Assessing “gas transition” pathways to low carbon electricity – An Australian case study

Future generation portfolios including varying quantities of gas-fired and renewable generation were compared on the basis of expected costs, cost risk and greenhouse gas emissions, with a view to understanding the merits and disadvantages of gas and renewable technologies. A Monte-Carlo based generation portfolio modelling tool was applied to take into account the effects of highly uncertain future gas prices, carbon pricing policy and electricity demand. Results suggest that portfolios sourcing significant quantities of energy from gas-fired generation in 2030 and 2050 are likely to be significantly higher cost and significantly higher risk than the other alternatives considered. High gas portfolios also do not achieve the greenhouse gas (GHG) emissions reductions levels that appear required to avoid dangerous global warming. For example, portfolios that source 95% of energy from gas-fired generation in 2050 experience expected generation costs that are $65/MWh (40%) higher than portfolios that source only 20% of energy from gas-fired generation. These high gas portfolios also exhibit a cost risk (standard deviation in cost) that is three times higher. The lowest cost portfolios in 2050 source less than 20% of energy from gas with the remaining energy sourced from renewables. Even in the absence of a carbon price, the lowest cost portfolio in 2050 sources only 30% of energy from gas-fired generation, with the remaining 70% of energy being sourced from renewable technologies. Results suggest the optimal strategy for minimising costs, minimising cost risk and reducing GHG emission levels in future electricity industries may involve minimising energy sourced from gas, and increasing renewable generation. In the Australian case study considered, the modelling suggests it is appropriate to target renewable energy penetrations approaching 60% of energy by 2030 and 80–100% by 2050. In the lowest cost and lowest risk portfolios, firm capacity is provided primarily by the transition of existing coal-fired plant into a peaking role, and later by further investment in peaking open cycle gas turbine plant. These results are found to be robust to a wide range of assumptions around future carbon prices.