1 proposed input assumptions to rtf cost-effectiveness determinations february 2, 2010
TRANSCRIPT
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Proposed Input Assumptions to RTFCost-Effectiveness Determinations
February 2, 2010
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Overview of Council Conservation Analysis Methodology
(1) Build Supply Curves
(2) Schedule
Availability
(3) Adjust NLO Supply Curve for Program Deployment
(4) Shape Savings by
Season & Hi/Lo
(5) Regional Portfolio
Model
(6) Strategy for Least-Cost & Least-Risk
(Cons Market Price Adder)
(7) Conservation
Build-Out over 750 futures
(8) Conservation
Targets & Action Plan
RTF >Translate Targets into Cost-Effective Portfolio of Measures and ProgramsRTF >Translate Targets into Cost-Effective Portfolio of Measures and Programs
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Objectives of this “Translation”
• Establish a cost-effectiveness limit for conservation that:– Is high enough to secure sufficient resources to meet
near-term and long-term conservation targets– Is low enough to avoid acquiring conservation
resources that have a high risk of costing more than 110% of generating resources over their expected lives (i.e., accounts for risk)
– Is shaped like market prices so that savings are appropriately valued
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Alternative Approaches
1. Use “110 % of Avoided Resource” cost to establish maximum levelized cost for conservation
Problems• Assumes perfect foresight• Not “shaped”
2. Use average amount of conservation acquired by RPM and supply curves to establish maximum levelized cost for conservation
Problems• Assumes all conservation is shaped the same• May hide underlying “pacing constraints”
3. Use “medium value” wholesale market price as “value of savings” to establish limit
Problems• Assumes perfect foresight• Wholesale market prices do not reflect full cost of new generation
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Option 1 – Use 110% of Cost of New Generation – But Which One?
Assumptions :
Efficiency Cost = Average Cost of All Conservation in Draft 6th Power Plan Under $100 MWh
Transmission cost & losses to point of LSE wholesale delivery
2020 service - no federal investment or production tax credits
Baseload operation (CC - 85%CF, Nuclear 87.5% CF, SCPC 85%)
Medium NG and coal price forecast (6th Plan draft)
6th Plan draft mean value CO2 cost (escalating, $8 in 2012 to $47 in 2029).
$0
$50
$100
$150
$200
$250
$300
Energ
y Effic
iency
Geothe
rmal
Combin
ed C
ycle
Col. B
asin
Win
d
AB Wind
Advan
ced N
uclea
r
Super
critic
al C
oal (
No CSS)
IGCC (N
o CSS)
Recip
roca
ting
Engine
Woo
d Res
idue
(No C
HP)
MT
Win
d
WY W
ind
CSP Par
aboli
c Tro
ugh
Utility
Photo
volta
ic
Leve
lized
Life
cycl
e C
ost
(200
6$/M
Wh)
Emission (CO2) costTransmission & Losses
System IntegrationPlant costs
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Even If We Pick A Resource, What is 110% of its Cost?
$0
$50
$100
$150
$200
$250
$300
$350
$400
0 2000 4000 6000 8000 10000 12000 14000 16000
MWa
20
06
$/M
Wh
Coal ConservationGasRenewablesNuclear
Generic coal, gas and nuclear units are shown at typical project sizes - more units could be built at comparable cost.
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Option 2 - Match Median Conservation RPM “Build Out” – Lost Opportunity Resources
0
500
1000
1500
2000
2500
3000
3500
4000
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
Cu
mu
lati
ve R
eso
urc
eD
evel
op
men
t (M
Wa)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
3130 MWa by 2030
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Lost-Opportunity Supply Technically Achievable Supply Curve
0
500
1000
1500
2000
2500
3000
3500
4000
<0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200TRC Levelized Cost (2006$/MWH)
Res
ourc
e P
oten
tial (
MW
a)
RPM Acquires 3130 MWa by 2030. This amount is technically available between $100 and $110/MWH
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Option 2 - Match Median Conservation RPM “Build Out” – Non-Lost Opportunity Resources–
But Which One?
0
500
1000
1500
2000
2500
3000
3500
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
Cu
mu
lativ
e R
eso
urc
eD
eve
lop
me
nt
(MW
a)
0%10%20%30%40%50%60%70%80%90%100%
2830 MWa by 2030
2640 MWa by 2026
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Non-Lost Opportunity Supply Technically Achievable Supply Curve
0
500
1000
1500
2000
2500
3000
3500
4000
<0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200TRC Levelized Cost (2006$/MWH)
Res
ourc
e P
oten
tial (
MW
a)
RPM Acquires 2640 MWa by 2026. This amount is technically available @ $90/MWH
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Unfortunately, A Single Levelized Cost Does Not Reflect On and Off Peak Value
$0
$10
$20
$30
$40
$50
$60
$70
$80
January w/oCO2
August w/oCO2
January w/CO2 August w/CO2
For
ecas
t P
erio
d R
eal L
evel
ized
Cos
t (2
006$
/MW
H)
High Load HoursLow Load Hours
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Option 3 – Use Wholesale Prices To Determine Cost-Effectiveness
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
Ma
y-9
6
Ma
y-9
7
Ma
y-9
8
Ma
y-9
9
Ma
y-0
0
Ma
y-0
1
Ma
y-0
2
Ma
y-0
3
Ma
y-0
4
Ma
y-0
5
Ma
y-0
6
Ma
y-0
7
Ma
y-0
8
Ma
y-0
9
Mid
-C M
on
thly
Wh
ole
sale
Pri
ce
(20
06
$/M
WH
)
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Which Wholesale Market Price Should Be Used?
$0
$20
$40
$60
$80
$100
$120
2005 2010 2015 2020 2025 2030
Who
lesa
le M
arke
t Pric
e (2
006$
/MW
H) Historical
6th Plan - Low w/Carbon6th - Medium w/Carbon6th Plan - High w/Carbon
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Method for Selecting the “Appropriate” Market Price Forecast
• The “Right” Market Price forecast is one that results in the pace and amount of conservation identified as cost-effective by the Resource Portfolio Model (RPM) over 20-yrs
• Use either the Aurora Mid-C medium market price forecast with or without carbon control cost (or any other price forecast)
• Adjust Aurora price with “adders” to reflect carbon control price included in forecast until “mini-RPM” builds same level of conservation as full RPM
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Proposed Calibration Goal – Match Average Conservation “Build Out” From RPM
0
1000
2000
3000
4000
5000
6000
7000
Sep-09 Sep-13 Sep-17 Sep-21 Sep-25Hydro-Year
Cu
mu
lati
ve
Sa
vin
gs
(M
Wa
) Lost OpportunityNon-Lost Opportunity
2640 MWa by 2026
3130 MWa by 2030
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What’s the “mini-RPM”
• Identical to full Resource Portfolio Model (RPM) except all inputs are “deterministic”– Average price forecast for gas and electricity– Average load growth forecast– Expected value cost for resources, forced
outage rates, dispatch order– Average carbon control cost and timing
• Can be run with or without median carbon cost in market price
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What’s The “Market Price Adder”
• Wholesale market prices no longer represent the full cost of new generation– State mandated RPS increase WECC system
wide energy surplus, which reduces value of wholesale market
• RPM uses 750 different wholesale market prices to establish the value and risk of acquiring new resources, including conservation
• Procost cost-effectiveness uses a single market price forecast which does not reflect uncertainty
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Expected Value Market Price Forecast without Carbon Control Cost
$0
$10
$20
$30
$40
$50
$60
$70
$80
Jan-08 Jan-12 Jan-16 Jan-20 Jan-24 Jan-28
Who
lesa
le M
arke
t Pric
e(2
006$
/MW
H)
Annual Average
Monthly Average High Load HoursMonthly Average Low Load Hours
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Expected Value of CO2 Cost Across Futures Modeled in RPM
0
10
20
30
40
50
60
Sep
-09
Sep
-11
Sep
-13
Sep
-15
Sep
-17
Sep
-19
Sep
-21
Sep
-23
Sep
-25
Sep
-27
Car
bon
Cos
t (2
006$
/ton
)
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Expected Value Market Price Forecast with Expected Value CO2 Control Cost
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
Jan-08 Jan-12 Jan-16 Jan-20 Jan-24 Jan-28
Who
lesa
le M
arke
t Pric
e(2
006$
/MW
H)
Annual Average
Monthly Average High Load HoursMonthly Average Low Load Hours
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Input Options
• Use Aurora market price forecast, including median carbon cost.– Primary Advantage: Reflects impact of carbon cost on the resource
dispatch– Primary Disadvantage: Embeds specific carbon cost assumptions
in market price forecast (limits flexibility and reduces transparency)
• Use Aurora market price forecast, input carbon cost separately– Primary Advantage: Allow for explicit input of carbon cost
assumptions (increases flexibility and transparency)– Primary Disadvantage: Does not reflects impact of carbon cost on
the resource dispatch
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What’s the “Calibration Adder”
• RPM uses 750 futures– Procost models only a single future
• RPM’s market prices and carbon cost are “volatile”– Procost’s prices are not “volatile”
• RPM futures are not “normally distributed,” hence the median values are not the average values
• RPM uses a single load shape for conservation– Procost models each measure’s load shape
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Market Price Adders for Conservation Cost-Effectiveness for Average Conservation Shape
$0
$10
$20
$30
$40
$50
$60
$70
LOWithoutCarbon
LO WithCarbon
NLOWithoutCarbon
NLO WithCarbon
RPM AdderCalibration AdderTotal LO Adder
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Proposed Final Input Assumption Choices
Resource Type
Carbon Cost Modeled
Pounds CO2 per kWh
RPM Adder ($/MWH)
Calibration Adder ($/MWH)
Total LO Adder ($MWH)
Lost Opportunity
Procost adds carbon
Fixed @ .99 lbs/kWh
$50 $18 $68
Non-Lost Opportunity
Procost adds carbon
Fixed @ .99 lbs/kWh
$35 $18 $53
Lost Opportunity
Aurora price w/carbon
Per Aurora Dispatch
$50 $8 $58
Non-Lost Opportunity
Aurora price w/carbon
Per Aurora Dispatch
$35 $8 $43
All of the above input produce identical TRC B/C Ratio’s for the weighted average conservation load shape and 13 year measure life.