Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
Top Ten Talking Points on Mon Power & Potomac Edison's IRP
1. MP/PE ignores the CPP. No specific plans until DEP imposes requirements.
2. Since Mon Power provides all generation for PE, these are combined under Mon Power.
3. MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027.
4. Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!)
5. Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project.
6. Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020.
7. Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs. Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018.
8. Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012.
9. Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation.
10. New generation could be acquired by building or buying an additional power plant. Co-firing would add "fuel diversity" at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
Top Ten Talking Points on ApCo's IRP (Based on a review of the Executive Summary)
1. ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a "cost of carbon dioxide" of $15-20/ton over a 30-year period.
2. FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited "capacity" potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM's Capacity Performance rule (reserve margin requirements).
3. ApCo assumes average growth in demand of 0.3%, with peak demand increasing 0.2 % annually.
4. ApCo continues operation of Amos and Mountaineer plants.
5. Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026.
6. Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025.
7. Add 10 MW of large-scale solar by 2018.
8. Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total).
9. Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW).
10. Adds 10 MW of battery storage by 2025.
Four Talking Points on Wheeling Power's IRP Based on a review of the Executive Summary)
1. Ignores CPP
2. Assumes growth in demand of 0.4 % and in peak Demand of 0.5 % per year.
3. All of WPCo's capacity comes from 50 % ownership in Mitchell plant.
4. No new resources are proposed, but some demand-side management options may be proposed in the future.
