20120411PAC to Exergy Attach1.1.pdf

IRP Avoided Cost Modeling
December 15, 2011
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ID GNR-E-11-03
Exergy 1 Attachment Exergy 1 -1
Attach Exergy 1 -1.pdf page 1 of 14
IRP Avoided Cost Modeling
METHODOLOGY
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Exergy 1 Attachment Exergy 1 -1
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Idaho Avoided Cost Background
•The “IRP” Methodology:
–“Ensures that utilities will not be required to acquire resource priced higher than would result
from a least cost planning process” - IPUC Order 25844 at p.6
15 000
13,000
14,000
15,000
(Me
g
a
w
a
t
t
s
)
Lake Side 2 in 2014
CCCT in 2016 CCCT in 2019
11,000
12,000
13,000
ap
a
c
i
t
y

O
b
l
i
g
a
t
i
o
n

(
Existing and Non-deferrable Capacity
9,000
10,000
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Sy
s
t
e
m

C
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
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Exergy 1 Attachment Exergy 1 -1
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Diagram of Avoided Cost Modeling
IRP
Avoided
Capacity
C t
Preferred
Resource
P tf li
GRID
Linear Programming
Avoided
Energy Cost
Cost
$/KW-yr
(1)
Portfolio
Proposed QF
1.Perform two simulations:
Linear Programming
Power Cost Simulation
Energy Cost
$/MWh (2)
( )(2)Resource
1.Perform two simulations:
Base Simulation: Excludes proposed QF resource
AC Simulation: Includes proposed QF resource and partial displacement
2.Calculate dollar difference between Base Simulation and AC Simulation
3 Less wind and solar integration charge3.Less wind and solar integration charge
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Exergy 1 Attachment Exergy 1 -1
Attach Exergy 1 -1.pdf page 4 of 14
Partial Displacement Illustration (MW)
Partial Dispalcement: CCCT (Dry "F" 2x1) - East Side Resource (4500')
--------------------------------------------------------------------------------------------------------------------
Base Base Load
Thermal
Canal Drop
Hydro Solar Wind
---------------------- ---------------------- ---------------------- ---------------------- ----------------------
IRP Nameplate Capacity 596 9 596 9 596 9 596 9 596 9IRP Nameplate Capacity 596.9 596.9 596.9 596.9 596.9
Committed Resources (Queue) (1) 36.1 36.1 36.1 36.1 36.1
Proposed QF Capacity Contribution - 20.0 17.2 7.0 1.1
---------------------- ---------------------- ---------------------- ---------------------- ----------------------
Total Displacement 36 56.1 53.3 43.1 37.2
---------------------- ---------------------- ---------------------- ---------------------- ----------------------
New Nameplate Capacity 560.8 540.8 543.6 553.8 559.7
Footnotes:
(1) Base includes displacement from QF contracts signed subsequent to IRP
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Exergy 1 Attachment Exergy 1 -1
Attach Exergy 1 -1.pdf page 5 of 14
Avoided Capacity Costs
•Capacity costs generally
–Non-energy costs (i.e. capital, O&M, interest, return on rate base, etc.)
–Avoided capacity cost entails modified resource selection in IRP process
•Next deferrable IRP resource addition
–June 2016 addition of Currant Creek 2 - 597 MW CCCT (Dry "F" 2x1)
•Partial displacement
–Deferrable resource size reduced by QF contribution to peak
–Ensures QF capacity price same as integrated resource planning process
–Captures energy benefits of deferrable resource not provided by QF
di h bili •e.g. dispatchability, reserves
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Exergy 1 Attachment Exergy 1 -1
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Price Provided to QF
•Energy price
–Stated in $/MWH
–Monthly HLH/LLH values
•Capacity price
–Stated in $/KW-YR
–Annual values
•Less: wind and solar integrationg
–$6.50/MWH pursuant to IPUC Order 31021
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IRP Avoided Cost Modeling
THE GRID MODEL
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Exergy 1 Attachment Exergy 1 -1
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The GRID Model
•GRID (Generation and Regulation Initiative Decision Tools)
•Energy model
•Simulate system operations
•Resources “dispatched” to serve load obligation by most economic means
•Least-cost dispatch linear programming algorithm
•Used in general rate cases and avoided costs
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GRID Logic
Input DataInput Data
= Intermediate GRID calculation
= GRID Calculated Input to Dispatch (LP)
Thermal Hydro Long Term 
Contracts
Short Term 
Firm
Hourly LTC DispatchPr
e HourlyHydroDispatch
De‐rated Availability
Commitment Logic
Retail Load
Hourly LTC Dispatche‐Di
s
p
a
t
c
h
Hourly Hydro Dispatch
Reserve Requirement
Allocated Reserves
Commitment Logic
Thermal Availability Hourly Purchases and Sales
Loadrequirements Prices Transmission capacity
Linear Program Objective Function
Hourly LTC DispatchHourly Hydro Dispatch
“Must Run” Resources from Market caps
Di
s
p Load requirements Prices Transmission capacity
Net Power Cost
System Balancing
Pre‐dispatch Market capspat
c
h
Ou
t
p
uuts
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Exergy 1 Attachment Exergy 1 -1
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GRID Topology
Mid
Columbia
Jim Bridger
Wyoming
Central
Wyoming
NortheastYakima
Walla
Walla
Colstrip$
Bridger
BPA*
multi-point
Path
TronaGoshen
Hot Springs
BPA NITS*
Brady*
IPC West*
Utah North
Monsanto,
SW WY
Path C(S)*
cut plane
C(N)*
IPC East*
Hermiston
Mead LegendGC-PP
West
Main
Utah
South
Colorado
Central
Oregon
Mona
$
$
COB
SP15
g
- Load points
- Resource
- Liquid market
- FTR
APS*
Trans.PV
4C
Cholla
Chehalis
NOB
Oregon
$$
$
$
$
$
* Not a physical path/area – represents contract terms
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IRP Avoided Cost Modeling
ILLUSTRATIVE STUDIES
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Exergy 1 Attachment Exergy 1 -1
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Summary
Avoided Cost: 20-Year Nominal Levelized
---------------------------------------------------------------------------
Project Description Capacity (MW) Capacity Factor
Capacity
Contribution
Energy
($/MWh)
Capacity
($/kW-yr)
Est. $/MWH at
Stated CF---------------------------------- ------------------------ ------------------------ ------------------------ ------------------------ ------------------------ ------------------------
Base Load Thermal 20 92.00% 100.00% $45.08 $118.16 $59.74
Canal Drop Hydro 20 34.00% 86.00% $48.16 $101.62 $82.27
Solar 20 22.60% 35.00% $44.41*$41.36 $65.30
Wind 22 34.40%5.00% $37.20*$5.91 $39.16
* Avoided energy cost includes reduction for wind and solar integration charge.
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IRP Avoided Cost Modeling
QUESTIONS
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