Climate and Energy Action Plan (CEAP)

3 Table 3 below describes assumptions for the electricity fuel mix. Table 3. Electricity Fuel Mix Assumptions Fuel Source 20156 2030 2050 Explanation Coal 24.5% 20.5% 24.0% Remainder based on other fuel sources Natural Gas 10.7% 14.5% 21.0% Based on previous amount of natural gas (in megawatt hours or MWhs) plus one third of renewables to smooth intermittency Nuclear 3.2% 2.2% 0.0% Assumes existing nuclear with be retired and not replaced Hydro 52.2% 48.5% 30.7% Assumes some loss in generation due to changing amount and timing of water flows Non -hydro renewables 8.8% 13.8% 23.8% Assumes increase in renewables based on RPS, acknowledging that not all of the RPS applies to Ashland Other 0.6% 0.6% 0.5% Kept at 2015 levels (in terms of MWhs) Note: Percentages may not sum to 100% due to rounding. Under this business -as-usual scenario, which assumes full implementation of both federal and state policies, Ashland’s sector -based emissions7 are projected to increase by 6 percent from 2015 levels by 2050 (see Figure 1). When adding consumption -based emissions to the equation, Ashland’s emissions are projected to increase by 12 percent from 2015 levels by 2050 as consumption -based emissions are expected to grow at a faster rate than sector -based emissions due to limited regulatory policies for consumption -related emiss ions. 6 United States Environmental Protection Agency, “Emissions & Generation Resources Integrated Database,” 2012 data. 7 Sectors included in this analysis are ground transportation, building and appliance energy use, and waste and disposal (including refrigerant leakage).