Electricity consumption and CO2 capture potential in Spain

Energy 34 (2009) 1341–1350

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Electricity consumption and CO2 capture potential in Spain Luis M. Romeo*, Elena Calvo, Antonio Valero, Alessia De Vita Centre of Research for Energy Resources and Consumptions (CIRCE), University of Zaragoza, Marı´a de Luna, 3–50018 Zaragoza, Spain

a r t i c l e i n f o

a b s t r a c t

Article history: Received 3 July 2008 Received in revised form 23 January 2009 Accepted 30 April 2009 Available online 23 June 2009

In this paper, different electricity demand scenarios for Spain are presented. Population, income per capita, energy intensity and the contribution of electricity to the total energy demand have been taken into account in the calculations. Technological role of different generation technologies, i.e. coal, nuclear, renewable, combined cycle (CC), combined heat and power (CHP) and carbon capture and storage (CCS), are examined in the form of scenarios up to 2050. Nine future scenarios corresponding to three electrical demands and three options for new capacity: minimum cost of electricity, minimum CO2 emissions and a criterion with a compromise between CO2 and cost (CO2-cost criterion) have been proposed. Calculations show reduction in CO2 emissions from 2020 to 2030, reaching a maximum CO2 emission reduction of 90% in 2050 in an efficiency scenario with CCS and renewables. The contribution of CCS from 2030 is important with percentage values of electricity production around 22–28% in 2050. The cost of electricity (COE) increases up to 25% in 2030, and then this value remains approximately constant or decreases slightly. Ó 2009 Elsevier Ltd. All rights reserved.

Keywords: Electricity consumption CO2 emission scenarios CCS

1. Introduction The Spanish economy has experienced an important upward trend in the last two decades. The Gross Domestic Product (GDP) has increased 48.8% in the period of 1990–2004 [1], 14 points higher than the 30 founded Organization for Economic Co-operation and Development (OECD) countries (including Spain). At the same time population has increased 9.4%, more than any other European country with population higher than 20 million inhabitants. This has led to an increase of the emissions of CO2 in Spain during the same period of 57.1% according to the reference approach of the International Energy Agency (IEA) [1]. Despite this data, the CO2 emission per capita in Spain is equal to the average for OECD Europe 7.72 tonnesCO2/capita, much lower than values of Luxembourg (24.94 tCO2/capita), Finland (13.18 tCO2/capita), or Germany, Netherlands, Ireland, Belgium or Czech Republic [1].

Abbreviations: BOE, Government reporter of the State; CC, combined cycle gas turbine; CCS, carbon capture and storage; CHP, combined heat and power; COE, cost of electricity; E, scenario with efficiency increase; E4, Spanish strategy for energy savings and efficiency; GDP, gross domestic product; H, high electricity demand scenario; HH, highest electricity demand scenario; IEA, international energy agency; INE, statistics Spain; L, low electricity demand scenario; M, medium electricity demand scenario; MITYC, Spanish ministry of industry, tourist and trade; MMA, Spanish ministry of environmental issues; NE, scenario with non efficiency increase; OECD, organization for economic co-operation and development; PER, renewable energy plan for Spain; REE, Spanish electricity grid. * Corresponding author. Tel.: þ34 976 762 570; fax: þ34 976 732 078. E-mail address: [email protected] (L.M. Romeo). 0360-5442/$ – see front matter Ó 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.energy.2009.04.035

Under the 1997 Kyoto Protocol, Spain is allowed to increase its CO2 emissions up to 15% of the level of 1990. During the period 1990–2005 there was an important rise in CO2 emissions that led to a peak value in 2005 of 52.2% above the 1990 level [2]. In 2006 the tendency changed and this value was reduced to 48.1% [2]. Improvements in energy efficiency (E4), the use of renewable energy (PER) and carrying out mitigation projects (Clean Development Mechanism, Joint Implementation, Carbon Credits and Emission Trading) have been proposed to reduce CO2 emissions. At present, electricity production represents 24.0% of CO2 emissions and transport 23.8%. The contribution of coal power plants is small, approximately a 14% of CO2 emissions (28% of total electricity production), but according to the National Allocation Plan 2008–2012 [3] one of the measures to stabilize the GHG emissions is reducing the number of emissions rights of these plants. CCS has the potential to combine the security of power generation with low GHG emissions. Therefore, the development of carbon capture and storage (CCS) projects in Spain is essential in order to maintain population and economic development without increasing CO2 emissions and approach Spanish emissions to Kyoto (and post-Kyoto) targets. There have been no studies that analyse the potential of this technology in Spain. This paper is an attempt to fill the gap. The CO2 capture potential on a global scale has been previously presented [4]. Two methods were used to calculate this potential, one based on scenarios for future energy demand and CO2 emissions, and the other based on the analysis of the demand for new power plants in the EU. Results have shown a huge potential for capture

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technologies that could reduce emissions by 25 billion tonnes in the EU by 2050 and 236 billion tonnes on a global level. This value corresponds to 33% reduction in global CO2 emissions compared to emissions today. By 2030 a 20% of the total European abatement potential would be caused by CSS [5], around 0.4 GTCO2/year in Europe and 3.6 GtCO2/year globally. Although these values are essential to highlight the future possibilities to reduce CO2 emissions, it is necessary to calculate the CO2 capture potential in each country. The advantages of a country-specific analyses include the accuracy of data, more realistic assumptions adapted to the developing plan of the country. It should be taken into account the complexity of the economic situation and the history of the countries to obtain realistic future scenarios and useful conclusions. Recently, there has been a growing interest in the evaluation of energy scenarios and CO2 capture potential by countries and regions [4–13]. For example, for Europe, the commercial CCS phase is intended to begin around 2020 with an important learning rate that could lead to a mature commercial phase in 2030 [5]. The role that carbon capture and storage (CCS) technologies could play as CO2 mitigation strategy has been analysed in detail for Germany up to 2030 [6]. Calculations show that the use of CCS can represent an interesting option to reduce CO2 emissions up to 35% compared with 1990 values. The role of efficiency in reducing CO2 emissions in Germany has also been studied with a sectoral approach [7]. There is an important opportunity for efficiency improvement not only in electricity generation but also in road transport, household, industrial and commercial sectors. Primary energy consumption and related CO2 emissions will be reduced in 2050, and results show a cumulative CO2 reduction of 4614 MtCO2 at an average cost per tonne of CO2 reduced of 56 V/tCO2. CO2 emissions, energy consumption and output in France have been examined using cointegration and vector error-correction modelling techniques [8]. Results suggest that output growth causes CO2 emissions and higher energy consumption in the long run. Other investigations use models to calculate CO2 emissions based on population, income per capita, economic structure, final and primary energy intensity per sector, primary fuel mix and emission coefficients [9]. Results for USA show in nearly all scenarios an increase in CO2 emissions up to 2050. The case of the Netherlands has also been analysed [10–13]. One of the main conclusions was that even if nuclear energy is excluded as a mitigation option, CCS can be sufficiently cost-effective in 2020 to avoid 29 Mt per year in the Dutch electricity sector. Strategies to achieve a 50% CO2 reduction in 2050 were also analysed in that paper. However, previous research in this field has been limited to some European countries and USA but none of these studies have

been carried out in Spain. It is the purpose of this paper to provide a detailed calculation of the CO2 capture potential in Spain assuming that there is a huge storage capacity in geological formations. Based on studies of 1996, [14], it is assumed, at least, storage of 1466 MtCO2 in saline aquifer in Spain. In the same study, authors focus the fact that it can be expected that more saline aquifers in Europe may have the potential to store CO2. A recent study [15] updated the storage capacity in Spain up to 14,300 MtCO2 in saline aquifers, 35 MtCO2 in depleted hydrocarbon fields and 200 MtCO2 in coal beds. Fig. 1 shows the general methodology used in this paper. Population, GDP per capita, energy intensity and contribution of electricity to the total energy demand are used to provide the electrical demand scenarios. These scenarios joined with the vintage structure of cumulative installed electricity generation capacity and projected country developments (i.e. contribution of nuclear and renewable energies) lead to future power plant necessities. Calculations have been carried out up to 2050. Predicting energy demand and policies beyond 2050 have large uncertainties and this has not been taken into account. Availability prediction scenarios for the future technologies define the possibility and potential for CCS based on coal. Finally economic and emission evaluation for this potential gives the augmentation of the cost of electricity, the installed CCS power plant and the CO2 emission reduction. 2. Electricity demand scenarios The scenarios for the electricity demand have been calculated according to Eq. (1).

Energy demand ¼ Population 

GDP Energy demand  Population GDP (1)

The energy demand depends on population, GDP per capita and energy intensity (per unit of GDP). We have also assumed that demand is perfectly inelastic because the electricity cost increment will not be high enough to cause an important reduction in energy demand. Each variable has been forecasted in order to propose different scenarios depending on several assumptions discussed below. Once the energy demand is evaluated it is necessary to study the contribution of electricity to the total energy demand. Population increased very slowly from 1990 to 2000. Since 2000 there has been an upward trend in the Spanish population due to immigration, for example between 2000 and 2005 immigrant was 3.2 million inhabitants [16]. Fig. 2 shows population scenarios

Fig. 1. General methodology used for evaluation CO2 capture potential in Spain.

L.M. Romeo et al. / Energy 34 (2009) 1341–1350

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Fig. 2. Population in Spain observed and projected in two scenarios supposing different immigration trends.

based on assumptions by statistics Spain (INE) (scenarios 1 and 2) and Eurostat (scenario 2), [16]. Scenario 1 supposes a constant trend in immigration up to 2010 and then it stabilizes. Scenario 2 assumes a reduction in immigration. Both scenarios include an increase in population. An additional scenario could be included to take into account that Spain is the aim of many tourists from all over the world. It is the second country in number of visitors, after France and the second by volume of sales, after the USA [17]. An increasing number of people are buying holiday homes in the country, where many northern Europeans plan to spend their retirement. These people and the tourists are not included in the population statistics, but they also consume energy. According to the Spanish Ministry of Industry, Tourist and Trade (MITYC) [18] more than 48 million tourists spend an average of 10 days in Spain, so an additional average of 1.5 million inhabitants could be added to the presented population scenarios. This figure represents around a 3% in electricity demand and it has the disadvantage that tourism is concentrated in summer. Despite this data, it has been supposed that a reduction in electricity transmissions losses (around 12%) could be achieved of approximately the same amount in a near future. In consequence, the influence of tourism and improvements in electricity grid compensate each other. The Spanish economy has experienced a high level of growth since joining the EU in the mid 1980s. Since 1990, GDP has been growing by an average of 3% per year. Lately this value is close to the EU-15 values. European Commission assumes a reduction of GDP in EU-15 from 1.8% in 2004–2011 to 1.6% during 2011–2030 and to 1.5% during 2031–2050 [19]. In the case of Spanish it has been supposed this hypothesis could agree with the current trend. A sensitivity analysis shows that reduction of GDP growth only reduce slightly the minimum demand scenario. For this reason this assumption makes the results slightly conservative with higher supply than demand and it is the only scenario considered for this variable. In Spain energy demand and economic growth are still strongly connected. The European Commission assumes an increase around 15% of the final energy demand in EU-25 by 2030 with a growing stabilization by 2020 that leads to a reduction in energy intensity of 1.5% up to 2030. The trend in Spain does not coincide with European Commission scenarios but it seems that reductions around 1.0% could be possible for the future due to different strategies adopted recently to reduce energy intensity. Two possible scenarios are proposed, the first one assumes current growth to 2015 and then a reduction of 1.0% yearly. The second one supposes a reduction of 1.0% yearly from 2008. The combination of two population projections, GDP per capita and two energy intensity trends provides four different scenarios

for the total energy demand. Highest demand (HH) combines highest population trend and low reduction of energy intensity. High demand (H) combines lower population trend and low reduction of energy intensity. Medium (M) and low (L) demand includes higher and lower population trends and high reduction of energy intensity. The contribution of electricity to the total energy demand is used to provide the electricity demand scenarios. Two hypothetical scenarios for the contribution of electricity have been chosen based on work by the European Commission [20]. An efficiency scenario (E), which promotes demand management and energy saving, with the objective to reduce the final energy consumption up to 20% by 2030. A scenario without changes in efficiency (NE) proposes to increase the contribution of electricity with a linear trend. This result in eight possible scenarios obtained through the combination of these possibilities with those calculated for the total energy demand, but two scenarios have been eliminated. It seems unreasonable to have scenarios without reduction of energy intensity and with an increase in efficiency and savings in the use of electrical energy (HH-E and H-E). Calculations for electricity demand show an increase in energy consumption up to 2025 for all scenarios. In HH-NE scenario demand increases 110% up to 53,500 GWh, H-NE and M-NE show an increase around 80%, whereas L-NE increase up to 60% (40,000 GWh). Only scenarios with efficiency increase and savings (M-E and L-E) in the use of electricity show a reduction in consumption from 2025 to 2030. The best scenario with lower increase in population and a reduction of energy intensity and higher efficiencies (L-E) obtain electricity demand values similar to current ones. Lines for scenarios H-NE and M-NE cross by 2035, it is due to the fact that, by 2025 population increase will have a bigger influence in consumption than energy intensity. Three scenarios have been selected representing a high demand (HH-NE) which could be interpreted in the sense of ‘‘business as usual’’, medium demand (L-NE) and low demand (L-E) in order to simplify the analysis of installed capacity, energy produced, CO2 emissions and cost of electricity.

3. Technology potential Once the electricity demand has been calculated, it is necessary to study how this energy is supplied. The Spanish electricity system is highly based on fossil fuels. In 2005, 63.7% of the electricity was generated with fossil fuels (coal 27.9%, natural gas 27.3% and oil 8.5%).

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Coal is used in power plants commissioned mainly in seventies (8000 MW) and eighties (5000 MW) and they are near the end of their life time. Coal also has a steady contribution to the electricity demand since 1999. For this reason the future capacity factor of coal power plants has been taken as the average of the period 1999–2006 (75%, 6570 h/year). Oil installations are used for peak loads and they are not as old as coal power plants. The contribution of fuel/gas is unpredictable because it is used to fit the production and the demand and strongly depends on the weather. Its contribution is not very important and an average capacity factor in the same period has been chosen (9%, 790 h/year). CC using natural gas are installations commissioned since the 1990s. There is an upward trend in the contribution of combined cycles, especially after 2001 due to the increase of capacity. For this reason the average of 2005–2006 has been assumed as the actual contribution of combined cycles to the total energy demand (40%, 3500 h/year). The future capacity factor for CC is assumed to increase from 40% at 2005 to 50% in 2011 (4380 h/year), 59% in 2020 (5170 h/year) and to remain constant at 65% from 2025 (5700 h/year). CHP capacity factor is assumed to increase linearly from 45% in 2006 (3940 h/year) to 67% in 2050 (5870 h/year). Nuclear power plants are also old installations and a phase-out is planned at the end of their life time. Nuclear energy has a constant capacity factor (90%, 7890 h/year) with exception of a slight reduction in 2005 due to maintenance reasons in one nuclear power plant. An average value has been taken for the capacity factor. The contribution of hydro varies strongly depending on the annual weather, for this reason an average for the period 1998–2006 (20%, 1750 h/year) has been considered for the future. In 2004 the capacity factor of renewable energy had an important reduction due to the sharp increase in total installed capacity in Spain of combined cycles. In 2005 the contribution of renewable energy increased but did not reach values of before 2004. An average value for the period 1998–2005, eliminating 2004, has been assumed for current renewable (non-hydro) contribution (18%, 1570 h/year). Future renewable availability is supposed to increase from 18% in 2005 to 31% in 2050 (2720 h/year) due to technological advances as ultracapacitors, and energy storage developments. It is important to notice that in some scenarios there is an important growth in renewable capacity so a strong increase in capacity factor could be an optimistic assumption. In order to obtain a useful scenario for the potential of different technologies it is necessary to take into account the vintage structure of electricity generation capacity, Fig. 4. Governmental strategy for nuclear is to phase-out nuclear power plants by 2030, this date coincides with the end of life of these installations. For coal power plants a life of 40 years is assumed. With this data 65% of these installations will be shut down between 2018 and 2026. Approximately for the same period the phase-out of nuclear plants is planned, that makes these years a critical period to satisfy the electricity demand. CHP will steadily increase depending on the economical situation. Conventional fuel and gas installations will be shut down and replaced by combined cycles with an average life of 30 years. According to the governmental strategy, [18,21], between 2004 and 2011 a capacity increase up to 33,000 MW is planned. The increase in gas prices has lead to an important reduction of CC economical benefits. For this reason it is considered highly improbable to reach this objective, and this data has not been considered as input. Renewable energy requires a detailed explanation. Hydroelectric power is historically the most developed and important form of renewable energy present in Spain. In the year 2000, hydroelectric plants produced approximately 80% of the electricity produced from renewable energies, with an installed capacity of 18,416 MW. In 2004 it only represented 61% of the electricity generation from

renewable energies. This is due to the fact that, the installed capacity of hydroelectric power remained almost constant, while the installed capacity for wind energy increased by almost 6000 MW. The potential for big hydropower plants in Spain is small, and the environmental apprehensions are strong, so it is highly improbable that new big power plants will be built. All new installed capacity will probably be mini-hydroelectric (<10 MW). An increase of 100 MW/year of hydro has been assumed in all scenarios that sums an augmentation of 4400 MW by 2050. It is difficult to calculate the amount of biomass economically available for energy purposes, as biomass also has other uses. It could be economically feasible to use biomass with co-firing in coal power plants, for this reason a maximum rate of new capacity of 1000 MW/year has been supposed. Between 1998 and 2005 the Spanish wind energy sector has seen an annual increase of 42% of installed capacity, going from 835 MW to 9911 MW in 2005, producing 21 TWh, 7.2% of the gross electricity production. Since 2000 the average annual increase has been 1400 MW. In Spain no detailed study of wind potential is available but due to gathered experience and studies taken through by some regional governments, the net potential of off- and on-shore wind energy is considered to be above 40 GW [21]. A maximum increase of 1500 MW/year has been assumed. At present, photovoltaic and solar systems in general are poorly competitive. To allow further development of the market and thus to incentive the learning capacity for this technology, important public incentives are needed. Governmental target is to achieve 500 MW for the year 2010 [21]. A maximum rate of 100 MW/year has been assumed up to 2010 and then it will be increased up to 300 MW/year. Summing up the maximum growth of renewable energies, 100 MW/year of hydro, for biomass 1000 MW/year, 1500 MW/year has been assumed for wind energy and finally 100–300 MW/year has been supposed for solar systems. As a consequence, a maximum new capacity around 3000 MW annually has been assumed for renewables. There are a lot of uncertainties for CCS implementation rates. For this reason it has been supposed different rates calculated to fulfil the electrical demand. It depends on the demand scenario, and usual values are around 600–1000 MW/year. The maximum implementation rate has been 3000 MW/year. This value is in agreement with a high roll-out rate at European level, a yearly capacity addition of 10,000–11,000 MW have been proposed [5]. 4. Results and discussion Table 1 presents a selection of the most important assumptions for the prices of energy carriers, coal and natural gas, [5], and several data of technological options: installation cost and efficiency, cost of electricity and CO2 emissions. These assumptions are shown for different years. Efficiency values represent a technology average taking into account old and new installations. An additional cost of 20 V/tCO2 has been assumed to calculate the cost of electricity from CHP, fuel, combined cycles, and coal technologies. Operation and maintenance costs vary from 15 V/MWh for renewable energy, to 5 V/MWh in combined cycles. It has been assumed 12 V/MWh for nuclear power plants, 6 V/MWh for coal, 7 V/MWh for CCS and 8 V/MWh for CHP. CCS technologies are also included in this table 2020 is assumed as the beginning of the installation of the early commercial phase of CCS [5] as an add-on to existing coal power plant or a new technology that use coal to produce electricity with near zero CO2 emissions. Capacity factor will begin at 40% and is supposed to increase to 70% by 2050, with utilization rates around 86% [5].

L.M. Romeo et al. / Energy 34 (2009) 1341–1350 Table 1 Main assumptions for the prices of energy carriers and data of different generation technologies. 2006 Coal price (V/GJ) Natural gas price (V/GJ)

2010

1.30 2.40

Installation cost (V/kW) Coal Renewables (no hydro) Hydro Combined heat & power Combined cycles CCS

1150 1200 1100 650 500 –

Efficiency (%) Coal Combined heat & power Combined cycles CCS

2030

1.35 2.92 1138 1180 1080 642 492 –

41.0 65.0 54.5 –

2.78 6.08

1078 1080 980 602 452 1820

1018 980 880 562 412 1420

41.8 65.4 55.1

45.8 67.4 58.1 39.5

49.8 69.4 61.1 44.5

52.03 92.03 76.64 45.72 42.97

55.53 69.77 70.94 53.60 51.85 71.91

54.84 56.17 65.23 54.82 54.54 54.13

–

Cost of electricity (V/MWh) Coal Renewables (no hydro) Hydro Combined heat & power Combined cycles CCS

–

–

CO2 emissions (kgCO2/MWh) Coal Combined heat & power Combined cycles CCS

805 305 363 –

789 303 359 –

51.02 98.30 77.79 43.87 42.39

2050

2.38 5.18

721 295 341 84

663 285 324 74

Nine possibilities have been studied. They represent three demand scenarios (HH-NE, L-NE and L-E) and three technological implementation rates. Minimum COE option maximizes the implementation rate of technologies with lower COE (CC and CHP). Minimum CO2 emissions maximizes the implementation rate of renewables and CCS. Evidently, from COE minimization and CO2 minimization there are a lot of possibilities to combine the implementation rates of CC, CHP, CCS and renewables. An arbitrary costCO2 criterion, balanced previous ones, has been proposed. This criterion is defined by the technological implementation rates. The results are the CO2 emissions, COE, capital investment and technological share of power. Tables 2–4 show main results from the balanced scenario for the three electricity demands considered.

Table 2 Main results for the BAU electricity demand scenario and cost-CO2 criteria for capacity installation.

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Table 3 Main results for the L-NE electricity demand scenario and cost-CO2 criteria for capacity installation. L-NE scenario and cost-CO2

2006

2010

2030

2050

Electricity production (GWh)

285,715

340,038

433,768

464,324

Total capacity (MW) and electric production percentage Nuclear 7226 (20) 7226 (17) Coal 11,424 (26) 10,398 (20) Renewable 41,103 (24) 48,503 (25) CHP 6645 (9) 8645 (10) Combined cycles þ fuel 22,144 (21) 27,051 (28) CCS – –

(%) – 1130 73,503 10,645 34,513 7000

(2) (35) (12) (43) (8)

– – 73,815 7000 22,800 18,600

CO2 emissions (MtCO2) Cost of electricity (V/MWh)

91,060 62.66

100,080 63.33

88,360 70.51

62,250 68.45

Year 2050

Renewables

CHP

Combined cycles

CCS

Capacity installed (MW)

71,000

11,750

28,400

18,600

(38) (9) (28) (25)

4.1. Highest demand with Business as usual (BAU) efficiency improvement scenario. Cost-CO2 criterion implementation rates For the HH-NE demand scenario, electricity production has to increase 110% in 2050 with an important growth between 2010 and 2030, Fig. 3. In these years there will be a sharp decrease in capacity due to old installations (coal and nuclear) being taken off the grid. Therefore, this is a critical period and a lot of new capacity has to be installed, Table 2. The contribution of nuclear is decreased from 20% in 2006 to 16% in 2010 and it is phased-out in 2030. Coal power plants are also shut down by 2030 and new capacity of CCS is necessary. 10,200 MW are installed that produce approximately 8% of the electricity in 2030. These values increase up to 29,400 MW, approximately 28% of electricity production in 2050. Renewable energies multiply by 2.5 its current capacity in 2050 up to 106,815 MW. Its contribution increases from 24% to 42% of the electricity production (from 35.7 TWh to 229.6 TWh). The contribution to the electricity supply of CHP and combined cycles in 2050 will be similar to the current values (21% combined cycles and 9% CHP). In 2030 the capacity of these installations have a peak (42,113 MW of combined cycles and 9900 MW of CHP) due to the necessity to fill the important gap of the nuclear phase-out and old coal installation by 2025–2035. CO2 emissions increase up to

BAU scenario and cost-CO2

2006

2010

2030

2050

Table 4 Main results for the L-E electricity demand scenario and cost-CO2 criteria for capacity installation.

Electricity production (GWh)

285,715

348,448

538,087

639,314

L-E scenario and cost-CO2

2006

2010

2030

2050

Electricity production (GWh)

285,715

340,038

363,841

322,815

Total capacity (MW) and electric production percentage (%) Nuclear 7226 (20) 7226 (16) – Coal 11,424 (26) 10,398 (20) 1130 Renewable 41,103 (24) 52,603 (24) 96,503 CHP 6645 (9) 8645 (10) 9895 Combined cycles þ fuel 22,144 (21) 28,651 (30) 42,113 CCS – – 10,200

(1) (38) (9) (44) (8)

– – 106,815 9000 24,000 29,400

(42) (8) (21) (28)

Total capacity (MW) and electric production percentage (%) Nuclear 7226 (20) 7226 (17) – Coal 11,424 (26) 10,398 (20) 1130 Renewable 41,103 (24) 48,503 (25) 61,003 CHP 6645 (9) 8645 (10) 8395 Combined cycles þ fuel 22,144 (21) 27,051 (28) 30,513 CCS – – 5100

(2) (34) (12) (46) (6)

– – 56,815 5000 15,600 11,700

91,060

102,500

103,180

72,720

62.66

63.10

70.86

68.77

CO2 emissions (MtCO2) Cost of electricity (V/MWh)

91,060 62.66

100,080 63.33

76,600 71.44

42,480 69.68

Year 2050

Renewables

CHP

Combined cycles

CCS

Year 2050

Renewables

CHP

Combined cycles

CCS

Capacity installed (MW)

126,400

13,750

39,600

29,400

Capacity installed (MW)

57,400

9750

21,200

11,700

CO2 emissions (MtonCO2) Cost of electricity (V/MWh)

(41) (9) (28) (22)

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Fig. 3. Results for electricity demand scenarios in Spain.

103,818 MtCO2 in 2030 (an increase of 13.3%), Fig. 5, but due to new CCS capacity it reduces up to 72,724 MtCO2 in 2050 (20% lower than actual values). The cost of electricity has a similar trend, Fig. 6, an increase up to 2030 with a peak value of 70.86 V/MWh but this value decreases up to 68.77 V/MWh in 2050, 10% higher than current cost of electricity. There are two reasons that support this result: the first one is that in our calculations is not included the governmental support to the renewable energies, in consequence our COE calculation is higher than real and the 10% increase is for

a COE without subsidies; the second one is that there are not a important contribution of CCS so, although the CCS COE was higher that other options, the average value for the energy system does not increase accordingly. New capacity in the period 2006– 2050 is 209,150 MW, 60% renewable, 6.5% CHP, 19% combined cycles and 14% CCS. Capital cost of this additional capacity amounts to 215,444 million euro. One of the threats in this scenario is the important increase in electricity capacity and production to supply the demand, between

Fig. 4. Vintage structure of electric generation capacity.

L.M. Romeo et al. / Energy 34 (2009) 1341–1350

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Fig. 5. CO2 emissions of the electricity sector in different demand scenarios for the option of a balanced scenario between COE and CO2 emissions.

2006 and 2010 an augmentation of 4.75% in electricity production. Then, stabilization and an annual increase of 1.5%. There is a strong pressure to the development and installation of renewable energies in order to increase its contribution to energy demand. This could be one of the uncertainties, whether renewable energies are capable to supply the projected demand or not. Finally in this scenario, CO2 emissions reduces between 2030 and 2035 and remain nearly constant with values below 80,000 MtCO2, Fig. 5. 4.2. Lowest demand with BAU efficiency improvement scenario. Cost-CO2 criterion implementation rates For the L-NE demand scenario, electricity production will have to increase 80% in 2050. Again the period between 2010 and 2030 is critical with a strong augmentation of electricity demand. In this scenario the development of renewable energy is more uniform with new annual capacity around 2000 MW until 2030 reaching at

73,500 MW of installed capacity and a contribution of 33% to electricity production, Table 3. These values remain constant up to 2050. CCS contribution is smaller with an installed capacity of 7000 MW in 2030 and 18,600 in 2050, the contribution to the electricity production is 7% and 25% respectively. Again the contribution to the electricity supply of CHP and combined cycles in 2050 is similar to the current values with a peak in 2030 (45,158 MW). CO2 emissions increase up to 100,082 MtCO2 in 2010 (an increase of 9.9%), Fig. 5, but the low increase in electricity demand and the use of renewable energy reduces this value to current values in 2030. In 2050 with the contribution of CCS it will reach a minimum of 64,433 MtCO2 (reduction of 30%). The cost of electricity has similar values to those presented in the previous scenario, with a maximum in 2030 of 70.51 V/kWh and a reduction in 2050 to values 10% higher than current cost of electricity, Fig. 6. New capacity is smaller than BAU scenario, 129,150 MW have to be installed, 55% renewable, 9% CHP, 21% combined cycles and 14% of

Fig. 6. COE of the electricity sector in different demand scenarios for the option of a balanced scenario between COE and CO2 emissions.

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CCS. Capital cost of this additional capacity sums up to 135,968 million euro. 4.3. Lowest demand with highest efficiency improvement scenario. Cost-CO2 criterion implementation rates The last scenario analysed is a low demand and efficiency case. In the L-E scenario there are reductions in electricity demand from 2015. As a result, the electricity production in 2050 only increases 13% compared to the 2006 value. It is a more desirable scenario due to smaller new capacity installation rates than previous ones. Renewable energy contribution is similar to previous scenarios but the capacity in 2030 is 61,000 MW, Table 4 (35,000 MW less than in BAU scenario and 20,000 MW more than 2006 values). In 2050 there will be a slight reduction in capacity due to a reduction in electricity production. In this case the contribution of combined cycles and CHP remains unchanged but capacity is lower with values around 40,000 MW in 2030 and 20,500 MW in 2050. Also CCS technologies have a lower capacity 5100 MW in 2030 and 11,700 MW in 2050, with a contribution to energy production of 6 and 22%. There is also a peak in CO2 emissions in 2010, Fig. 5, but drastic reductions will be achieved between 2018 and 2038 reaching a minimum in 2050 of 42,478 MtCO2, a reduction of 54%. Cost of electricity has a similar trend to previous scenarios but values are slightly higher. The relative contribution of renewable energy increases the cost up to 71.44 V/kWh in 2030, around 0.5 V/kWh higher than BAU scenario, Fig. 6 New capacity amounts 100,050 MW with a similar contribution as in previous scenarios. Capital costs are reduced in this case to 99,779 million euro a 45% of the BAU scenario. 4.4. Different implementation rates. Minimum COE and CO2 emissions Two additional cases have also been analysed, a minimum electricity cost and a minimum CO2 emission in electricity production. The minimum COE option leads to an important increase of combined cycles and CHP reducing the contribution of renewable energy and coal (also CCS) to a minimum. Renewable capacity reaches a maximum in 2010 with 48,503 MW and 25% of electricity production. These values reduce to 38,503 MW and 14–21% in

2030, and 22,815 MW and 6–13% in 2050, the values of electricity production depending on the BAU, L-NE or L-E scenario. There is no deployment of CCS in any scenario. Combined cycles and CHP contribution to electricity production reach values around 90% with a new capacity installed above 130,000 MW in BAU scenario and 60,000 MW in L-E scenario. Beside these values, cost of electricity is not reduced considerably, minimum cost obtained is 58.89 V/MWh in 2050. The strong importance of combined cycles leads to obtain cost of electricity values very close to values presented in Table 1 for combined cycles. For 2030 the cost of electricity has values ranging between 62.7 and 66.4 V/MWh. Finally CO2 emissions increase in nearly all scenarios. Although specific emissions of combined cycles are smaller than coal, the reduction of nuclear, renewable and CCS increase the global CO2 emissions. In a BAU scenario, CO2 emissions reach 191,890 MtCO2 an increase of 106% compared to the 2006 values. Also in L-NE scenario there is an increase of 50%. There is a reduction of 3% in only L-E scenario in CO2 emissions due to the reduction of electricity production. Capital cost in the option of minimum cost is also minimum because the price of combined cycles and CHP are smaller than renewables and CCS, ranging from 152,000 MW (9% renewable, 26% CHP and 64% combined cycles) and 84,300 million euro for a BAU scenario and 75,700 MW (19% renewable, 22% CHP and 59% combined cycles) and 46,629 million euro for L-E scenario. The minimum CO2 emissions option leads to an important increase of renewable energy and CCS reducing the contribution of combined cycles and CHP to a minimum. Renewable capacity reaches a maximum in 2030 with values ranging between 97,500 and 75,500 MW in BAU and L-E scenarios with electricity production between 40 and 60% depending on the deployment of CCS. In this case, the installation of CCS for base demand is essential and the implementation rates of renewable and CCS does not depend on cost, but strategic reasons and security of supply in electricity production. CCS in 2050 ranges from 24,000 MW in L-E scenario to 67,500 in BAU scenario. As a result, CO2 emissions in 2050 are strongly reduced to values between 30,694 MtCO2 in BAU and 10,914 MtCO2 in L-E (reduction of 90%), Fig. 7. Even in this case, CO2 emissions will not decrease until 2018 when old coal and fuel installations reach the end of their operation and are replaced by new renewable and CCS power plants to supply electricity. It is also important to notice that the cost of electricity does not increase sharply, values are higher than any previously presented but

Fig. 7. CO2 emissions of the electricity sector in different demand scenarios for the option of a maximum CO2 reduction.

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differences do not eliminate this option. By 2030 COE in any scenario is around 74 V/MWh (20% higher than actual ones) and in 2050 varies between 71 and 75 in BAU and L-E scenario. The only disadvantage in this case is the capital cost. New installed capacity ranges from 228,000 MW (50% renewable, 3% CHP, 17% combined cycles and 30% CCS) with 254,300 million euro investments for a BAU scenario and 113,500 MW (72% renewable, 2% CHP, 5% combined cycles and 20% CCS) with 136,738 million euro for L-E scenario. 4.5. Sensitivity analysis A sensitivity analysis has been carried out for the carbon cost in all the nine possibilities studied. The cost of the carbon market has been calculated for 10, 20 (reference), 30 and 50 V/tCO2. In general, an augmentation of 10 V/tCO2 in carbon cost increase the COE of the overall electricity system in 2.5 V/MWh for the peak values in 2030, and 1.5 V/MWh for the values of 2050. This value increases scope for CCS deployment and renewable profitability. The influence of carbon price is slightly lower in L-E scenario and CO2 option due to low electricity demand and low emissions. This influence is not representative in scenarios based on renewables and CCS (minimum CO2 and cost-CO2 criterion). In these cases COE is high enough to allow CCS and renewable deployment implementation rates. Only in the option of minimum COE, the future implementation rate of CC reduces and CCS and renewables increase its contribution.

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with COE around 70 V/MWh. New capacity up to 2050 increases between 100 and 210 GW with a capital cost of 100,000–215,000 million euro. In our calculations, we have assumed that sufficient storage capacity is available and that the necessary infrastructure for CO2 transportation can be established in the period of time considered. Moreover, it is also assumed that CCS will be commercially available from 2020. In conclusion, a reasonable recommendation to the people responsible for Spanish Electricity Planning in order to decarbonize the electricity production in Spain by 2050 would be the support of a renewable energy and a strong development of CCS, RþD projects in a near term, pilot plants and demonstrations units in a medium, and deployment from 2020. Spain should invest in renewables at a minimum rate of 1500–2000 MW/year up to 2040, and 800–1000 MW/year of CCS from 2020 to 2040. This would imply yearly investments around 2000 million euros/year up to 2020 and 4000 million euros/year from 2020 to 2040. CO2 emissions due to electricity production would be 33% below the 1990 level with an average CO2 emissions reduction of 650 MtnCO2/year. A wise combination of energy efficiency savings both on the supply and demand side, the steady and realistic increase of renewables (with energy storage) and CCS technology would help Spain reach zero emission power by 2050 as described in the paper. None of these three technologies alone will be sufficient to reach this objective. Acknowledgements

5. Conclusions In this paper we present several scenarios for the electricity demand of Spain. These scenarios have been calculated taking into account population, income per capita, energy intensity and structure. Actual data and technological implementation plans in Spain have also been included as inputs to achieve realistic future scenarios and useful conclusions. In a BAU scenario electricity consumption increases up to 110% in 2050, and 60% in a scenario with medium population-economic growth and reaches current values in 2050 with an efficiency scenario combined with medium population-economic growth. These scenarios have been used to analyse the possibilities of new generation capacity (coal, nuclear, renewable, CCS, CC and CHP) up to 2050. Three options for new capacity have been analysed (minimum COE, minimum CO2 emissions and cost-CO2 criterion). Although quantitative results are different, calculations show that CO2 reductions are achieved around 2030 in a cost-CO2 criterion option and in 2020 in a minimum CO2 option. No significant reduction of CO2 emissions in 2050 is achieved in a minimum COE option. Reduction of CO2 emissions in 2050 could reach 90% in an efficiency scenario with medium population-economic growth combined with minimum CO2 option. COE in this situation (75 V/MWh) is 25% higher than a minimum COE option for the same scenario (60 V/MWh). The energy sources contributing will be around 50% renewables and 50% CCS, for this reason the new capacity will be between 113 and 228 GW with a capital investment cost between 135,000 and 254,000 million euro. In this situation the development of energy storage for renewables will play an essential role, the quantification of storage is out of the scope of this work. Although the COE of CC/CHP are similar to CCS in 2050, in a minimum cost option the contribution of CC and CHP is relevant, around 80–90% and 10% of renewables. New capacity requirements are between 75 and 150 GW with the lower capital cost (45,000– 85,000 million euro). Cost-CO2 criterion shows reduction of CO2 emissions from 2025 to 2035 (depending on electricity demand)

The authors are grateful for the financial support from the Spanish Government, without which, this work could not have been undertaken. The work described in this paper was supported by the RþD Spanish National Program from the Spanish Ministry of Science and Education under the project ENE2004-06053, Cuasi-zero CO2 emissions power plant technologies research. The Spanish case. The work of the Technology Platform for Zero Emission Fossil Fuel Power Plants (ETP-ZEP) is also acknowledged. References [1] International Energy Agency, IEA. CO2 emissions from fuel combustion, 1971–2004. OCDE/IEA; 2006. 2006 edition. ˜ a 2006, [2] MMAMinisterio de Medio Ambiente. Perfil Ambiental de Espan Informe basado en indicadores; 2006. [3] BOE. Plan Nacional de asignacio´n de derechos de emisio´n 2008-2012. BOE nu´m. 284, 27 noviembre, 2007. p. 48609. [4] Stageland A. A model for the CO2 capture potential. International Journal of Greenhouse Gas Control 2007;. doi:10.1016/S1750-5836(07)00087-4. [5] Naucle´r T, Campbell W, Ruijs J. Carbon capture and storage: assessing the economics. McKinsey & Company; 2008. [6] Martinsen D, Linssen J, Markewitz P, Vo¨gele S. CCS: a future CO2 mitigation option for Germany? A bottom-up approach. Energy Policy 2007;35:2110–20. [7] Blesl M, Das A, Fahl U, Remme U. Role of energy efficiency standards in reducing CO2 emissions in Germany: an assessment with TIMES. Energy Policy 2007;35:772–85. [8] Ang JB. CO2 emissions, energy consumption, and output in France. Energy Policy 2007;35:4772–8. [9] Tol RSJ. Carbon dioxide emission scenarios for the USA. Energy Policy 2007;35:5310–26. [10] Van den Broek M, Faaij A, Turkenburg W. Planning for an electricity sector with carbon capture and storage. Case of the Netherlands. International Journal of Greenhouse Gas Control 2007;. doi:10.1016/S1750-5836(07)00113-2. [11] Van den Broek M, Faaij A, Turkenburg W. 2006. Timing is a crucial factor in a CCS development pathway. The case of the Netherlands. 8th International Conference on Greenhouse Gas Control Technologies, Norway. [12] Damen K. 2006. Developing strategies for large-scale implementation of CO2 capture and storage: a case study for the Netherlands. 8th International Conference on Greenhouse Gas Control Technologies, Norway. [13] Koornneef J, Faaij A, Turkenburg W. 2006. Environmental Impact Assessment of Carbon Capture & Storage in the Netherlands. 8th International Conference on Greenhouse Gas Control Technologies, Norway.

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