The Irish TIMES model used in this analysis has a time horizon of 45 years that ranges from 2005, the base year, to 2050, with a time resolution of four seasons with day-night time resolution, the latter comprising day, night and peak time-slices [26]. Energy demands are driven by a macroeconomic scenario, which is based on the ESRI HERMES macroeconomic model of the economy [32], with key drivers extended to the period 2050. On the supply side, fossil fuel prices are based on IEA’s current policy scenario in World Energy Outlook 2012 report [33]. Given the importance of renewable energy for the achievement of mitigation targets, Ireland’s energy potentials and costs are based on the most recently available data. The domestic bioenergy resources are represented by 12 different commodities. The total resource capacity limit for domestic bioenergy – considering both available and technical potential – has been set at 2,887 ktoe for the year 2030 and at 3,805 ktoe by 2050, based on the estimates from [12], [19], [23], [34], [35]. The potential for each individual commodity is shown in Table 2. The upper capacity limit for other renewable resources such as onshore and offshore wind energy, ocean, hydro, solar and geothermal energy are summarized in [31]. The use of geothermal energy in Ireland is limited only to small installations in the residential and services sector mostly for space and water heating purposes. Because solar and geothermal energy contribute marginally to scenarios outputs, no maximum potentials have been provided in the model.

The cost assumptions for domestic bioenergy commodities are based on [36] for biogas from grass, [37] for forestry, [38] for willow and miscanthus crops and delivery costs, and [23] for wheat crops, Oil Seed Rape (OSR) and Recycled Vegetable Oil (RVO). For the remaining commodities, the cost assumptions used in the PET model within the RES2020 project [39] were used. Cost estimates for bioenergy imports are based on [23] international trends. Details are summarized in Table 3. Cost assumptions for bulk renewable energy technologies are based on [40], [41] (for wind energy) and [42] (for solar).

Based on work undertaken by Ireland’s transmission system operator EirGrid [43], the level of intermittent (non-dispatchable) renewable generation – namely wind, solar and ocean energy – is limited here to a maximum share of 70% of electricity generation within each timeslice and to 50% at annual level to account for operational issues associated with such high levels of variable generation in the power system. Regarding policies, investment subsidies and feed-in-tariffs for renewables based on policies currently in practice are assumed here to continue until 2030 and no trading of green certificates is assumed. The installation of new coal power plant capacities are limited to the replacement of current capacity levels, while for wind a maximum installation rate is set at 750 MW per year. Additional information regarding the main input assumptions may be found online at http://www.ucc.ie/en/energypolicy/irishtimes/.

In this analysis we do not model non energy-related emissions associated with agriculture but rather take projections from other sources and use them to exogenously establish the target for the energy system. Set against this backdrop, this paper makes a simple assumption regarding GHG emissions in agriculture, namely that agriculture emissions in 2020–2050 are the same as current national projections (+1% relative to 1990) [44] for 2020. This anticipates growth in agricultural activity in conjunction with the implementation of some level of mitigation.

In this paper results for four distinct scenarios are presented to explore the role of bioenergy in Ireland’s low carbon future. The main scenarios assumptions are listed below:

• Business as Usual (BaU) scenario: it delivers energy system demands at least cost in the absence of emissions reduction targets and efficiency improvements. It is used as a reference case (counterfactual) against which to compare three the distinct mitigation scenarios;

• CO2-80 scenario: the energy system is required to achieve at least an 80% CO₂ emissions reduction below 1990 levels by 2050 (−85.7% relative to 2005). The pathway includes interim targets in line ^§ with the EU 2020 climate energy package [4], [5], i.e. 20% CO₂ emissions reduction by 2020 relative to 2005 levels. Agriculture GHG emissions are implicitly assumed to grow by 4% in the period 2005-2020 [44], while over the period 2020-2050 are assumed constant;

• CO2-80 SC scenario: it delivers the same emissions reduction pathway than CO2-80 scenario, but it simulates how shortages on imported bioenergy commodities consequent with the introduction of the Sustainability Criteria (SC) of the EU Renewable Energy Directive may affect the energy system choices. To simulate the maximum levels of available imported bioenergy, which meet SC requirements, we refer to analysis in Clancy et al. [23]. Assuming a global context of high bioenergy demand driven by the introduction of mitigation targets in several countries, the “Medium supply/High demand” scenario has been used as main reference for the period 2010–2030, as shown in Table 4^**.

• CO2-80 DR scenario: it delivers the same emissions reduction pathway than CO2-80 scenario, but it simulates an energy scenario where, given the growing concerns over sustainability and impacts in terms of Direct and Indirect Land Use Change (DLUC and ILUC) of most of the imported bioenergy crops, the mitigation targets may be achieved only by mean of Domestic Resources (DR), meaning that no bioenergy imports are allowed beyond 2020.

The main scenarios assumptions are summarized in Table 5.

This section firstly presents the CO₂ emissions for the resultant energy systems from the BaU and 80% CO₂ emissions reduction scenario (CO2-80) for the period to 2050. The results show radically different futures. In the absence of emissions mitigation (see Figure 4), the BaU scenario shows the energy system emissions at approximately 53 Mt CO₂ in 2050, representing a growth of 24% relative to 2010 (or 55% growth relative to 1990). By contrast, an 80% CO₂ reduction target means effectively reducing by 87% the projected BaU emissions. In the CO2-80 scenario the greatest reduction in emissions relative to 2010 is in the transport sector (from 19.6 Mt to 1.7 Mt) followed then by electricity generation (from 14.3 Mt to 0.9 Mt).

Figure 4.

Incremental change in CO₂ emission required by each sector in CO2-80 relative BaU scenario and 2010 (Mt)

The evolution of Total Final Consumption (TFC) of energy by sector in BaU and CO2-80 scenarios is presented in Figure 5. Changes in final energy consumption are driven by economic activity (which affects energy service demands), the type of end use energy (including electricity) and the efficiencies of end-use technologies, in addition to consumer response to changing energy prices and to policy measures. There is currently no feedback between the Irish TIMES scenario results and the economy and hence in all scenarios, economic growth (measured in terms of GDP) follows the same trend, growing by 1.9% per annum on average over the period 2010–2050. TFC grows by 0.9% p.a. in the BaU scenario and remain stable (+0.002% p.a.) in the CO2-80 scenario, illustrating the increased decoupling between economic growth and emissions growth.

Table 6 and Figure 5 summarize the primary energy requirements in these alternative energy futures. The projected primary energy consumption in the BaU suggests future trends very similar to current, i.e. substantial reliance on oil and gas with a small share for renewables. The CO2-80 scenario shows a drop in reliance on oil from 2030, coupled with a renewables (wind and bioenergy) expansion. By 2050 liquid biofuels and biogas are extensively used in transport (51%-55% of transport TFC), while biomass is largely used in industry (63% of industry TFC) and buildings (26% of buildings TFC). Coal has all but disappeared from the domestic energy system except for use in industry in combination with CCS technology. Wind energy and natural gas in combination with CCS technology provide an impetus for the electrification of private cars and rail in the transport sector.

Focussing on renewable energy and in particular on bioenergy Figure 6 details the modal results for renewable heat (RES-H), transport (RES-T) and electricity (RES-E) from the energy system cost optimal analysis for the BaU scenario and the CO2-80 scenario. The coloured areas represent bioenergy commodities, while grey pattern bars represent other renewables. In the BaU scenario bioenergy consumptions are dominated by biomass, with 642 ktoe in RES-H while bioethanol dominates in the transport sector (93 ktoe). In the RES-E 46 ktoe are delivered by biogas generation. In the CO2-80 scenario growth of bioenergy consumptions are mainly delivered in the heating sector, where biomass consumption results 2,500 ktoe by 2050 and transport; and transport, which shows an steep increase of biofuel consumption, delivered by bioethanol (33.7%), biogas (28.2%) and biodiesel (28.0%). No bioenergy is hence consumed in the electricity generation sector, dominated by wind generation (94.1% of renewable electricity). In this scenario (CO2-80), renewables account for 61.8% of Gross Fuel Consumption (GFC)^†† by 2050, in which biofuels deliver for 81.4% of transport GFC^‡‡ and 61.4% of thermal GFC.

Figure 5.

Final energy demand by sector in REF and CO2-80 (ktoe)

Figure 6.

Bioenergy consumption by mode in BaU and CO2-80 (ktoe)

This section discusses the sustainability of low carbon future pathways, in particular how the ability of the energy system of delivering deep reductions in emissions levels given the sustainability implications of bioenergy imports. The CO2-80 results are compared with results from the CO2-80 SC scenario (which limits imported bioenergy commodities due to the Sustainability Criteria (SC) of the EU Renewable Energy Directive) and the CO2-80 DR scenario (in which mitigation targets may be achieved only by mean of Domestic Resources (DR)).

Figure 7, which compares bioenergy and other renewables consumption by sector^§§ for CO2-80, CO2-80 SC and CO2-80 DR, shows that restrictions in biofuels and biomass imports have only limited impact on the short term (2020) but may have a larger impact on over the longer term. Reductions in bioenergy levels are only partially replaced with domestic bioenergy resources and other renewable sources (mostly from the power sector).

Figure 7.

Bioenergy and other renewables consumption by sector in CO2-80, CO2-80 SC and CO2-80 DR (ktoe)

Results for the CO2-80 SC scenario indicate that since 2030 bioenergy consumption reduces in all end-use sectors (by about 6% in 2030 and by 19% in 2050 relative to the CO2-80 scenario) while renewable electricity grows (+36% by 2050 relative to CO2-80). Figure 8 shows that in the transport sector the drop in biodiesel imports are only partially balanced by higher domestic biogas production (from grass) (+21%) and increased imports of ethanol (+32%). With respect to heating, electricity displaces biomass and biogas (-20% and -38%) in the heating sectors.

Figure 8.

Bioenergy consumption by mode in CO2-80, CO2-80 SC and CO2-80 DR (ktoe)

The CO2-80 DR shows a similar pattern, but with steeper reduction trends in bioenergy consumption. By 2030 the reduction in bioenergy consumption is 36% lower relative to the unconstrained case (CO2-80) and passes to 53% in 2050. The heating sectors moves further from bioenergy (−42% in 2030 and −45% in 2050) to electricity (+2.5% in 2030 and +76% in 2050) which shows increased levels of renewable generation (+2.4% in 2030 and +70% in 2050 from onshore and offshore wind, solar and some ocean energy). The transport sector (freight and public transport) from 2030 transitions from bioliquids to biogas, while in 2050 about 40% of freight fleet consumes hydrogen (from gasification of coal with CCS).

The results (shown in Table 7) moreover indicate that drops on bioenergy imports cause reductions of the renewable shares (measured as share of total gross energy consumption)^***, which are driven by reduced bioenergy consumptions in transport and heating sectors (where biomass and biofuels are the dominant renewable sources). These limitations do not influence the share in the electricity generation sector, where it indeed grows. By contrast, the reduced bioenergy availability forces the model to adopt deeper efficiency measures causing an increase in end-use efficiency in transport, residential and services sectors.

As third consequence, the results highlight (Table 8) an increase in electricity importance for the end-use sectors. By 2050 electricity grows by 35% (CO2-80 SC) and 67% (CO2-80 DR) respectively relative to the CO2-80 case; and become the most important energy vector for meeting heat demand. The electricity generation fuel mix to meet this increased electricity demand is summarized in Figure 9.

Figure 9.

Electricity generation by fuel in CO2-80, CO2-80 SC and CO2-80 DR

Table 9 highlights the implications of these different mitigation scenarios on another key policy issue, energy security. The analysis here is limited to import dependency, which is a crude and limited metric by which to assess energy security. More details on implications for Ireland’s energy security are assessed in a separate analysis [45]. Focussing first on primary energy import dependency, the results show that the import dependency in the business as usual scenario grows to approximately 93% in 2050, while across the mitigation scenarios reducing trends are shown. Bioenergy contributes in this reduction resulting in all scenarios with lower import dependency indices compared to overall primary energy levels.

The potential growth of bioenergy raises a number of concerns relating to land depletion and implications with one of Ireland’s most important economic sectors: the agri-food sector. These concerns have also been highlighted recently in [24] which shows that the EU Agricultural Policy (Cross Compliance) [46], [47] does not accept that pasture (currently 4 Mha in Ireland) can be ploughed to generate arable land for biofuel production. Ireland is not self-sufficient in grains [19] and as such there would be intense competition for a grain ethanol industry with the likelihood that ethanol production in Ireland would be based on imported grains or at least necessitate import of more grain [24].

This section therefore presents a first attempt on quantifying this impact, presenting modelling results, not only in terms of energy flows or emissions, but also in terms of land consumption. The conversion factors of each individual commodity (Table 10) are drawn from [24], [48], [49]. Crop rotation levels determine the ratio between required and contracted land.

Table 11 summarizes energy crops (including grass) consumptions in the different scenarios converted into land units, namely hectares. Regarding imported commodities, the model does not distinguish between different import locations nor different feedstock crops and hence the following assumptions were made to complete this analysis:

• Imported bioethanol is assumed to originate from optimized wheat crops;

• Biodiesel originates from palm oil;

• Woody biomass originates from miscanthus crops.

Given the total of Ireland’s agriculture land is 4.3 Mha [49], the required land for domestic energy crops in 2030 ranges from 1.4% (in BaU) to 4% (in CO2-80 DR) and by 2050 between 0.7% (in BaU) and 11.9% (in CO2-80 DR) of total agriculture land. Given crop rotation this translates into values shown in Table 11. Equally bioenergy imports by 2050 require the equivalent of 1.8% (BaU) to 28.3% (CO2-80) of current agricultural land.

Currently tillage accounts only for about 0.4 Mha, while the remaining 3.9 Mha are under pasture grassland. Mitigation scenarios therefore indicate that by 2050 to produce methane from grass would require the equivalent of 8% of current grassland area. Energy crops in total (willow, miscanthus, wheat and rapeseed) would require an equivalent between 64% (CO2-80) and 73% (CO2-80 DR) of today’s arable land contracted by 2030 and between 79% and 113% by 2050.

However research in [50] has highlighted that practices such as increasing nitrogen (N) fertiliser input (to the limit permitted by the EU Nitrates Directive) combined with increasing the grazed grass utilisation rate may in future significantly increase the grass resource available in excess of livestock requirements (from 1.7 million t of dry matter (DM) to 12.2 million t DM/annum), limiting the competition with traditional dairy, beef and lamb production systems (reduction in required land for energy uses) and providing an alternative enterprise and income to farmers. This will potentially reduce land use competition by making more land readily available for grass as a feedstock for biomethane production.

One of the main insights that can be gained from the use of energy systems models such as TIMES is from quantifying the impact of different mitigation targets on marginal CO₂ abatement costs, which provide an indication of the costs of abating the last tonne of CO₂ and can be used as a proxy for indicating the level of carbon tax that may be required to reach a certain level of mitigation.

Table 12 summarises the marginal CO₂ abatement costs for the mitigation scenarios presented in this paper. The CO2-80 SC scenario indicates as early as 2030, higher CO₂ abatement prices due to insufficient availability of bioenergy resources. By 2050 this difference becomes steeper, illustrating how bioenergy imports influences the achievement of this challenging mitigation targets. Similarly the CO2-80 DR scenario shows that limitations in import options may forces the energy system to invest in expensive abatement technologies (e.g. hydrogen) which drives the marginal abatement costs at values even higher than the CO2-80 SC case.