October 20, 2008
Loss Factor Stakeholder Team:
Re: Draft Loss Factors for 2009
The AESO has completed its preliminary calculation of 2009 loss factors and the draft
results are attached. The analysis includes the application of the 2009 Generic Stacking
Order (GSO) results published earlier this summer to the 2009 Base Cases published on
October 15 2008 on the AESO web site. The AESO is hosting a meeting on the draft loss
factors October 27, 2008 from 9:30-12:00. The AESO will be posting the final 2008 loss
factors on or before November 07, 2008.
In order to provide perspective on the draft values, the AESO offers the following:
Load treatment:

In the 2009 loss factor calculation, only transmission loads were unassigned.
Consistent with our methodology, these loads were not included in the loss factor
calculation. Therefore the loss factors are based on generation less the behind the
fence load levels at all relevant Generation Buses while maintaining the appropriate
GSO level at the MPID bus.

The load used in the base cases is consistent with the latest AESO load forecast for
2009.
Overall results:





The Rainbow area has less credit or more charges than in the 2008 Loss Factors.
These results are due primarily to lower Ft. Nelson area load levels in the 2009
base cases. The Rainbow area is historically sensitive to load and generation
changes. A small deviation in the Rainbow Area net flow can result in a swing in the
loss factors on the generators. The loss factor sensitivity in the area is consistent
with previous years’ findings.
The South area receives more credits/less charges than 2008. Lower generation
and higher load has resulted in more favorable loss factors in 2009 than in 2008.
The Lake Wabamun area loss factors are lower relative to the 2008 loss factors.
The changes are primarily due to the KEG loop energization.
Sheerness and Battle River generation are higher and area loads are lower in most
of the 2009 base cases and resulting in higher loss factors.
The Fort McMurray area loss factors are higher [in general] in 2009 due to higher
generation dispatches. The higher dispatches have resulted in higher net flow out of
area in the cases.
2500, 330 - 5th Ave SW Calgary, Alberta T2P 0L4
t (403) 539-2450 | f (403) 539-2949 | www.aeso.ca
-2
The AESO has included more rigorous voltage thresholds in the base case
development than previous years. Please refer to the loss factor web site for
details.
Inter-Tie Losses
 Import loss factors in 2009 reflect the implementation of the 2007 Transmission
Regulation
 The tie line losses will be posted prior to the October 27, 2008 meeting.
Shift Factor:

The preliminary shift factor for 2009 has been determined at 0.85%. The 2008 shift
factor was 0.81%, representing a difference of 0.04%. The lower level of the shift
factor reflects the improvement in the accuracy of the overall process. The main
components in the process are the forecast of losses, the load forecast, the generic
stacking order, the base case development, and the determination of the loss
factors.
Weighting Factor:

The AESO has applied unequal weighting factor to the raw loss factors based on
historical load levels. The weighting factor will be published with the final results.
Generally, the 2009 loss factors reflect changes in the AIES as would be expected through
normal generation and load growth and large generator maintenance schedules.
Please provide any comments on the draft 2009 loss factors in writing to
lossfactor@aeso.ca by October 27, 2008.
Yours truly,
Robert Baker, P.Eng.
Regulatory Forecasting, AESO
cc:
Doyle Sullivan
Ashikur Bhuyia
-3-
2009 Alberta Loss Factors - 2008-10-20, Draft
MP-ID*
0000016301
0000079301
NX01
BAR
BR3
BR4
BR5
BCHIMP
BCRK
BCR2
BPW
BLYR
BIG
BRA
GOC1
0000045411
CES1
CES2
TC01
CAS
CR1
EC01
CHIN
CMH1
ENC1
ENC2
CRE1
CRE2
CRE3
PKNE
CRWD
Project692_1_SUP DAI1
DKSN
DOWGEN15M
DV1
DRW1
Project730_1_SUP FNG1
EC04
0000001511
GN1
GN2
GN3
GHO
0000022911
GPEC
HSH
HRM
INT
KAN
KH1
KH2
KHW1
IOR1
MATLIMP
Project703_1_SUP AKE1
MKRC
ProjectISD762SUP
MKR1
NX02
Project672_1_SUP
NPC1
NOVAGEN15M
OMRH
WEY1
0000039611
0000035311
POC
PH1
PR1
RB1
RB2
RB3
Facility Name
PSS/E Bus
Normalized and
Compressed Loss
Factor (%)
Loss Factor
Asset
Difference % in Loss
Factor to System
Average
Amoco Empress (163S)
ANG Cochrane (793S)
BALZAC
BARRIER
BATTLE RIVER #3
BATTLE RIVER #4
BATTLE RIVER #5
BCH - Import
BEAR CREEK G1
BEAR CREEK G2
BEARSPAW
BELLY RIVER IPP
BIGHORN
BRAZEAU
BRIDGE CREEK
BUCK LAKE
CALPINE CTG
CALPINE STG
CARSELAND
CASCADE
CASTLE RIVER
CAVAILIER
CHIN CHUTE
CITY OF MEDICINE HAT
CLOVER BAR PEAKER (STAGE 1 - LM6000)
CLOVER BAR PEAKER (STAGE 2 - LM6000)
COWLEY EXPANSION 1
COWLEY EXPANSION 2
COWLEY NORTH
COWLEY RIDGE WIND POWER PHASE1
COWLEY RIDGE WIND POWER PHASE2
Dapp Power Westlock Expansion
DIASHOWA
DICKSON DAM 1
DOW GTG
DRAYTON VALLEY PL IPP
DRYWOOD 1
ENMAX Crossfield Energy Centre
FORT NELSON
FOSTER CREEK G1
FT MACLEOD
GENESEE 1
GENESEE 2
GENESEE 3
GHOST
GLENWOOD
GRANDE PRAIRIE ECOPOWER CENTRE
HORSESHOE
HR MILNER
INTERLAKES
KANANASKIS
KEEPHILLS #1
KEEPHILLS #2
KETTLES HILL WIND ENERGY PHASE 2
MAHKESES, COLD LAKE
MATLIMP
Maxim Power Deerland Peaking Station
McBRIDE
McKAY RIVER
Meg Energy
MUSKEG
NEXEN OPTI
Northern Prairie Power Project
NORTHSTONE ELMWORTH
NOVA JOFFRE
OLDMAN
P&G WEYERHAUSER
PINCHER CREEK
PLAMONDON
POCATERRA
POPLAR HILL
PRIMROSE
RAINBOW 1
RAINBOW 2
RAINBOW 3
262
191
290
216
1491
1491
1469
56765
10142
10142
183
447
103
56153
19145
80
187
187
5251
175
234
247
406
680
516
516
264
264
264
264
264
21
1088
4006
61
4332
4226
503
1016
1301
4237
525
525
525
180
4245
1101
171
1147
376
193
420
420
402
56789
451
432
901
1274
405
1236
1241
1120
19134
383
230
1141
4224
4304
214
1118
1302
1031
1032
1033
0.94
3.68
-0.41
-1.46
5.07
5.07
4.16
-0.62
-1.44
-1.44
-1.37
0.00
2.49
2.07
0.00
2.33
-0.33
-0.33
-0.54
-2.22
1.40
-0.43
0.00
-0.32
4.19
4.19
3.52
3.52
3.52
3.52
3.52
0.00
-2.03
0.00
3.97
0.00
1.26
0.80
7.55
7.04
0.71
5.72
5.72
5.72
-1.53
0.46
-1.88
-1.48
2.34
-1.06
-1.37
5.72
5.72
1.56
4.68
0.68
4.10
1.12
6.59
6.06
6.76
6.85
-4.79
-5.05
1.25
2.09
-3.02
1.52
2.87
-1.45
-4.81
5.46
2.79
2.73
2.93
DOS
DOS
Gen
Gen
Gen
Gen
Gen
Imp
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Imp
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
-3.61
-0.87
-4.96
-6.01
0.52
0.52
-0.39
-5.17
-5.99
-5.99
-5.92
-4.55
-2.06
-2.48
-4.55
-2.22
-4.88
-4.88
-5.09
-6.77
-3.15
-4.98
-4.55
-4.87
-0.36
-0.36
-1.03
-1.03
-1.03
-1.03
-1.03
-4.55
-6.58
-4.55
-0.58
-4.55
-3.29
-3.75
3.00
2.49
-3.84
1.17
1.17
1.17
-6.08
-4.09
-6.43
-6.03
-2.21
-5.61
-5.92
1.17
1.17
-2.99
0.13
-3.87
-0.45
-3.43
2.04
1.51
2.21
2.30
-9.34
-9.60
-3.30
-2.46
-7.57
-3.03
-1.68
-6.00
-9.36
0.91
-1.76
-1.82
-1.62
-4RL1
RB5
RYMD
TC02
RG10
RG8
RG9
RUN
SH1
SH2
SHCG
SCTG
GWW1
SPCIMP
SPR
0000038511
STMY
0000006711
ST1
ST2
IEW1
SCR1
SCR3
SCR2
SD1
SD2
SD3
SD4
SD5
SD6
SCL1
341S025
TAB1
TAY1
TAY2
THS
VVW1
VVW2
WB4
WTRN
WST1
EAGL
RAINBOW 4, RL1
RAINBOW 5
RAYMOND RESERVOIR
REDWATER
ROSSDALE 10
ROSSDALE 8
ROSSDALE 9
RUNDLE
SHEERNESS #1
SHEERNESS #2
SHELL CAROLINE 378S
SHELL SCOTFORD
SODERGLEN
SPC - Import
SPRAY
SPRING COULEE
ST MARY IPP
STIRLING
STURGEON 1
STURGEON 2
SUMMERVIEW 1
SUNCOR
SUNCOR HILLRIDGE WIND FARM
SUNCOR MAGRATH
SUNDANCE #1
SUNDANCE #2
SUNDANCE #3
SUNDANCE #4
SUNDANCE #5
SUNDANCE #6
SYNCRUDE
Syncrude Standby (848S)
TABER WIND
TAYLOR HYDRO
TAYLOR WIND PLANT
THREE SISTERS
VALLEYVIEW
VALLEYVIEW # 2
WABAMUN #4
WATER IPP
WESGEN
WHITE COURT
Notes:
* MP-ID - point where loss factors assessed
For loss factors, "-" means credit, "+" means charge
Loss factors effective from January 01, 2009 to December 31 2009.
System Average Losses, %: 4.55
For more information, please visit www.aeso.ca
1035
1037
413
50
507
507
507
197
1484
1484
3370
43
358
1473
310
4246
3448
4280
1166
1166
336
1208
389
251
135
135
135
135
135
135
1205
1200
343
670
670
379
1171
1172
133
3449
14
410
3.26
2.72
0.00
4.15
4.43
4.43
4.43
-1.60
3.81
3.81
-0.72
4.36
1.46
1.35
-1.59
0.36
0.00
0.60
-0.28
-0.28
2.01
6.69
-0.17
0.54
6.05
6.05
6.05
6.05
6.05
6.05
6.71
-4.45
-0.72
1.68
1.68
-1.43
0.79
0.77
5.73
0.00
0.00
0.00
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Imp
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
DOS
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
Gen
-1.29
-1.83
-4.55
-0.40
-0.12
-0.12
-0.12
-6.15
-0.74
-0.74
-5.27
-0.19
-3.09
-3.20
-6.14
-4.19
-4.55
-3.95
-4.83
-4.83
-2.54
2.14
-4.72
-4.01
1.50
1.50
1.50
1.50
1.50
1.50
2.16
-9.00
-5.27
-2.87
-2.87
-5.98
-3.76
-3.78
1.18
-4.55
-4.55
-4.55