MWG Identified Area of Model
Improvement to TAS
Salt Lake City - January 30, 2017
Kevin Harris, ColumbiaGrid
TEPPC\Model Work Group - Chair
2
Overview
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Hydro Operation
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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?
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Hydro Issues
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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?
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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
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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
On average this change would support 200
MW of the afternoon ramp
New daily peak
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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
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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
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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
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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 50-60 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
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Non-Dispatchable Supply
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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
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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
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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
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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
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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
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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
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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?
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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
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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
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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
– $471k/day
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Annual
Avg Daily
2026CC v1.7 Start
(Avg Start/Day)
CA
SW
NW
2026CC v1.7 Start Cost
($k/Mo)
CA
SW
NW
9.3
12.9
14.2
12.5
9.0
10.5
6.1
4.5
3.9
10.1
9.7
12.1
2.1
2.5
2.0
3.8
3.2
3.8
3.5
1.3
1.4
2.9
4.2
2.8
7,893
9,900
12,128
10,313
7,673
8,690
5,225
3,823
3,190
8,635
8,030
10,285
10,285
10,065
10,725
11,220
12,650
11,578
12,375
10,505
14,190
12,843
12,650
14,823
1,788
1,925
1,733
3,108
2,723
3,135
2,943
1,100
1,183
2,448
3,465
2,393
3,483 5,233 1,016
9.5 14.3
2.8
95.8
262
143.9
394
27.9
77
12.1
13.1
12.6
13.6
14.8
14.0
14.5
12.3
17.2
15.1
15.3
17.4
Start are the difference between
Max(HE 17-22) – Min(HE 12-16)
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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?
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Kevin Harris
(503) 943-4932
[email protected]
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Impact of CA Duct Curve
• ~25,000 MW of solar
modeled in CA
• Avg daily min shifts
from Off-Peak to midday
• 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
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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
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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
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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
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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