EE 369 POWER SYSTEM ANALYSIS

1. EE 369POWER SYSTEM ANALYSIS Lecture 15Economic Dispatch Tom Overbye and Ross Baldick

2. Announcements • Read Chapter 12, concentrating on sections 12.4 and 12.5. • Read Chapter 7. • Homework 11 is 6.43, 6.48, 6.59, 6.61, 12.19, 12.22; due November 21. • Homework 12 is 12.20, 12.24, 12.26, 12.28, 12.29; due Tuesday, November 26. • Homework 13 is 12.21, 12.25, 12.27, 7.1, 7.3, 7.4, 7.5, 7.6, 7.9, 7.12, 7.16; due Thursday, December 5.

3. Retail Electricity Prices • There are many fixed and variable costs associated with power systems, which ultimately contribute to determining retail electricity prices. • The major variable operating cost is associated with generation, primarily due to fuel costs: • Roughly half of retail costs.

4. Aside: Levelized Cost of Generation,operating costs plus paying off capital. Keep in mind these numbers involve LOTs of assumptionsthat can drastically affect the value, and that many technology costs are site dependent. Source: California Energy Commission: http://energyalmanac.ca.gov/electricity/levelized_costs.html

5. Power System Economic Operation • Different generation technologies vary in the: • capital costs necessary to build the generator • fuel costs to actually produce electric power • For example: • nuclear and hydro have high capital costs and low operating costs. • Natural gas generators have low capital costs, and higher operating costs.

6. Power System Economic Operation • Fuel cost to generate a MWh can vary widely from technology to technology. • For some types of units, such as hydro, “fuel” costs are zero but the limit on total available water gives it an implicit value. • For thermal units it is much easier to characterize costs. • We will focus on minimizing the variable operating costs (primarily fuel costs) to meet demand.

7. Electric Fuel Prices Source: EIA Electric Power Annual, 2006 (October 2007)

8. Natural Gas Prices: 1990’s to 2008

9. Coal Prices: 2005 to 2008 There are fourmain types of coal:bituminous, sub-bituminous,lignite, andanthracite. Heatvalues range froma low of 8 Mbtuper ton to a highof 31 Mbtu per ton.For Illinois coalprice per Mbtuis about$4/Mbtu.

10. Power System Economic Operation • Power system loads are cyclical. • Therefore the installed generation capacity is usually much greater than the current load. • This means that there are typically many ways we could meet the current load. • Since different states have different mixes of generation, we will consider how generally to minimize the variable operating costs given an arbitrary, specified portfolio of generators.

11. US Generation Mix (Energy) circa 2006-2009 • Gen Type US % Illinois % California % Texas % • Coal 48 48 1 36 • Nuclear 19 48 15 15 • Hydro 6 0.1 22 2 • Gas 21 3 50 40 • Petroleum 1 0.1 1 • Other Renewable 3 0.4 12 (14 in 1990) 7 Indiana is 94% coal, while Oregon is 71% hydro, Washington State is 76% hydro. Canada is about 60% hydro, France is also 80% nuclear, China is about 80% coal Source: http://www.eia.doe.gov and Public Utility Commission of Texas

12. Thermal versus Hydro Generation • The two main types of generating units are thermal and hydro, with wind rapidly growing. • For hydro the fuel (water) is free but there may be many constraints on operation: • fixed amounts of water available, • reservoir levels must be managed and coordinated, • downstream flow rates for fish and navigation. • Hydro optimization is typically longer term (many months or years). • We will concentrate on thermal units and some wind, looking at short-term optimization.

13. Generator types • Traditionally utilities have had three broad groups of generators: • “Baseload” units: large coal/nuclear; almost always on at max. • “Midload,” ‘intermediate,” or “cycling” units: smaller coal or gas that cycle on/off daily or weekly. • “Peaker” units: combustion turbines used only for several hours. during periods of high demand

14. Block Diagram of Thermal Unit • To optimize generation costs we need to develop cost relationships between net power out and operating costs. • Between 2-10% of power is used within the generating plant; this is known as the auxiliary power.

15. Generator Cost Curves • Generator costs are typically represented by one or other of the following four curves • input/output (I/O) curve • fuel-cost curve • heat-rate curve • incremental cost curve • For reference • 1 Btu (British thermal unit) = 1054 J • 1 MBtu = 1x106 Btu • 1 MBtu = 0.29 MWh

16. I/O Curve • The IO curve plots fuel input (in MBtu/hr) versus net MW output.

17. Fuel-cost Curve • The fuel-cost curve is the I/O curve multiplied by fuel cost. • A typical cost for coal is $ 1.70/MBtu.

18. Heat-rate Curve • Plots the average number of MBtu/hr of fuel input needed per MW of output. • Heat-rate curve is the I/O curve divided by MW. Best heat-rate for most efficient coal units is around 9.0

19. Incremental (Marginal) cost Curve • Plots the incremental $/MWh as a function of MW. • Found by differentiating the cost curve.

20. Mathematical Formulation of Costs • Generator cost curves are usually not smooth. However the curves can usually be adequately approximated using piece-wise smooth, functions. • Two approximations predominate: • quadratic or cubic functions • piecewise linear functions • We'll assume a quadratic approximation:

21. Coal Usage Example • A 500 MW (net) generator is 35% efficient. It is being supplied with coal costing $1.70 per MBtu and with heat content 9000 Btu per pound. What is the coal usage in lbs/hr? What is the cost?

22. Wasting Coal Example • Assume a 100W lamp is left on by mistake for 8 hours, and that the electricity is supplied by the previous coal plant and that transmission/distribution losses are 20%. How much coal has he/she wasted?

23. Incremental Cost Example

24. Incremental Cost Example, cont'd