1. Kevin Harris, ColumbiaGrid TEPPC\Model Work Group - Chair
MWG Identified Area of Model Improvement to TAS Salt Lake City - January 30, 2017
Kevin Harris, ColumbiaGrid
TEPPC\Model Work Group - Chair

2. Overview Hydro Operation Modeling CC as 1x1 Heat rate review
Dispatch PLF to Load – Solar –Wind
The use of fixed hourly shape
Modeling of the Core Columbia River
Hydro Dispatch to Multi Regions
Modeling CC as 1x1
Heat rate review
Non-Dispatchable Supply
Maintenance
Other Items
What do we Model?

3. Hydro Issues

4. Hydro Dispatch: Load – Solar - Wind
Currently: Hydro is dispatch against load
Problem: Load – Solar shapes results in radical shift in daily load pattern which dispatchable Hydro is not responding to
Shift CA Hydro to respond to net load (Load – Solar)
Hydro supporting afternoon ramp instead of contributing to the problem
Recommendation:
Solar Coefficient Factor:= 1 (100%)
Wind Coefficient Factor:=
Northwest:=0; other area?

5. Hydro Dispatch: Hourly Shape
Currently: Many Hydro units in California are modeled with a fixed hourly shape
Problem: They are capable of shifting generation to correspond to load - solar
Switch these plants from “Hourly Shape” to “Load Following” (PLF only) allows them to respond to the net Load - Solar

6. Hydro Dispatch: Hourly Shape
Example Modeled Hydro gen (WAPA): Judge F Carr, Spring Creek, & Folsom
If op flexibility still exist peaking capability by increase.
Example: Shifting 8 hrs of peaking into 6 hrs results in a 33% increase in peaking capability
Fixed hourly shapes peak mid-day
New daily peak
On average this change would support 200 MW of the afternoon ramp

7. Modeling Core Columbia River
Currently: The Core Columbia River is modeled as PLF with some HTC
Problem: HTC increase in operational flexibility by shifting generation from the morning to the afternoon ramp
Recommend switch modeling of Columbia River with PLF only

8. Hydro Dispatch: Multi Regions
Currently: Some Hydro is dispatch to multi regionals
Problem: Currently procedure in GridView makes it difficult to calc the appropriate K Factor
Minimize the use of this feature or iterate on solving appropriate K Factor

9. Modeling of Combine Cycle
Currently: CC are modeled as whole plants, i.e. 2x1 Redhawk CC modeled as 482 MW
Problem: Commitment is preformed by CT
Switching modeling to 1x1 configuration allow additional operational flexibility in meeting California duck curve
Switching modeling to 1x1 configuration allow additional operational flexibility in meeting California duck curve

10. Full Load Heat Rate Review
Problem: Continue to find units with heat rate issues
Example:
Carlsbad LMS full load heat rate
v1.5: 10.7 MMBtu/MWh
V1.7: 6.1 MMBtu/MWh
LMS Generic: 8.8 MMBtu/MWh
Carlsbad min generation
Min rating 20%
Gas turbines cannot operate below load and be NOx compliant
Las Vegas CG 2&3 full load heat rate: 6.65 MMBtu/MWh
LM6000 base CC ~ 7.9
GT/CC with 5-6 heat point blocks

11. Non-Dispatchable Supply

12. Non-Dispatchable Supply
Non-Dispatchable supply is not limited to just wind and solar
Other types of Non-Dispatchable supply: Geothermal, Cogeneration, Biomass, Land Fill Gas,..
Currently: These units are modeled as dispatchable supply: heat rate curve, fuel cost, dispatch range (min-max rating)
Problem: This result in non-dispatchable supply responding to price signals in the whole sale electric market

13. Non-Dispatchable v1.5: Geysers
Average annual generation (aMW)
Modeled: 907
Historic 5 yr avg: 534
Diff in gen: 373 (+70%)
Hourly generation profile shows a significant amount dispatchability
Note: Modeled capacity is close to nameplate

14. Non-Dispatchable v1.7: Geysers
Average annual generation (aMW)
Modeled: 572
Historic 5 yr avg: 534
Diff in gen: 38 aMW (7%)
Hourly generation profile does not reflect historic operation

15. Non-Dispatchable v1.50: Sycamore CG
Average annual generation (aMW)
Modeled: 277
Historic 5 yr avg: 159
Diff in gen: 118 (+74%)
Hourly generation profile shows a significant amount of dump energy

16. Non-Dispatchable v1.70: Sycamore CG
Average annual generation (aMW)
Modeled: 73
Historic 5 yr avg: 159
Diff in Gen: -86 (-54%)
Hourly generation profile shows a significant amount of dump energy

17. Non-Dispatchable
Economic of non-dispatchable supply is independent of the whole sale electric market
Making it dispatchable makes it difficult to control
Small changes in fuel cost changes how the units dispatches

18. Re-evaluate Maintenance
With load minus solar and wind changes when maintenance can be preformed
Example: Intermountain 1 & 2 ran an avg of 0.9 units between 3/13 to 6/17 (Sched maint in fall)
Given little op in spring should maint be shifted to spring?
Other Issue
Annual CF 39% but min fuel take ~50-70%
Should fix cost be taken out of modeled coal cost?
Two weeks maintenance per year?

19. Other Items Pancake wheeling cost
Impedes exchange of power on the market
Modeling of CAISO CO2 tax with asset controlled supply
Explore an hourly method to implement
PAR’s operation
Problem: Consistently appear as a binding path in WECC analyst
If PAR is properly operated the path is not binding

20. An efficient market vs a power market?
What do we Model?
An efficient market vs a power market?
Do we model
An efficient single owner market?
A wholesale power market with 38 balance areas?
Problem: We pick and choose modeling assumption independent of a clear understanding of what market we are modeling
Solution: We need a clear definition of what type of market we model in the Base Case

21. Cycling of CC Outside of CA
CC outside of CA are starting mid-day in response to duck curve
Est cost of start outside of CA (SW + NW)
$172M/year
$471k/day
Start are the difference between Max(HE 17-22) – Min(HE 12-16)

22. What do we Do?
Do we apply constraints to minimize mid-day start of CC outside of California?
Do we model an efficient market
If so, what rules do we enforce and ignore in the base case?
When market issues are found what do we do?

23. Kevin Harris
(503)

24. Based on 2026CC modeled loads and solar from 2026CC v1.5
Impact of CA Duct Curve
~25,000 MW of solar modeled in CA
Avg daily min shifts from Off-Peak to mid-day
Solar only reduces peak demand May-Sep
No change to peak demand during fall/winter (Oct-Apr)
Based on 2026CC modeled loads and solar from 2026CC v1.5

25. CAISO Duck Curve Impact on Ramp Rate
Modeled CAISO load avg daily ramp rate
4,000 MW ramp in 3 hrs in 11 months
12,000 MW ramp in 7 hrs is 4 months
Modeled CAISO Load–Solar avg daily ramp rate
12,000 MW ramp in 3 hrs in 11 months
18,000 MW ramp in 7 hrs in 10 months

26. Cycling of CC for CA Duct Curve
Average daily committed start by hour by month
CA: Minor mid-day dip in committed CC
SW: Clear mid-day dip with afternoon spike in committed of CC

27. Suggested Intertie Charts
Propose 3 types of charts to review flow on interties
Flow duration: Determine peak flow issues
Avg monthly flow: Compare modeled flow with historic flow

28. Suggested Intertie Charts
Average hourly flow by month. Intra-day relationships are change with the CA duck curve. Understanding then this occurs and it magnitude results in improved understanding of transmission issues