The large-scale CO2 reductions envisioned to stabilize, and ultimately reverse, global atmospheric CO2 concentrations present major technical, economic, regulatory and policy...
Electric Vehicles and Gas-Fired Power
A strategic approach to mitigating rate increases and greenhouse gas price risk.
to meet load growth. This resource plan also complies with the North Carolina RPS, which requires that by 2021, 12.5 percent of 2020 load be met by a combination of renewables and energy efficiency. 8 The resulting resource portfolio would effectively hold the utility’s level of GHG emissions flat through 2030, despite projected long-term annual average growth of 1.5 percent per year.
Apart from fairly expensive off-shore wind, Duke Carolinas has limited access to renewable energy resources compared to other regions of the country. 9 It has an interest in developing zero-emissions generation through new nuclear power. Nuclear power currently makes up 51 percent of Duke Carolinas’ generation, with over 2,400 MW of additional nuclear capacity planned by 2023.
Duke Carolinas hasn’t historically needed a large amount of flexible load-following generation like natural gas. The predominance of baseload generation in the region means that new EV loads likely will require constructing new power plants, rather than simply increasing the output from existing, under-utilized gas-fired generation, as might be the case initially in other parts of the country.
Figure 2 shows the five future scenarios developed for Duke Carolinas. All of the scenarios, with the exception of “BAU with no carbon price,” assume compliance with the North Carolina RPS, and the same cost per ton of GHG emissions starting at $15/short ton in 2018 and increasing to $50/short ton by 2030. Fuel prices are held constant in each scenario, with coal prices steady at about $3 per MMBtu throughout the study period, and with natural gas prices increasing from about $5.50/MMBtu initially to $7/MMBtu by 2030 (in constant 2010 dollars). The nuclear, hydro, and market purchases are the same in each scenario. The only other variations between scenarios are in total demand due to electric vehicles and the amount of coal versus natural gas generation.
This analysis assumed a dramatic increase in electric vehicles in two of the five scenarios, with 275,000 electric vehicles on the road by 2015 in the Duke Energy Carolinas service territory alone, and 4.7 million EVs in the region by 2030. The low-risk electrification scenario presented here represents a “best case” outcome for the utility in many ways because under this scenario the utility receives 100 percent of the emissions benefits of electric vehicles, while the high-risk electrification scenario represents a “worst case” outcome for the utility wherein the utility receives no credit for the emissions benefits of electric vehicles. The low-risk and high-risk electrification cases thus represent “book-end” cases.
The resulting 2030 generation mix for each scenario is shown in Figure 3. The portfolio in Scenarios 1 and 2 reflect a projection of Duke’s proposed generation portfolio in 2030. Scenario 3 replaces the coal resources in Scenarios 1 and 2 with gas-fired resources. In Scenarios 4 and 5, electric vehicles are assumed to increase in market share rapidly between 2015 and 2030, largely replacing new sales of conventional vehicles. All coal in the region is replaced with natural gas generation by 2024, and new electrification loads are met with new natural gas-fired generation.
Figure 4 shows the