MPR Capacity Factor William B. MarcusJBS Energy, Inc.for The Utility Reform Network
Two alternatives • Actual Operating Capacity Factor (60-70%) • Theoretical Availability (about 90%)
Fixed and Variable Costs • Fixed Costs are Incurred regardless of capacity factor • Variable costs increase as operations increase • Cost in cents per kWh declines as capacity factor increases because fixed costs are spread over more kWh of operations
Combined Cycle Economics • Why does a plant only run at 60% of the time when it could theoretically run 90% of the time? • ECONOMICS • Either cheaper power is available the other 30% of the time, or demand isn’t available to keep it running at full capacity, or both.
So what does a baseload renewable avoid (levelized market price in all hours)? • 100% of the fixed cost of a combined cycle • Operating costs of the combined cycle when it would run • Costs that are a maximum of the variable costs of the combined cycle during hours when the combined cycle would not run or would be turned down. • In other words, fixed and variable costs calculated at a 90% capacity factor
Spreading fixed costs over kWh: 9.3 cents/kWh at 60%, 8.5 cents/kWh at 90%
Time Differentiation Doesn’t Help • Lower prices at 3 AM and higher prices at 3 PM are not enough. • The total number before time differentiation is too high, so that prices paid for baseload operation are still too high.
Conclusion • Appropriate payout for baseload or intermittent plant that is not dispatched spreads fixed costs over the theoretical maximum capacity factor for a combined cycle. • Time-differentiated MPR for 30-40% of low load hours should be no more than combined cycle variable cost. All fixed costs should be in 60-70% of hours for time-differentiation purposes. • Only this method gives appropriate value to both baseload plant and plants that can be dispatched downward in off-peak hours.