. The process is therefore to take a fossil fuel source of carbon, and oxidize in an exothermic reaction to produce CO2. Chemically, this is similar to any other type of combustion process. For cement, however, the source of carbon is in the limestone (not a fossil fuel), and it is not an oxidation process that releases the CO2 from the mineral - energy needs to be added to release CO2, since the carbon is already oxidized in effect within the raw material (limestone is CaCO3).

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purchase of scrap. A benchmark could thus be calculated based on an average European or national CO2 emission rate per tonne of pig iron produced.

By multiplying the CO2 benchmark by the total pig iron production per mill, this would set the benchmark for the industry. Plants which emit above the average would have to purchase the missing allowances, and plants below the average level would receive surplus credits.

Likewise, for cement production, a similar benchmark or performance-based allocation79 could be envisaged since process-related emissions from the calcination of raw materials can be influenced only to a very limited extent in the short term. The benchmark or performance based allocation should be based on cement in this sector –not on clinker80. The reason it that cement can be produced by other materials, and if governments want to cap the sector’s emissions, best is to go as far as possible in the production process. However, should the different types of cement be substitutable, governments may wish to encourage the products which are less GHG emitting.

To make cement, clinker is mixed with gypsum – which regulates speed of hardening. If the clinker-to-cement ratio is 95 per cent, Portland cement is produced. Blended cements can be produced by adding other additives such as blast-furnace slag (a by-product of integrated steel plants) and fly ash (from coal combustion), etc. Approximately half a tonne of slag is generated by the time a tonne of steel is produced. Clinker can be substituted up to a certain level81, which reduces clinker production per tonne of cement output and therefore CO2 emissions.

If allocation were to be based on performance, it would need to take into account the amount of additives (e.g. blast furnace slag). This allocation mode would then isolate the efficiency performance of the cement production process and create incentives to reduce emissions via energy efficiency improvements that may be more readily accessible than process emissions.

There are of course drawbacks in setting an allocation on the basis of a benchmark. Producers that are above the benchmark are immediately penalised for investment choices that were made without knowledge of an upcoming carbon constraint – a free allocation of allowances is precisely the answer to such “stranded costs” (Harrison & Radov, 2002). It is therefore rational to introduce corrective factors – e.g., taking into account scrap consumption in pig iron production. However, because each plant may differ in design and production inputs, setting appropriate benchmarks on process emissions as the basis for allocation may be a costly exercise, and one that needs to be repeated as new technological solutions appear. Of all concerns, the risk of freezing innovation may be the most important: emissions trading is partly an answer to the drawbacks of command and control regulation, whereby economic actors are imposed certain technological choices that may not prove the most cost-effective. In that respect and in a long run perspective, it is not clear whether basing an allocation on specific benchmarks would be superior to grandfathering allowances on the basis of several years emission levels, potentially taking into account the weight of process emissions.

79 Cembureau has agreed on a common performance based allocation formula, the question is whether the benchmarking should be at national/ regional/ European level. 80 Contrary to the steel production process, in the cement process, there is only one production route – although there are 27 types of cement. 81 The overall level of clinker substitution is about 20%. There is potential to reduce it further, the extend depending mainly on lifting the non-technical barriers. One non-technical barrier is that building codes in many countries dictate the chemical and/or physical characteristics of cement used for production. Another barrier is that the additive materials needed may not be available to many cement manufacturers. Like scrap, the slag market is constrained by the production tool.

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5.3. THE CASE OF TRANSFERRED EMISSIONS FROM BLAST FURNACE GAS (BFG) EXPORT

As previously explained, in the primary steel route, the basic materials used for the manufacture of pig iron are iron ore, coke, and limestone. The coke is burned as a fuel to heat the furnace82; as it burns, the coke gives off carbon monoxide, which combines with the iron oxides in the ore, reducing them to metallic iron. Coke gas has significant energy content – with a calorific of 20 MJ/m3. It is captured and is used to produce power.

Likewise, the waste combustible gas generated in a blast furnace when iron ore is being reduced with coke to metallic iron is also commonly used as a fuel within steel works. BFG contains very low amounts of combustibles (20-22 per cent CO) and high amounts of inert elements such as nitrogen and CO2. The calorific value of BFG is relatively low (approximately 3MJ/m³). However, 2-3 tonnes of BFG are generated for each tonne of iron, and since a typical blast furnace may produce 3,000 to 10,000 tonnes of pig iron each day, its potential as a valuable energy source is obvious.

Generally, the integrated plant power mill produces almost all the required electricity consumption for rolling mills and other shops. Using coke gas and BFG instead of natural gas (methane) in the stoves and the boilers, saves fuel costs for operators.

When generating electricity from BF gases, emissions represent five times that of natural gas per kWh83. Hence, the quantity of CO2 allowances for electricity fuelled by BFG based on historical emissions is significant compared to the number of CO2 allowances given to gas or coal power generators. The difference in allowances highlights the importance of to whom the allowances belong.

In the case where the generating facility is the propriety of the steel company, there is no debate. The emission allowances for the power production facility belong to the steel company.

However, there is an issue in the case where the power plant belongs to a different company and the BFG is sold to the owner of that power plant. In its Guidance to assist Member States in the implementation of the criteria listed in Annex III to the EU-ETS, the Commission specifies that “where a waste gas from a production process is used as a fuel by another operator, the distribution of allowances between the two installations is a matter for Member States to decide”.

If a Member State transfers the allowances to the power producer using BFG, the case in one national allocation plan, several situations may occur:

The BFG user can receive a monopoly position in which case it has the right but no obligation to use the BFG as a fuel. If the power producer were to use the BFG and to reflect the associated CO2 into the electricity price, the integrated steel plant would incur this indirect CO2 cost for the BFG;

If there were any malfunctions in the power plant or gas pipe hindering the use of BFG, the steel plant would lose its market for the BFG. It would be left with no choice but to flare it and to purchase allowances to cover resulting emissions;

82 This is true only for integrated plants which have a coke oven. In the case where they do not, they import the coke from another country – from China essentially for Europe. 83 According the IPCC data, modern blast furnace gases emit 281gCO2 per MJ and coke gases emit 95gCO2 per MJ, compared to 56gCO2 per MJ for natural gas and 96 for coal.

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If there were any malfunction of the blast furnace, the power producer would benefit: it would still hold allowances for BFG that has not been used, and could rely on a less CO2 intensive fuel.

This example illustrates that setting the right boundaries on installations’ emissions, which from the basis for the allocation of allowances, is important in the distribution of cost among sectors.

5.4. IMPLEMENTING TARIFFS ON IMPORTED PRODUCTS FROM NON-CARBON CONSTRAINED

COUNTRIES84

The objective of the EU-ETS and the Kyoto Protocol is to engage other countries to develop a broad international approach to reduce emissions. The ideal development would be for a broader set of countries and industry in these new countries to come onboard, so that CO2 capping is no longer an incentive to move production to uncapped regions. However, there may be cases where the threat of leakage is real. Among the options discussed in the literature, there is the possibility of border-tax adjustments, a defensive measure taken to protect domestic industry.

As seen in Section 3.3.1, there may be a risk that European imports could increase as non-carbon constrained companies or countries do not have to bear environmental costs, although current freight prices are effectively a barrier to their penetration into the European market. To eliminate the loss of competitiveness of their industries most exposed to international competition, carbon-constrained countries could decide to correct for the distortion introduced by carbon costs. Since emissions trading raises the cost of production for industry, import tariffs could raise the after-tax price of foreign goods by as much as the cost of allowances and the increase in power prices raise the prices of domestic goods. European producers could thus maintain their market share on the European market85, the risk of leakage would be considerably reduced: competitiveness would be maintained without undermining the environmental goal.

Without debating the implications on international relations of such an approach, the key question is whether such trade measures could withstand challenge before the WTO. The General Agreement on Tariffs and Trade of 1994 (GATT) generally prohibits trade restrictions except under very limited conditions. Likewise, according to the Uruguay Round accords, countries – including European countries – have committed to cut and “bind” their customs duty rates on imports of goods. In some cases, tariffs have been cut to zero. However, Article XX(g) of GATT allows a member to impose measures on imports that relate to the conservation of exhaustible natural resources.86 What remains undecided at WTO is whether a duty could be applied to an imported product on the basis of its “production and process method”: a recent report by the Swedish National Board of Trade (2004) recalls that “it is not clear, however, if inputs [here, CO2] must be physically present in the end product.”

84 Note that the objective of the EU-ETS and the Kyoto Protocol is to engage other countries to develop a broad international approach to reduce emissions, rather than to take defensive measures. 85 Netherlands Bureau for Economic Policy Analysis http://www.cpb.nl/nl/cpbreport/1996_4/s3_1.htm 86 According to Fontaine (2004), what is required to satisfy the four elements of Article XX(g) could be put forward by Europe and a CO2 tax on US imports could be accepted by the WTO. “[4] Subject to the requirement that such measures are not applied in a manner which would constitute a means of arbitrary or unjustifiable discrimination between countries where the same conditions prevail, or a disguised restriction on international trade, nothing in this Agreement shall be construed to prevent the adoption or enforcement by any Member of measures (…). [1] relating to the conservation of [2] exhaustible natural resources [3] if such measures are made effective in conjunction with restrictions on domestic production or consumption”. (WTO, GATT, Article XX(g) (1986); Fontaine, P. J. (2004): “Global Warming: The Gathering Storm”, Public Utilities Fortnightly, August).

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One potential problem in implementing such measure is defining the carbon tax equivalent of an emissions trading system which relies on grandfathered allocation, but also diffuses its economic signal on products that are one-step removed from the source of emissions, such as aluminium. The actual carbon cost incurred in the production of industrial products may be very difficult to evaluate and the source of much controversy when it comes to taxing imports on this basis.

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6. CONCLUSIONS

This analysis provides a set of static estimates of the cost impacts of the EU ETS on some key industrial sectors. It shows that, for the most part, the scheme is not likely to lead to major negative impacts in the near term, although special cases cannot be ruled out. Some of the underlying assumptions of our results highlight key factors in this picture:

• Industry’s ability to pass on the extra carbon cost to consumers is critical. At present, it seems that electricity is the only sector likely to reflect part of the opportunity cost of holding CO2 allowances. Other sectors may be at danger if they adopted a similar behaviour as they compete with producers outside the EU, without a CO2 constraint;

• How power markets will react to the carbon constraint and the corresponding price of CO2 could have strong repercussions on the profitability of sectors like aluminium. The longer term dynamics in power generation and the competitive nature of the markets will also influence this picture;

• Grandfathering does help reduce the competitiveness effects of the EU ETS on cost – the other aspects competitiveness picture is not addressed. At the same time, grandfathering is usually presented as a transitory measure whereby existing capital stock is compensated for the introduction of a new constraint (cf. the issue of “stranded costs”). In the textbook version of emissions trading, sources should eventually pass on the full opportunity cost of emissions so that both producers and consumers adjust their behaviours and emission reductions are achieved at low cost. A careful balance will have to be found to maintain a low impact on international competitiveness, an incentive to reduce CO2 emissions, the incentive for new producers to bring in more innovative production means inside the region, and international market openness.

• It is also important for policy makers to provide as much visibility as possible on the policy framework, given the long lifetime of productive capital in the targeted industries – e.g., total quantity allocated to industry, allocation mode, future structure of the scheme, etc. This would encourage investors to make proper investments in less CO2-intensive capital stock and avoid postponing or discouraging investments in Europe.

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8. ANNEX 1: SHARE OF INDUSTRY’S CO2 EMISSIONS IN EU-15 AND EU-25

Figure 23: Share of Industry’s CO2 emissions in EU

Share of Industry's CO2 emissions in EU15 1990

Non-M etallic M inerals

14.8%

Paper Pulp and Print4.9%

Other industrial activities

53.0% Integrated Iron & Steel25.3%

Non-Ferrous M etals

2.1%

Share of Industry's CO2 emissions in EU25 1992

Non-M etallic M inerals

14.7%

Paper Pulp and Print4.8%

Other industrial activities

53.8% Integrated Iron & Steel24.8%

Non-Ferrous M etals

1.9%

Share of Industry's CO2 emissions in EU15 2002

Non-M etallic M inerals

15.0%

Paper Pulp and Print5.5%

Other industrial activities

56.2%

Non-Ferrous M etals

2.1%

Integrated Iron & Steel21.2%

Share of Industry's CO2 emissions in EU25 2002

Non-M etallic M inerals

14.9%

Paper Pulp and Print5.2%

Other industrial activities

55.1% Integrated Iron & Steel22.7%

Non-Ferrous M etals

2.1%

9. ANNEX 2: IRON AND STEEL

In what follows, we present the characteristics of Eastern and Western Europe steel technology and cost. Note that the report relies on Western Europe technology assumptions.

Table 40: CO2 Emissions from Combustibles and Electricity in a Western Integrated Plant

PIG IRON PRODUCTION AT BLAST FURNACE

Coke rate 325 kg/t pig

Coal rate 160 kg/t pig

ENTAILED CO2 GENERATION

BF Gas combustion 1,356 t eq CO2/t pig

Pig iron C gasification 172 t eq CO2/t pig

Total 1,529 t eq CO2/t pig

BF BURDEN PREPARATION (SINTERING)

Coke rate 35 kg/t sinter

Coal rate 17 kg/t sinter

87

Limestone 130 kg/t sinter

EMISSION 223 KG CO2/T SINTER

Sinter rate 1,500 kg/t pig

COKE MAKING

Coking coal rate 1,280 kg/t coke

CO gas production 350 t eq CO2/t coke

PROCESS EMISSIONS FOR THE BF ROUTE 87

CO gas combustion 132 t eq CO2/t pig

BF gas combustion 1,356 t eq CO2/t pig

Pig iron C gasification 172 t eq CO2/t pig

Sinter plant 335 t eq CO2/t pig

Total 1,995 t eq CO2/t pig

Total 1,930 t eq CO2/t steel

Source: Arcelor, Eurofer

Figure 24: Steel Export Prices from Eastern Europe 2003-06/2004

MB - Steel HR Coil CIS $/Mt

150250350450550650

Jan-

03

Mar

-03

May

-03

Jul-0

3

Sep

-03

Nov

-03

Jan-

04

Mar

-04

May

-04

Source: Datastream; Metal Bulletin.

The price assumption is the 2003 average for export prices of CIS steel, USD280 per tonne of HRC steel – see Figure 24. Note that the average price for 2003 – June 2004 is USD343 per tonne – similar to exports of Western European steel over the same period. The latter price is not used, however, for the same reasons as mentioned in Section 2.1. The capacity utilisation of the plant is 85 per cent and the asset cost per tonne of steel are lower in contrast to the Western plant – essentially resulting from historical costs.

87 According to the “GHG Protocol Initiative”, the carbon emission factor of coal is 0.095tCO2/GJ; of blast furnace is 0.281tCO2/GJ; of natural gas is 0.056tCO2/GJ; of fuel oil is 0.0774tCO2/GJ; of coke oven gas is 0.044GJ/tCO2; and according to the IPCC Guidelines for National Greenhouse Gas Inventories, the carbon emission factor for coking coal is 25.8tC/TJ or 0.095tCO2/GJ.

88

EASTERN EUROPEAN INTEGRATED STEEL MILL

Table 41: Cost Assumptions for an Eastern BOF

Source: CECS.

88 These costs are ‘out of the plant costs’ and do not include certain costs e.g. general overhead, marketing, etc.

Capacity 3.5 Mtonnes

Asset cost 300 USD per tonne

Variables Price 280 USD/tonneCapacity utilization 85% Revenue Volume 2.975 Mt Price 280 USD/t Total revenue 833 USDM Fixed costs Depreciation 10.5 USD/t Labor 30 USD/t Maintenance 14 USD/t Other overhead 8.53 USD/t Variable costs Raw materials (2003 average) 133 USD/t Combustibles 2.33 USD/t Electricity 0.78 USD/t Total costs88 199.1 USD/t 592.4 USDM Profit Turnover 833.00 USDM operating income 240.59 USDM

Operating profit EBITA 28.88%

89

10. ANNEX 3: STEEL TRADE IN 2002

Figure 25: Global steel trade in 2002– China’s importance (tonnes)

Source: IISI, 2004

11. ANNEX 4: CONCENTRATION OF INDUSTRY ON A WORLD-SCALE

Figure 26: Concentration level world-wide

Steel

Plastic

Cement

Aluminium

Iron ore

Industrial gases

Platinum

0

5

10

15

20

25

30

10 20 30 40 50 60 70 80 90

Top 5 - market share (%)

Ave

rag

e E

BIT

DA

mar

gin

(%

)

Source: Exane sourced by Arcelor. Note: This graph does not reflect the latest announcement by Mittal Steel Group, which became the largest producer in October 2004.

90

12. ANNEX 5: WORLD PRICES FOR HRC STEEL (FROM INTEGRATED MILLS)

Figure 27: Price of HRC steel (USD/t)

0

100

200

300

400

500

600

01-0

1-95

01-0

5-95

01-0

9-95

01-0

1-96

01-0

5-96

01-0

9-96

01-0

1-97

01-0

5-97

01-0

9-97

01-0

1-98

01-0

5-98

01-0

9-98

01-0

1-99

01-0

5-99

01-0

9-99

01-0

1-00

01-0

5-00

01-0

9-00

01-0

1-01

01-0

5-01

01-0

9-01

01-0

1-02

01-0

5-02

01-0

9-02

01-0

1-03

01-0

5-03

01-0

9-03

01-0

1-04

01-0

5-04

$/to

nn

e

Chinese Steel HRC

CIS Steel HRC

Brazilian Steel HRC

US Steel HRC

European Steel HRC

Source: Datastream; Metal Bulletin.

91

LEXICON

Benchmarking Comparing aspects of performance (functions or processes) with other practitioners

Blast furnace, Basic oxygen furnace (BOF)

A furnace for smelting of iron from iron oxide ores; combustionis intensified by a blast of air

CEPI Confederation of European Paper IndustriesCost feed-through Passing additional input costs onto product prices Direct emissions Emissions from sources owned or operated by a reporting

installation: combustion, process emissions and fugitive losses Energy-related emissions Energy-related emissions are CO2 emissions connected with the

consumption of energy during the production phase EU-ETS European Emissions Trading SchemeFree on board (FOB) Shipping term which indicates that the supplier pays the

shipping costs (and usually also the insurance costs) from the point of manufacture to a specified destination, at which point the buyer takes responsibility

HRC Hot rolled coil, a product made from the integrated steel route –BOF

IEA International Energy AgencyIndirect emissions In this report: emissions associated with an industry’s use of

electricity, for which it is not accountable Leakage Ratio of emission increase in industry outside the constrained

region and emission reductions achieved inside the region. Leakage may result from: increased capacity use or relocation of installations

Marginal production In this analysis, marginal units for which emission allowances are not allocated freely

Opportunity cost The economic cost of a foregone opportunityOpportunity cost of allowances In theory, the value of carbon emission allowances should be

reflected in the short run generating costs of fossil-fired plants. Any emission from the production of electricity must be offset by an allowance held or purchased on the market. CO2 allowances – although allocated for free – have a real value and thus have to be considered in the short-run marginal cost.

Process emissions Process emissions are defined as non-energy related emissions from the production process

“Windfall profits” Projected increase in power generators’ earnings as a result of short-run marginal cost pricing on power markets when allowances were allocated for free