HomeMy WebLinkAbout20240208Appendix 7.1 - PacifiCorp-Idaho 2018 Electric System Loss Study.pdf
PACIFICORP
Idaho
2018 Electric System Loss Study
April 2020
PacifiCorp
2018 Electric System Loss Study
Executive Summary
The PacifiCorp’s 2018 Electric System Loss Study (“Study”) for Idaho presents power loss
information on Idaho’s power systems. This Study only considers technical losses, or losses
affiliated with transmitting electricity over Company equipment and does not consider non-
technical losses, such as losses attributable to erroneous metering or theft.
The Study developed estimated losses for each level of the system including; transmission,
distribution substations, the primary system, service transformers, the secondary system, services
and the retail meter. The Study developed separate demand (kW) and energy (kWh) loss factors
for each level of service in the power system.
Since it is impractical to perform detailed line loss calculations for each level of the system for
every hour of the year, PacifiCorp selected four hours that broadly represent different conditions
on its electric system and conducted power flow analyses at these four hours. The four base cases
used in the study were as follows:
Table 1: Power Flow Base Cases
PacifiCorp Load Percent of Peak Base Case
10,551 MW 100.0% July 16,@ 17:00 PPT 2018 (Summer Peak)
8,436 MW 80.0% February 23, 2018 @ 08:00 PPT (Winter Peak)
6,638 MW 62.9% October 8, 2018 @ 10;00 PPT (Median)
4,757 MW 45.1% May 4, 2018, @ 03:00 PPT (Minimum)
To extrapolate the losses from the four base cases to hourly (demand) and annual (energy) losses,
two separate second-degree polynomial loss functions for each level of the system were developed
– one for winter and one for summer. The total hourly losses for each state and loss category are
calculated across the entire year and then, once summed, are divided by the appropriate total load
to determine the annual loss percentage for each category. Demand losses are calculated based on
the sum of the losses at time of the twelve monthly coincident peaks divided by the sum of load at
those same times. The demand loss factors and energy loss factors are shown in Tables 2 and 3.
Table 2: Idaho 2018 Demand and Energy Loss Summary
Voltage Class Demand Loss Factor Energy Loss Factor
Transmission 3.816% 3.503%
Primary 8.121% 7.082%
Secondary 9.834% 9.061%
Table 3: Distribution System Losses
Functional Category Demand Loss Factor Energy Loss Factor
Dist. Substation Transformers 0.355% 0.715%
Primary Lines 3.950% 2.863%
Service Transformers 1.535% 1.827%
Secondary Lines 0.120% 0.094%
Meters 0.058% 0.058%
PacifiCorp
2018 Electric System Loss Study
INTRODUCTION
PacifiCorp’s 2018 Electric System Loss Study (“Study”) for Idaho presents power loss
information on Idaho’s power systems. This Study only considers technical losses, or losses
affiliated with transmitting electricity over PacifiCorp (“Company”) equipment and does not
consider non-technical losses, such as losses attributable to erroneous metering or theft.
Information included in the Study includes an overview of the systems analyzed along with a
discussion of the methodology employed. The Appendices provide additional supporting data.
METHODOLOGY
PacifiCorp performed a system loss study on its electric system to determine the amount of demand
and energy losses occurring by voltage class level. The Study developed estimated losses for each
level of the system including; transmission, distribution substations, the primary system, service
transformers, the secondary system, services and the retail meter. The Study developed separate
demand (kW) and energy (kWh) loss factors for each level of service in the power system.
Since it is impractical to perform detailed line loss calculations for each level of the system for
every hour of the year, PacifiCorp selected four hours that broadly represent different conditions
on its electric system and conducted power flow analyses at these four hours. The four base cases
used in the study were as follows:
Table 1: Power Flow Base Cases
PacifiCorp Load Percent of Peak Base Case
10,551 MW 100.0% July 16,@ 17:00 PPT 2018 (Summer Peak)
8,436 MW 80.0% February 23, 2018 @ 08:00 PPT (Winter Peak)
6,638 MW 62.9% October 8, 2018 @ 10;00 PPT (Median)
4,757 MW 45.1% May 4, 2018, @ 03:00 PPT (Minimum)
Subsequent sections provide additional detail regarding the technical analysis necessary to
determine the losses for each level of the system for the base case.
High Voltage System
Transmission: To calculate losses on the transmission system, PacifiCorp developed
detailed power flow models for the base cases for both the PacifiCorp West (PACW) and
PacifiCorp East (PACE) balancing authority areas. PacifiCorp utilized the Siemens PTI
PSS/E power flow software program for power flow studies. Transmission planning
relied on Western Electric Coordinating Council (WECC) approved base cases to
conduct the system Study, which represents the Bulk Electric System (BES). Detailed
system models for the PacifiCorp local area non-BES systems were added to the starting
base cases. System loads within each of the PacifiCorp balancing authority areas were
scaled to represent the four 2018 snapshot load profiles and generation dispatch was
adjusted within each of the four cases to approximate the dispatch observed in those four
historic hours. Supporting data and calculations are found in Appendix A.
Distribution System
Distribution Substations: The substation detailed network data was added to the starting
WECC approved bases cases in both of the PacifiCorp balancing authority areas. The cases
were then tuned and solved. After addition of the detailed network data in the four different
base cases, transmission and substation losses were extracted from the base cases.
Additionally substation losses were grouped by state jurisdiction. Supporting data and
calculations are found in Appendix A.
Primary System: A high level loss ranking of primary distribution system networks was
performed in order to develop a sample of primary networks by using their electrical
characteristics. Specifically, in order to estimate relative range of losses across many
circuits in each state, the customer energy usage (summer peak kWh/day), E, and locational
positive sequence resistance (primary R1) for each customer location were used. From the
sample set for each state, several networks near the average E2R1 were evaluated to
determine whether the distribution model was reasonably accurate, and whether detailed
load information (typically SCADA at the breaker) was available. Then three to five of
these networks were studied in the CYME power flow application, under base case loading
conditions.
The kW and kVAR loss results from each state’s sample of power flows were reduced to
an average value for each base case, and that average value was then multiplied by the total
number of distribution networks within the state to estimate the state’s total primary system
losses. Supporting data and calculations are found in Appendix B.
Secondary System - Service Transformers, Secondary and Service Conductors: An
extract from the Company’s GIS database was used to evaluate and classify line
transformers and to develop impedance models for the associated secondary and service
conductors. A summary of parameters extracted from the Company’s GIS database is
provided in Table C.1.
Manufacturer test records for line transformers procured between CY2012 and CY2015
were used to determine no-load and load loss values for typical transformer sizes based
on class, voltage and kVA rating. Current Company standards for the sizing of secondary
and service conductors were used to develop an impedance model and an associated load
loss value for the secondary of each line transformer. Hourly load profile data for the
delivery of residential and non-residential load at secondary voltage was used distribute
load and calculate losses for each base case.
Retail Meter: PacifiCorp contacted meter manufacturers to determine the losses for those
meter models used extensively by PacifiCorp throughout its service territory. PacifiCorp
then determined the currently-installed population of each meter model and multiplied the
population by the losses, as obtained from the manufacturer. This system-wide total was
then allocated to each individual state based on the number of customers located in each
state. Supporting data and calculations are found in Appendix D.
APPLICATION OF BASE CASE RESULTS TO HOURLY LOSSES
To extrapolate the losses from the four base cases to hourly (demand) and annual (energy) losses,
two loss functions for each level of the system were developed; one for winter and one for
summer. Generally, the winter line loss function relies on 2018 loads and losses for three points -
winter peak, median and minimum power flow results. The summer line loss function relies on
2018 loads and losses for three points - summer peak, median, and minimum power flow results.
In some cases the loss functions rely on two points – peak and minimum power flow results.
Once the loss functions were determined, those loss functions were applied to 2018 actual hourly
loads to derive hourly losses. Transmission system losses were derived from PacifiCorp West
and PacifiCorp East balancing area hourly loads. Primary losses rely on hourly primary and
secondary energy volumes by state as determined by load research studies. Transformer losses
and secondary losses rely on hourly secondary energy volumes by state as determined by load
research studies. Supporting data and calculations are found in the Appendix E.
Appendix A
Table A.1: PacifiCorp West Power Flow Results
PACW Total
Load (MW)
Transmission
Losses (kW)
Transmission
Losses (%)
Summer
Peak 3,659.7 84,865.1 2.32%
Winter
Peak 3,645.3 76,849.0 2.11%
Median
Load 2,339.5 54,540.9 2.33%
Minimum
Load 1,533.6 46,730.4 3.05%
Table A.2: PacifiCorp East Power Flow Results
PACE
Total Load
(MW)
Total Losses
(kW)
Total Losses
(%)
Transmission
Losses (kW)
Distribution
Losses ID
(kW)
Summer
Peak 9,063.0 377,254.0 4.16% 352,903.6 2,159.50
Winter
Peak 6,661.4 237,239.9 3.56% 220,050.2 1,435.59
Median
Load 6,125.3 185,384.3 3.03% 169,658.7 1,329.32
Minimum
Load 5,016.8 141,821.2 2.83% 129,131.1 978.10
Table A.3: Base Case Transmission Loss Results
Location Condition Total Load (MW) Transmission Losses
(MW)
Transmission Losses
(%)
PACW
Summer Peak 3,659.7 84.9 2.32%
Winter Peak 3,645.3 76.8 2.11%
Median 2,339.5 54.5 2.33%
Minimum 1,533.6 46.7 3.05%
PACE
Summer Peak 9,063.0 352.9 3.89%
Winter Peak 6,661.4 220.1 3.30%
Median 6,125.3 169.7 2.77%
Minimum 5,016.8 129.1 2.57%
Table A.4: Base Case Distribution Substation Power Flow Results
Location Condition Total Load
(MW)
Substation Losses
(MW)
ID
Summer Peak 857.6 2.2
Winter Peak 570.1 1.4
Median 527.9 1.3
Minimum 388.4 1.0
Appendix B
Table B.1: Primary Distribution Screened Network Detail
State Total Networks Sampled E2R1
Networks
(% of Total)
E2R1 Average of Sample
Set
Detailed Load Flow
Networks
ID 168 131 (78%) 493,279,060 3
Table B.2: Base Case Primary Loss Results
State Condition
Average
Network
kW Loss
Average
Network
kVAR
Loss
State
Total
State
Total
State
Total
kW
Loss
kVAR
Loss
kVA
Loss
ID
Summer Peak 112.5 125.7 18,897 21,125 28,344
Winter Peak 51.3 103.6 8,616 17,401 19,417
Median 8.6 9.2 1,446 1,545 4,472
Minimum 8.0 8.2 1,336 1,385 4,066
Appendix C
Table C.1: Line Transformer GIS Database Extract
Line Transformer (Parameter) Parameters Value (ex.)
State UT, WY, ID, OR, WA, CA
Facility Point Number Ex: 11302001.0069804
Class Overhead, Padmount,….
Phase(s) Energized 1,2,3
KVA 25,50,...,2500
Primary Voltage (kV) 7.2,12.47,...14.4,19.9
Secondary Voltage 120/240, 120/208, 277/480,…
No. of Connected Customers 1,2,…10,..
Connected Customer Rate Sch. Residential, Non-Residential
Table C.2: Secondary Voltage Loads (MW)
State MWH Load
Factor
Loss
Factor
Peak
Load
July
16,
2018 at
17:00
PPT
February
23, 2018
at 8:00
PPT
May
14,
2018 at
3:00
PPT
October
8, 2018
at 10:00
PPT
ID 1,812,581 37% 16% 566 497 219 114 157
Table C.3: Non-Residential Secondary Voltage Loads (MW)
State MWH Load
Factor
Loss
Factor
Peak
Load
July
16,
2018 at
17:00
PPT
February
23, 2018
at 8:00
PPT
May
14,
2018 at
3:00
PPT
October
8, 2018
at 10:00
PPT
ID 1,112,073 --- --- --- 376 97 67 94
Table C.4: Residential Secondary Voltage Loads (MW)
State MWH Load
Factor
Loss
Factor
Peak
Load
July
16,
2018 at
17:00
PPT
February
23, 2018
at 8:00
PPT
May
14,
2018 at
3:00
PPT
October
8, 2018
at 10:00
PPT
ID 700,508 48% 25% 165 121 123 46 63
Table C.5: Base Case Service Transformer,
Secondary and Service Loss Parameters
Class/State Sum of Transformer
Capacity MVA
Sum of
Transformer NLL
Sum of Transformer
LL at Full Load
Sum of Secondary
Losses LL at Full
Load
Sum of Service
Losses at Full
Load
Non-Residential 14,706.6 24.9 135.3 0.0 70.1
ID 1,110.0 2.0 10.7 0.0 5.6
Residential 11,984.5 23.9 130 64.9 70.7
ID 716.3 1.5 8.3 2.3 2.9
Total 26,691.1 48.7 265.3 64.9 140.8
Table C.6: Base Case Service Transformer,
Secondary and Service Loss Results
State Condition
Transformer
Input (MVA)
Transformer NLL
(MW)
Transformer LL
(MW)
Secondary LL
(MW)
Service LL
(MW)
Retail Load
(MVA)
ID
Summer
Pea
528.9 3.4 1.7
0.1
0.8
522.9
Winter Pea
235.0 3.4 0.4
0.1
0.1
230.9
Median
169.0 3.4 0.2
0.0
0.1
165.3
Minimu
123.3 3.4 0.1
0.0
0.0
119.7
Appendix D
Table D.1: Meter Populations and Results
Model Voltage Losses (W) Population Total Losses (Wh) / Day
Final Losses
(MWh) / Day
CENTRON Single
Phase 120-240 1.08 1,242,427 32,205,241 32.2
CENTRON
Pol phase 120-480 1.35 40,253 1,308,110 1.3
KV2C 120-480 1.15 33,717 930,589 0.9
KV2C 120-480 1.17 5,691 159,803 0.2
KV2C 120-480 2.029 47,342 2,305,366 2.3
I-210+c 240 2.184 605,839 31,755,657 31.8
Total 1,975,269 68,664,767 68.7
Table D2: Meter Loss Results
Location Customers Annual Losses (MWh) Losses (aMW) Loss Percentage
ID 82,994 1,053 0.1 0.06%
Total 1,975,269 25,063 2.9 0.07%
Appendix E
Table E.1: Loss Functions
Level
Summer Winter
PACE Transmission 0.000008 -0.019110 107.107548 0.000044 -0.300927 647.3062433
PACW Transmission 0.000008 -0.018491 57.680383 0.000004 -0.003855 45.28459738
ID
Substation -0.000016 0.013210 -0.390300 -0.000067 0.027641 -1.394837
Primary 0.000140 -0.033208 2.259246 0.000000 0.136937 -16.384230
Transforme 0.000007 -0.000106 3.449119 0.000015 -0.002289 3.593100
Secondary 0.000004 0.000058 -0.002362 0.000010 -0.001678 0.112087
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