Kaufmann (1994) observed that there is considerable uncertainty associated with the effect of the expected energy prices on energy demand. The price of primary energy is one of the most important indicators which is used to determine its demand and the level of utilisation in various energy transformation processes. Also, energy prices are affected by carbon taxes imposed on unabated fossil fuel electricity generation processes. Sensitivity assessments have been performed to assess the impact of varying the cost of fossil fuel (gas) and carbon tax by 10 % on unabated gas generation in the N/Gas50 and N/Gas100 scenarios by 2030. The sensitivity assessments on gas plants fitted with CCS technology only apply a 10 % fuel variation as they are exempt from the carbon floor price (DECC, 2012a). The same analysis has not been extended to cover the 200 gCO2/kWh pathway due to its higher decarbonisation target which ultimately favours
unabated fossil fuel powered generation to low-carbon and renewable energy sources. Increasing the cost of gas and carbon on these decarbonisation scenarios neither increases nor decreases the penetration of unabated gas plants in the generation mix nor the electricity generated. The deep cuts in emissions projected by the ‘path to 50 g’ scenario constrains the uptake of gas CCGT to 24.1 GW with a 16.7 TWh generation output when
the cost of gas and carbon is increased or decreased by 10 %. The adoption of a 100 gCO2/kWh decarbonisation target allows a total of 24.9 GW capacity of unabated gas in
the mix to contribute 46.9 TWh to the total electricity demand by 2030. This deployment and generation profile is replicated in this scenario when the cost of gas and carbon is increased or decreased by 10 %. The penetration and utilisation of generation plants using gas fuel remains unchanged in both the N/Gas50 and 100 scenarios compared to the baseline scenarios. This is due to the structural function of the model which sets a minimum capacity within the total gas installed capacity as a safety net designed to safeguard against energy capacity inadequacies. Another potential reason why the level of gas capacity remain unchanged after variations in demand or carbon cost is probably due to the build-up rate set in the model which determines the level of unabated gas capacity in the generation mix. These issues were discussed in detail in Section 3.3.9. The only change that emerges from a sensitivity assessment involving gas and carbon price variations on gas plants is that of the cost of electricity generation, as highlighted in Figure 5.16.
The cost of electricity generation in the N/Gas50 baseline scenario is £0.17/kWh compared to £0.18 and £0.16/kWh following a 10 % increase and decrease in the combined cost of gas and carbon emissions, respectively. On the other hand, the N/Gas100 baseline scenario’s LCOE is about £0.11/kWh, but the cost of electricity generation respectively increases and decreases to £0.12/kWh and £0.1/kWh following a 10 % increase and decrease in the cost of gas and the carbon floor price as shown in Figure 5.16. The difference in the LCOE demonstrated in the N/Gas50 and N/Gas100 baseline scenarios is influenced by the higher load factor, the increased installed capacity and generation output as described in Figure 5.9 (see Section 5.2.3). In all the scenarios, the LCOE from gas plants fitted with CCS remain unaffected by the price variations on both gas and carbon as depicted in Figure 5.16, where the LCOE is maintained at £0.03/kWh.
Figure 5.16. The impact of a 10 % variation of gas and carbon price on the LCOE of unabated gas and gas CCS.
5.2.6 Summary
The UK shale gas development is still at exploration stage. Its use in the electricity generation sector is anticipated in the late 2020s. However, the decarbonisation framework presented by the ‘path to 50 and 100 g’ pathways limits the use of conventional and unconventional gas in the generation mix by 2030. Unabated gas plants under the ‘path to 50 and 100 g’ scenarios are operated at capacity factors below 10%, mainly as back-up up to increased intermittent generation resources within the electricity supply system. Based on this limited operational regime of unabated gas plants in the 50 and 100 gCO2/kWh decarbonisation targets by 2030, the introduction of shale gas in the
generation mix may not alter the low-carbon and renewable energy technology development and deployment framework required to cut carbon emissions.
The benefits of shale gas in the electricity generation could be realised under large decarbonisation targets such as the ‘path to 200 g’ where unabated gas plants are operated at 55 % capacity factor. At a baseload operational regime of 55 %, the unabated shale gas generates 142.8 TWh, and thus limiting the penetration of low-carbon and renewable energy technologies to 7.3 and 56.6 GW by 2030 compared to 17 and 84.8 GW in S/Gas50 in the same period. The scale of low-carbon and renewable energy technology investment under the 200 gCO2/kWh decarbonisation is £135.5 billion compared to £246.4 and £206
billion in S/Gas50 and S/Gas100, respectively. The reduced capital investment likely to be achieved through the increased use of shale gas in electricity generation under the ‘path
to 200 g’ could come at the expense of the UK 2050 emission reduction target as well as the pledge to limit global annual GHG emissions agreed at the Paris COP21 (UNFCCC, 2015).