20171220IPC to Sierra Club Attachment 3 Line Loss Study Report.pdf

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Development of 2012 System Loss Coefficients

Prepared by:

Trevor Schultz
Bryan Hobson
Transmission Policy & Development
5/2/2014

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Table of Contents

Executive Summary ................................................................................................................................... 3
Introduction .............................................................................................................................................. 4
System Level Descriptions ........................................................................................................................ 4
Transmission Level ................................................................................................................................ 4
Distribution Levels ................................................................................................................................ 5
Energy Loss Coefficient Calculations ......................................................................................................... 6
Transmission Level Energy Losses ......................................................................................................... 6
Distribution Substation Level Energy Losses......................................................................................... 7
Distribution Level Energy Losses ........................................................................................................... 8
Distribution Line Transformer Losses ................................................................................................. 10
Primary/Secondary Distribution Losses Split ...................................................................................... 12
2012 Energy Loss Coefficients Diagram .............................................................................................. 14
Peak Demand Loss Coefficients Calculations .......................................................................................... 15
Transmission Level .............................................................................................................................. 15
Distribution Stations Level .................................................................................................................. 16
Distribution Primary System Level ...................................................................................................... 16
2012 Peak Loss Coefficients Diagram ................................................................................................. 17
Delivery Point Loss Coefficients .............................................................................................................. 18
Appendix A: 2012 Energy Losses Data Sources .......................................................................................... 19
Appendix B: 2012 Peak Losses Data Sources ............................................................................................. 21
Appendix C: Loss Coefficients Not Including GSU Losses ........................................................................... 23
Appendix D: Reconciliation with FERC Form 1 ........................................................................................... 24

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Executive Summary
This loss study determines the peak and energy loss coefficients for the Idaho Power delivery system for
the calendar year 2012. The delivery system was broken down into four system levels including:
1. Transmission: All voltage levels from 46 kV to 500 kV, includes transmission voltage tie
transformer banks and iterations with/without generator step up transformers
2. Distribution Stations: Includes distribution station transformers
3. Distribution Primary: All distribution lines and facilities at 12.47 kV, 25 kV and 34.5 kV
4. Distribution Secondary: Includes distribution line transformers
The losses documented in this study represent the actual, physical losses that occurred on Idaho Power
delivery system facilities. Application of the calculated loss coefficients is limited to loads served from
Idaho Power Company facilities. The peak loss coefficients are calculated based on data from the
system peak hour in 2012 which occurred on July 12 from 4 pm to 5 pm.
This study employs a slightly different approach to calculating losses than previous studies. Previous
studies calculated losses as the difference between system level “outputs” and system level “inputs”.
While the principle of losses = inputs – outputs still applies, this study uses hourly load data from AMI,
MV90 and Pi to directly calculate the losses at each individual system level. Transmission line losses are
calculated directly based on the resistance of the line. Total transformer losses, including generator
step-ups, tie banks, distribution substation transformers and distribution line transformers are found by
calculating and summing the core and the winding losses. The distribution system losses, primary plus
secondary, were found as the difference between the distribution system inputs (output of the
substation layer) and the distribution system outputs as defined by the AMI, MV90 and Pi data.
The individual system level loss coefficients are the system level inputs divided by the system level
outputs, including wheeling. The loss coefficients used at each delivery point in the system (at the four
system levels above) are calculated as the product of the individual level loss coefficients. These final
loss coefficients for the energy losses and peak losses for calendar year of 2012 are shown in Table 1.
System Level Energy Loss Coefficient Peak Loss Coefficient
Table 1: 2012 Delivery Point Loss Coefficients, wheeling included

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Introduction
Loss coefficients are the ratio of the system input required to provide a given output at a particular
system “level” in the power system. For example, the energy input to the system required to serve
residential sales equals the sales multiplied by the distribution secondary system energy loss coefficient.
Similar calculations can be made for peak demand using the peak loss coefficients. Both peak demand
and energy loss coefficients are calculated for each system level.
Individual level loss coefficients relate the input and the output of each individual system level by
Equation 1.

Equation 1

The system loss coefficient is obtained by multiplying all of the “upstream” system level coefficients
together. For example, the total distribution secondary system loss coefficient is found by the following
equation:

For 2012, the total Distribution Secondary system energy loss coefficient is 1.096.

The 2012, the total Distribution Secondary system peak loss coefficient is 1.097.

System Level Descriptions

The Idaho Power Company power system was split into four categories for the purposes of this loss
study: Transmission, Distribution Stations, Distribution Primary and Distribution Secondary. The
system inputs and outputs for each level are described below. The sources of information for each of
the individual level inputs and outputs are shown in Appendix A.

Transmission Level
The transmission level includes losses for all facilities and lines from 46 kV up through 500 kV. Losses
from the generation step-up transformers (GSU) and transmission tie-bank transformers are calculated
and included in the transmission level. Customer owned facilities are not included. The loss factors
Individual Level Coefficient

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used for FERC rate calculations assume that the generator step-up (GSU) losses are included as part of
the generation output and therefore are not included in the transmission system level losses. The
adjusted loss factors not including the GSU losses are shown in Appendix C.

The inputs to the transmission system level include IPC generation, power purchases and exchanges
from other companies, customer owned generation connected directly to the transmission system, and
wheeling transactions. The transmission level outputs include high voltage sales to customers and other
utilities, power exchanged to other utilities, wheeling transactions, and output to the distribution station
level. The Exchanges Out are adjusted to remove the scheduled losses for the Idaho Power share of
losses in the jointly owned Bridger-Idaho and Valmy-Midpoint transmission systems. FERC Form 1
includes the Bridger and Valmy scheduled losses as exchanges out. The calculated losses in this study
include the Idaho Power share of losses on the Bridger and Valmy systems as transmission level losses.
The Bridger and Valmy scheduled losses are added to the total FERC Form 1 losses to reconcile the
calculated losses with the FERC Form 1 losses. (See Appendix D, Reconciling with FERC Form 1). The
Idaho Power share of Boardman-Idaho transmission system losses are only accounted for financially.
The scheduled output loss transactions by IPC to other utilities for losses caused by wheeling IPC energy
through other systems are included as system outputs used to calculate transmission losses.

The treatment of loss transactions in the computing of the transmission level loss coefficients is to: (1)
Include in Idaho Power’s transmission level losses, energy delivered to Idaho Power for loss
compensation due to wheeling other system’s transactions on the Idaho Power system. (2) Include in
Idaho Power’s transmission level losses, Idaho Power’s share of losses in the jointly owned Bridger-
Idaho and Midpoint-Valmy transmission systems. (3) Exclude from Idaho Power’s transmission level
losses, energy scheduled out for losses on other systems due to Idaho Power’s wheeling on other
systems.
Distribution Levels
The distribution station level includes all Idaho Power owned distribution substations, including Idaho
Power owned distribution substation transformer losses. Customer owned facilities are not included.
The input to the distribution station level is the net output of the transmission level. The outputs of the
distribution station level are the direct sales from substations (both industrial/commercial and
irrigation), wheeling transactions with substation level delivery points, and output to the primary
distribution level.

The distribution primary level includes all primary voltage lines and equipment at voltages of 12.5 kV, 25
kV and 34.5 kV. Customer owned facilities are not included. Inputs to this level include the net output
of the distribution station level and the customer owned (PURPA) generation connected to the primary
distribution system. Outputs from the distribution primary system include direct primary metered sales
to IPC customers, wheeling transactions with distribution primary delivery points, and the output to the
distribution secondary level.

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The distribution secondary level consists of all Idaho Power owned secondary voltage lines and
equipment including the distribution line service transformers. Customer owned facilities are not
included. Inputs to this level include the output from the distribution primary level and the net-
metering and Oregon Solar customers. Outputs include the retail distribution sales (secondary
customers), wheeling transactions with distribution secondary delivery points, and Idaho Power
Company internal uses (not including substation local service use).
Energy Loss Coefficient Calculations

Figure 1 shows the total system flow diagram for the 2012 energy losses. This figure outlines each
system level’s input and output, the total energy losses (MWh) and loss coefficient. The transmission
level output (MWh) to the distribution station level is calculated by subtracting the remaining outputs
and calculated losses from the transmission level inputs.
Transmission Level Energy Losses
The transmission level losses (in MWh) were calculated by first collecting hourly load data from the Pi
database for the entire 2012 calendar year. Then the I2R losses were calculated for each Idaho Power-
owned transmission line section using Equation 2.
Equation 2

Where Rp.u.Line is the total p.u. resistance of the transmission line section on 100 MVA base
And “Hourly_Usage” is the average hourly usage on the transmission line section in MWh

The transmission line energy losses in MWh were calculated by voltage at all the voltage levels from 46
kV up to 345 kV (see Table 2). Where transmission voltage data was available in Pi (138 kV and higher),
the line losses were scaled by the average hourly voltage to more accurately calculate the losses. Where
voltage data is not available in Pi, 1.0 p.u. voltage is assumed.

Voltage
Tot Losses
MWh
Total Lines Losses 650,629.8
Table 2: Transmission Line Losses by Voltage
The energy losses for the generator step-up transformers (GSU) and transmission tie-banks are
calculated by summing the winding (copper) losses and the core losses for each transformer unit. The
winding (copper) losses are calculated by collecting hourly load data and per unit resistance (100 MVA
base) on each transformer then using Equation 2 above.

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The core losses for each transformer are obtained from Idaho Power Apparatus department “no-load
losses” records. It is assumed the transformers are energized for every hour of the year so the total core
losses for each transformer unit are calculated with Equation 3.

Equation 3

Where NLL is the “no-load losses” in kW for each transformer
And 8784 is the number of hours in 2012 (leap year)

The GSU and transmission tie-bank energy losses for 2012 were found to be:

76,154.1 MWh Core Losses + 45,703.0 MWh Copper Losses = 121,857.1 MWh Total Losses

Total transmission level losses are shown in Table 3.

Tot Losses
MWh
Total Transmission 772,486.9
Table 3: Total Transmission Level Losses
Distribution Substation Level Energy Losses
Distribution substation losses are found by calculating the total losses in the substation transformers for
the calendar year 2012. Losses in other substation apparatus, equipment and bus are assumed
negligible. The total losses in the substation transformers are the sum of the core losses and the
winding (copper) losses.
The core losses are calculated using Equation 3. The no-load losses (in kW) were obtained from the IPC
Apparatus group. The winding (copper) losses are proportional to the total energy delivered through
the transformer. Hourly average load data (MWh) was obtained for each transformer. Most of the
substation transformer load data was obtained from Pi. For the transformers not in the Pi database,
one of three methods was used to obtain or estimate hourly transformer data:
1) MV90 system data if available, otherwise
2) Sum of the Pi data on the feeders served by the transformer if available, otherwise
3) Estimated losses based on transformer kVA rating and average load profile
96% of all the distribution substation losses were calculated from Pi data. 3% of the data came from
MV90 and 2% of the total losses were estimated.

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Table 4: Distribution Station Losses 2012
Distribution Level Energy Losses
The system wide implementation of Automated Metering Infrastructure (AMI) has provided a much
more granular data set of customer loads than was ever available before. In 2012, approximately 99%
of Idaho Power customers were metered with AMI meters. To calculate distribution system inputs,
outputs, and losses, this study gathered and made use of hourly customer metered data that is available
from the AMI system, the MV90 metering system, and Pi. For information about how each type of data
source was handled, including care taken to ensure the correct sign for net-metering and cogen data,
see the document titled “Notes About Data.docx”.
The total distribution level losses (distribution primary plus distribution secondary losses) were
calculated in a multi-step process whereby a loss percentage was calculated based on distribution level
inputs minus distribution level outputs for a large subset of distribution data screened for data integrity,
then this loss percentage was applied to the total distribution level input (the output of the substation
level). Here is a description of the steps in the total distribution system loss calculation:
1) Hourly energy data was obtained for distribution level inputs for the subset of substation
distribution transformers with AMI installed. The distribution level input hourly data came from
one of two sources:
a. MV90 database if available, otherwise
b. Pi database
2) Hourly energy data was obtained for distribution level outputs (primary and secondary) for the
subset of customers connected to distribution systems fed by station distribution transformers
with AMI installed. The distribution level hourly output data came from several sources:
a. AMI meter data; includes the vast majority of energy consumption
b. MV90 BPA meter data; includes all BPA customers served by IPC distribution system
c. MV90 Large Customer meter data; large customers metered via the MV90 system
d. AMI Net meter data; All net-metering customers net load
e. MV90 Oregon Solar meter data; the “net” energy meter data was tabulated
f. Co-generation meter data; All customer owned generators connected to the
distribution system (generation was considered a negative output for computation
purposes). Data came from the MV90 database if available, otherwise from the Pi
database if available, otherwise hourly data was estimated based on monthly billing
from the Energy Contracts group.
3) The output data for each customer was mapped to a substation based on one of two methods:
a. For AMI meters, the mapping was assigned according to AMI meter self-reported
locations based on a snapshot from May 13, 2013.
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b. For non-AMI meters, the mapping was assigned based on the substation which normally
sources the feeder to which it is connected.
4) Total input and total output data were tabulated by substation.
5) The hourly input data from the Pi database was screened for “gaps” between consecutively
logged data points of 3 hours or more. (It was assumed the hourly output data integrity was
adequate since most data came from the AMI or MV90 databases. The AMI database logs
hourly interval data, and any missing data is replaced by an estimation algorithm that replaces
the missing intervals with estimated data based on valid register reads on the boundaries of the
missing interval data. The MV90 system logs 15-minute interval data and generally does not
have missing data).
6) The input and output data for hours where “gaps” were detected in the input data for a
particular substation were excluded from the input and output totals for that substation.
7) Input data was further screened to check for situations where load transfers caused the input
data to flatline at 0, which generally results in intervals of greater than 3 hrs between logged
data points in Pi, thereby resulting in exclusion of the inputs and outputs for that substation for
the duration of the load transfer. In this situation, if load was transferred between different
stations, this caused the exclusion of output data for meters connected to the offloaded
transformer or feeder, but inclusion of the input energy feeding those meters which shows up in
the input data for the substation to which the load was transferred. In cases where valid
flatlined data was identified for load transfers between stations, the input and output data for
those hours were included in the totals for the offloaded substation. Development of a dynamic
substation-to-meter map would prevent this problem in future loss studies.
8) Screened losses for each AMI substation were calculated based on the screened input and
output data by subtracting the sum of the output data from the sum of the input data for valid
hours.
9) A loss percentage was calculated based on the total screened losses for all substations divided
by the total screened input for all substations.
10) This loss percentage was applied to the total distribution level input (the output from the
substation level) to determine total distribution level losses and individual loss percentages for
distribution primary, distribution transformers, and distribution secondary (see below for
calculation of these values).
11) At this point, a slightly iterative process was used to factor in the losses of the non-AMI
substations.
12) Distribution level inputs and outputs for each non-AMI substation were tabulated in terms of
annual kWh.
13) The non-AMI substation distribution input data came from one of the following sources:
a. MV90 database if available, otherwise,
b. Pi database if available, otherwise,
c. Estimated data based on substation distribution transformer rating and average load
profile (6% of input energy for non-AMI stations came from this source)
14) The non-AMI substation distribution output data was directly measured via MV90 where
available or estimated based on the average loss percentages calculated for distribution
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primary, distribution transformers, and distribution secondary up to this point. Only the
percentages for the portion of distribution system fed by each non-AMI station were used. For
example, if a particular non-AMI substation fed one or more large industrial customers for which
Idaho Power owns the primary facilities and service transformers, only the average distribution
primary and distribution line transformer loss percentages would be applied to this substation
to determine the losses (the distribution secondary loss percentage would not be applied).
15) Once the non-AMI stations inputs and outputs were calculated, these numbers were added to
the AMI substation inputs and outputs from step 9. Idaho Power internal use and non-metered
energy (e.g. street lighting) were also added as outputs. Adding the non-AMI substation input
and non-AMI substation output, IPCo internal use output, and non-metered energy output
resulted in a slightly different average loss percentages as originally calculated in steps 9 and 10.
This creates new average loss percentages to apply in step 14 to the non-AMI substations. This
iterative process was repeated until the average loss percentages settled out.
After the final iteration, the following numbers were calculated:
Total Distribution Energy Input = 12,906,659 MWh
Total Distribution Energy Output = 12,282,015 MWh
Total Distribution Energy Losses = 624,644 MWh

Distribution Line Transformer Losses
The distribution line transformer energy losses are also calculated as part of the total distribution
system energy losses. As with other transformer loss calculations, both the core losses and the winding
(copper) losses are calculated. Distribution line transformer data was extracted from the GIS database
including number of transformers, kVA rating, and feeder. Typical manufacturer test data including no-
load losses and full-load losses by kVA size was obtained from IPC’s Methods and Materials group.
Distribution Line Transformers As of 12/31/2012
Table 5: Distribution Line Transformers (from GIS)
The distribution line transformer core losses of each individual transformer were calculated directly by
transformer kVA size and summed by feeder.
Equation 4

Where NLL = No-load loss in kW from transformer manufacturer test data

The winding losses or copper losses are dependent on the load through the transformer. The feeder
and kVA rating of each individual distribution line transformer on the system as of 12/31/2012 was
collected from the GIS system. Also, the manufacturer rated full-load losses (FLL) were collected from
the IPC Methods and Materials group by transformer kVA rating. Two sets of FLL data were provided;
one from 2005-2006 data and one set of test data from 2013. The 2013 vintage transformers were
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found to be less “lossy” than the 2005-2006 vintage by about 23%. Since the vast majority of existing
line transformers were installed prior to 2013, the 2005-2006 data was used in the winding losses
calculations as the best approximation of the diverse set of line transformers installed on the
distribution system. For individual transformers that were not included in the manufacturer test data
(by kVA rating), a linear approximation was used to estimate the FLL for that kVA rating size.
The winding losses for all the line transformers installed on each distribution feeder were then
calculated based on the load profile of each distribution feeder and applying a loss factor method
developed by Kip Sikes in previous losses studies. First, the total full-load losses (from manufacturer
test data) of all the individual line transformers on each feeder were summed by feeder in kW. Then,
the hourly load profile for each distribution feeder was used to calculate feeder peak load and average
load in MW for 2012. A loss factor for each feeder was then calculated based on the loss factor
equation developed by Kip Sikes:
Equation 5
Where: OpFactor = Average Feeder Load / Connected kVA on feeder
C1, C2, C3 are coefficients determined based on 2012 system loading data
For 2012, the coefficients are:
C1 = -1.0561 C2 = 1.360 C3 = 1.574

Resulting in the final loss factor equation as Equation 6

Equation 6
A loss factor is then calculated for every feeder. The total distribution line transformer winding losses
are then calculated by feeder with Equation 7.

Equation 7
Where: WindingLosses are in MWh
RatedFLLfeeder (in kW) = sum of all line transformers Full-load Losses (FLL) on feeder

The total of all the distribution line transformer energy losses in 2012 are:
Core Energy Losses = 173,366 MWh
Winding Energy Losses = 38,096 MWh
Total Energy Losses = 211,462 MWh

For feeders that do not have load data either in Pi or the MV90 system, the total core losses for all the
line transformers were calculated and included in the total transformer losses, but the winding losses
were ignored. The total connected kVA on the feeders that do not have hourly load data is only about
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0.8% of the total connected line transformer kVA (103,101 connected kVA out of 11,973,575 total
connected kVA).
A potential improvement in calculating the total distribution losses is to directly calculate the winding
losses in each individual line transformer. Prior to AMI, this was impossible, but with the AMI data and
the customer-to-transformer (C2T) tie in the GIS system, it is possible by summing the hourly customer
load by line transformer. This could replace the loss factor method used in this study in a future loss
study.
Primary/Secondary Distribution Losses Split
To be able to calculate and apply loss coefficients to both primary metered and secondary metered
customers, the distribution system level must be split into to classifications: Primary Distribution and
Secondary Distribution. Because Idaho Power does not currently keep records on the service
conductors to customers (i.e. size of conductor, length of service), we are not able to directly calculate
the secondary distribution losses separate from the primary distribution losses. One option is to build
“typical” models to simulate the primary and secondary losses and extrapolate the model results to all
500,000+ customers. This method may or may not provide additional information and is left to be
investigated in a future possible future version of the loss study.
The total distribution system energy losses were split into primary and secondary losses in this study by
using a ratio of distribution primary and secondary line miles. Two sources of the line mileage data were
considered: the company’s GIS system and the company’s property tax statements. The tax statements
were used as the final source of line mileage data because they included totals by voltage for both
primary and secondary wire miles see Table 6 and Table 7.
All Wire Mileage (TAX651)
(Includes Secondary mileage)
12/31/2012
Total 65,497.1
Table 6: Total Dist Wire Mileage
Table 7: Primary Distribution Wire Miles
Total Secondary Wire miles = 65,497.1 – 44,196.8 = 21,300.3 miles
Split of distribution system line losses based on wire miles is Table 8.
Miles %
Primary Distribution Wire Miles
Secondary Distribution Wire Miles
Table 8: Distribution Wire Miles as of 12/31/2014

1 phase 11,783.6 11,783.6

2 phase 984.6 1,969.2

3 phase 10,148.0 30,444.1

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The distribution line transformer losses are included in the Distribution Secondary system level. Then,
based on the distribution wire mileage data, the total distribution system level energy losses are in Table
9.
MWh
Primary Distribution Line Losses 278,811
Total Secondary Distribution Losses 345,833
Table 9: Distribution Level Energy Losses

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2012 Energy Loss Coefficients Diagram

Power Supply 13,859,001 328,060 Retail Transmission Sales
Utility Purchases 1,711,463 Input = 23,425,904 2,183,262 High Voltage Sales
PURPA/Cust Gen 1,388,995 Losses = 772,487 152,381 Exchange Out (excluding Bridger
Exchange In 392,313 Output = 22,653,417 and Valmy loss transactions)
Wheeling In 6,074,132 Loss Coefficient = 1.0341 5,864,395 Wheeling Out
14,125,319 To Distribution Stations
Input = 14,125,319 851,866 Direct Station Sales
Losses = 76,040 85,375 Irrigation Sales
Output = 14,049,279 92,151 Wheeling Out
Loss Coefficient = 1.0054
13,019,887 To Distribution Primary
Input = 13,585,766 2,468,641 Direct Primary Sales
PURPA 565,879 Losses = 278,811 898 Wheeling Out
Output = 13,306,955
Loss Coefficient = 1.0210
10,837,416 To Distribution Secondary
Input = 10,838,541 10,302,329 Distribution Sales
Net Met/Ore Solar 1,125 Losses = 345,833 22,818 IPCo Internal Use
Output = 10,492,708 49,885 Street Lighting / Unbilled
Loss Coefficient = 1.0330 117,676 Wheeling Out
Distribution Secondary
Idaho Power Company
2012 Energy Loss Coefficients Diagram - Including Wheeling
Values in MWh
Transmission System
Distribution Stations
Distribution Primary
Figure 1: 2012 Energy Loss Coefficient Flow Diagram
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Peak Demand Loss Coefficients Calculations

A load-flow case simulating the conditions on the system peak hour in 2012 was used in the peak losses
calculation. The peak hour for 2012 was 7/12 from 4 pm to 5 pm. The peak system demand was 3245
MW. The peak demand loss calculations are intended to calculate and represent the physical losses on
the Idaho Power Company owned facilities at peak demand.

As with the energy losses calculations, the Idaho Power system was split into four system levels:
1. Transmission: All voltage levels from 46 kV to 500 kV, includes transmission voltage tie
transformer banks and iterations with/without generator step up transformers
2. Distribution Stations: Includes distribution station transformers
3. Distribution Primary: All distribution lines and facilities at 12.47 kV, 25 kV and 34.5 kV
4. Distribution Secondary: Includes distribution line transformers
The representation of the four system levels including input and outputs, calculated losses (MW) and
individual level loss coefficients are shown in the diagram in Figure 2. The source of the data used for
the peak loss calculations are in Appendix B.
Transmission Level
Transmission level inputs and outputs were gathered for the peak hour. The transmission level IPC
power supply generation was obtained from the Pi archives and totaled 2,533.6 MW, as shown in Table
10.
2012 Peak Hour IPC Generation
Total 2,533.6 MW
Table 10: 2012 IPC Peak Hour Generation
Other transmission inputs include utility purchases, customer generation / PURPA, exchanges in, and
wheeling transactions in. The utility purchases, exchanges, and wheeling transactions were provided by
Idaho Power Operations for the peak hour. The customer generation was obtained from PI and includes
all customer owned generation that connects directly to the IPC transmission system (customer owned
substation transformer). The transmission level outputs include high voltage sales for resale, retail
transmission sales, exchanges out, wheeling transactions out, and the output to the Distribution
Substation level. The retail transmission sales data came from MV90 data and Pi data for transmission
level customers. The high voltage sales for resale, exchanges out, and wheeling transactions out came
from the system operation data for the peak hour.
The transmission level losses are calculated directly from the power flow model built to simulate the
2012 system peak load, 7/12/12 4-5 pm. The losses in the transmission lines and tie bank and generator
step-up (GSU) transformers totaled 167.1 MW and are shown by voltage in Table 11.
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Line kV Line Losses
(MW)
Transformer
Losses (MW)
Total
(MW)
Total 155.57 11.53 167.10
Table 11: Transmission Level Losses by Voltage
Distribution Stations Level
The distribution substation transformer losses are the sum of the transformer core losses and the
winding (copper) losses. The core losses (in kW) are obtained from manufacturer test data supplied by
the Substation Apparatus group.
The winding losses are calculated directly based on the demand (MW) on the transformer and the per
unit resistance of the transformer. The per unit resistance of each transformer was supplied from the
Substation Apparatus group and from Planning files. The MW demand on each distribution substation
transformer during the peak system load hour (7/12/12 4-5 pm) was found from Pi data, AMI and MV90
data. Peak Winding losses in MW were calculated for each transformer with Equation 8.
Equation 8

The distribution substation peak losses are totaled in Table 12.
Total Distribution Substation Losses 18.639 MW
Table 12: Distribution Substation Transformer Losses
The input to the distribution station level equals the output of the transmission system level. The direct
station sales are included as outputs to the distribution stations system level. The direct station sales
are customers that get their service directly from an Idaho Power owned substation with primary or
secondary distribution facilities not owned by Idaho Power.
Distribution Primary System Level
The distribution primary system level inputs include the output of the distribution stations level and
customer owned (PURPA) generation connected to the primary distribution system. The distribution
primary level outputs are the direct primary sales (primary metered customers) and the output to the
distribution secondary system level. The direct primary sales totals were found in MV90 data on the
peak system hour (7/12/12 4-5 pm).
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2012 Peak Loss Coefficients Diagram

2012 Summer Peak:7/12/2012 3245 MW
4:00 PM
Power Supply Gen 2,534 106.3 Retail Transmission Sales
Utility Purchases 501 Input = 4,822 0 High Voltage Sales
PURPA/Cust Gen 101 Losses = 167.1 4 Exchange Out (Excluding Bridger
Exchange In 70 Output = 4,655 and Valmy loss transactions)
Wheeling In 1,616 Loss Coefficient = 1.0359 1,564 Wheeling Out
2,980 To Distribution Stations
Input = 2,980 113.5 Direct Station Sales
Losses = 18.64 28.1 Irrigation Sales
Output = 2,962 14.9 Wheeling Out
Loss Coefficient = 1.0063
2,805 To Distribution Primary
Input = 2,866 340 Direct Primary Sales
PURPA 60.3 Losses = 74.7 0.1 Wheeling Out
Output = 2,791
Loss Coefficient = 1.0268
2,451 To Distribution Secondary
Input = 2,451 2,350 Distribution Sales
Losses = 60.1 3.51 IPCo Internal Use
Output = 2,391 36.9 Wheeling Out
Loss Coefficient = 1.0251
Distribution Secondary
Idaho Power Company
2012 Peak Loss Coefficients Diagram - Including Wheeling
Values in MW
Transmission System
Distribution Stations
Distribution Primary

Figure 2: 2012 Peak Loss Coefficient Flow Diagram
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Delivery Point Loss Coefficients

One of the primary goals for this loss study is to determine the total amount of energy required to be
generated to serve a customer at any given delivery point in the system. Or in other words, how much
energy must be generated from Idaho Power generators to deliver 1 kWh of energy to a customer
connected to the Idaho Power system at the distribution secondary level? Delivery point loss
coefficients are used to define the total losses to each delivery point level in the system. Delivery point
loss coefficients calculated by multiplying all the “upstream” individual level loss coefficients together.

The 2012 delivery point loss coefficients for energy and peak demand are shown in Table 13 and Table
14.

Delivery Point Energy Loss Coefficients
Table 13: 2012 Delivery Point Energy Loss Coefficients
Transmission 1.036
Distribution Stations 1.042
Distribution Primary 1.070
Distribution Secondary 1.097
Table 14: 2012 Delivery Point Peak Loss Coefficients

Page | 19

Appendix A: 2012 Energy Losses Data Sources

Transmission
Inputs
Value
(MWh) Data Source Notes
Transmission
Outputs
File: “Wheeling Form 1 Detail”
Distribution
Station
Outputs
File: “Wheeling Form 1 Detail”
Page | 20

Distribution
Primary Inputs
PURPA
Distribution
Primary
Outputs
Direct Primary
Sales
Wheeling Out File: “Wheeling Form 1 Detail”
Distribution
Secondary
Inputs
Net Met/Ore
Solar
Distribution
Secondary
Outputs
Distribution
Sales
IPCo Internal Use
Wheeling Out “Wheeling Form 1 Detail”

Page | 21

Appendix B: 2012 Peak Losses Data Sources

Transmission
Inputs
Value
(MW) Data Source Notes
File: “PeakWheeling2012_2013.xlsx”
Transmission
Outputs
Transmission
Losses 167.2
Determined from peak power
flow model simulating 2012
system peak on 7/12/12 4-5 pm
See file: "Peak PowerFlow
model.xlsx"
File: “PeakWheeling2012_2013.xlsx”
Distribution
Station Outputs
See "Dist Substation Transformer
Losses 12July2012 peak hour.xlsm"
Calculated from MW loading on
7/12/12 4 pm to 5 pm (peak
2012 hour)
Filename: "Dist Substation
Transformer losses 12July2012 peak
hour.xlsx"
Page | 22

Distribution
Station Peak
Losses 18.640
Filename: "Dist Substation
Transformer losses 12July2012 peak
hour.xlsx"
File: “PeakWheeling2012_2013.xlsx”
Distribution
Primary Inputs
Generation data from
Operations Logs, Pi, and Cogen
Payment data
See file: "Cogen_PURPA_Purchases
Detail FERC Form 1 2012.xlsx"
Distribution
Primary Outputs
Distribution
Primary Losses 74.7
Files: "Distribution Peak losses
2012.xlsx"
"Dist Line Txfrmrs Losses 2012.xlsx"
File: “PeakWheeling2012_2013.xlsx”
Distribution
Secondary
Outputs
Distribution Sales
IPCo Internal Use
Distribution
Secondary Losses 60.1
Files: "Distribution Peak losses
2012.xlsx"
"Dist Line Txfrmrs Losses 2012.xlsx"
“PeakWheeling2012_2013.xlsx”

Page | 23

Appendix C: Loss Coefficients Not Including GSU Losses

System delivery point loss coefficients not including generator step-up transformer unit (GSU) losses and
including wheeling:

Delivery Point Total Energy Loss Coefficients
(No GSU losses)

Delivery Point Total Peak Loss Coefficients
(No GSU losses)

Page | 24

Appendix D: Reconciliation with FERC Form 1

The data used in the development of the energy loss coefficients in this report is consistent with that
reported in the 2012 FERC Form 1 page 401a. Values used in Figure 1 are reconciled with values in 2012
FERC Form 1 below.

System Losses
Total System Losses 1,473,171 1,253,953 Form 1, pg 401a, line 27
Adjustment for Bridger Loss
Transactions
238,941 Bridger Loss transactions counted as
system outputs in Form 1 (part of
total in Form 1, pg 401a, line 13)
Adjustment for Valmy Loss
Transactions
3,935 Valmy Loss transactions counted as
system outputs in Form 1 (part of
total in Form 1, pg 401a, line 13)
Adjustment for Company Use -22,818 Company Use counted as losses in
Form 1 (part of total in Form 1, pg
401a, line 27)
Adjusted Total 1,473,171 1,474,011

The ratio of Figure 1 losses to Adjusted FERC Form 1 losses is 99.94%. Reasons for the small discrepancy
may include non-uniformity between the calculation method used to determine transmission losses on
the Bridger and Valmy subsystems in this study versus the calculation method used to determine the
actual loss transactions and estimation methods used where small amounts of data were missing in the
tabulation of individual level losses.